United Taconite Analysis of Best Available Retrofit Technology 

(BART) 

Table of Contents 

1. Executive Summary.............................................................................................................................iv

2. Introduction...........................................................................................................................................1

2.A BART Eligibility.........................................................................................................................3

2.B BART Determinations ................................................................................................................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..................................................................12

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ...............................................15

4.A MPCA Subject-to-BART Modeling .........................................................................................15

4.B Facility Baseline Modeling .......................................................................................................16

4.C Facility Baseline Modeling Results ..........................................................................................24

5. BART Analysis for Indurating Furnaces ............................................................................................26

5.A Indurating Furnace....................................................................................................................26

5.A.i Sulfur Dioxide Controls............................................................................................... 27

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 27

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 27

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control 

Technologies................................................................................................ 33

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 33

5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 37

5.A.ii Nitrogen Oxide Controls.............................................................................................. 42

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 42

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 42

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

Technologies................................................................................................ 54

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 54

5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 57

6. Visibility Impacts................................................................................................................................61

6.A Post-Control Modeling Scenarios .............................................................................................61

6.B Post-Control Modeling Results.................................................................................................61

7. Select BART.......................................................................................................................................68

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List of Tables 

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis.... 13

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data . 17

Table 4-2 Baseline Visibility Modeling Results........................................................................... 25

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

Technical Feasibility.................................................................................................... 33

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness ......................................... 33

Table 5-3 Indurating Furnace SO2 Control Cost Summary........................................................... 34

Table 5-4 SO2 Control Technology Impacts Assessment ............................................................. 36

Table 5-5 Post-Control Modeling Scenarios ................................................................................ 38

Table 5-6 Post-Control SO2 Modeling Scenarios - Modeling Input Data ..................................... 39

Table 5-8 Post-Control SO2 Modeling Scenarios - Visibility Modeling Results .......................... 41

Table 5-9 Post-Control SO2 Modeling Scenarios - Visibility Improvements................................ 41

Table 5-10 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility.................................................................................................... 54

Table 5-11 Indurating Furnace NOx Control Technology Effectiveness......................................... 54

Table 5-12 NOx Control Cost Summary......................................................................................... 55

Table 5-13 NOx Control Technology Impacts Assessment............................................................. 56

Table 5-14 Post-Control Modeling Scenarios ............................................................................... 58

Table 5-15 Post-Control NOX Modeling Scenarios – Emissions Data............................................ 58

Table 5-16 Post-Control NOX Modeling Scenarios - Visibility Modeling Input Data .................... 59

Table 5-17 Post-Control NOX Modeling Scenarios - Visibility Modeling Results ......................... 60

Table 5-18 Post-Control NOX Modeling Scenarios - Visibility Improvements .............................. 60

Table 6-1 Post-Control Modeling Scenarios ................................................................................ 63

Table 6-2 Post-Control NOX Modeling Scenarios - Modeling Input Data .................................... 64

Table 6-3 Post-Control Modeling Scenarios - Visibility Modeling Results.................................. 65

Table 6-4 Post-Control Modeling Scenarios - Visibility Modeling Results.................................. 66

Table 6-5 Post-Control Modeling Results – Dollars per Deciview Improvement......................... 67

List of Figures 

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

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List of Appendices 

Appendix A Control Cost Analysis Spreadsheets 

Appendix B Changes to MPCA BART Modeling Protocol 

Appendix C Visibility Impacts Modeling Report 

Appendix D Applicable and Available Retrofit Technologies 

Appendix E Clean Air Interstate Rule (CAIR), Cost-Effective Air Pollution Controls 

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1. Executive Summary 

United Taconite is located in northern Minnesota, with mining facilities near Eveleth, Minnesota. 

United Taconite’s processing facilities are located near Forbes, Minnesota. This report describes the 

background and methods for the selection of the Best Available Retrofit Technology (BART) as 

proposed by United Taconite for its taconite processing plant located near Forbes, MN. 

MPCA identified approximately 70 pieces of equipment at United Taconite that were installed within 

the time window (1962-1977) that makes them subject to BART. The equipment includes two gratekiln indurating furnace lines. Line 1 is permitted for natural gas and fuel oil, but Line 2 also uses 

coal and petroleum coke. Other equipment identified includes crushers, pellet coolers, combustion 

units, fugitive sources, and material handling and/or storage units for ore, product, and additives. 

Preliminary visibility modeling conducted by the Minnesota Pollution Control Agency (MPCA) 

found that air emissions from United Taconite’s facility “cause or contribute to visibility 

impairment” in a federally protected Class I area, therefore making the facility subject to BART. 

Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to 

propose BART for the subject units. The existing pollution control equipment includes a wet 

scrubber designed to control particulate matter (PM); however some collateral control of sulfur 

dioxide (SO2) is also achieved. A dispersion modeling sequence of CALMET, CALPUFF, and 

CALPOST was used to assess the visibility impacts of the baseline emissions and after the 

application of candidate BART controls. Visibility impacts were evaluated in the selection of BART. 

Other criteria that the BART rules require to be considered include the availability of technology, 

costs of compliance, energy and environmental impacts of compliance, existing pollution control 

technology in use at the source, and the remaining useful life of the source. 

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

• SO2 emissions will be controlled by the existing scrubbers. 

• NOx emissions will be controlled by the implementation of a heat recuperation project on 

Line 1. 

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• PM emissions will be controlled as prescribed by the taconite maximum achievable control 

technology (MACT) standard1

. 

CALPUFF model is conservative, resulting in an over prediction of impacts. This modeled high 

impact from the BART eligible sources is 4.7 dV, which is slightly above perceptible levels of one to 

two dV. Real impacts to the Class I areas from United Taconite are expected to be even less than 

these modeled impacts. 

The proposed BART controls will reduce the facility’s visibility impact by 0.7 dV, an improvement 

of 15%, on the worst visibility days. This represents a significant contribution to the default glide 

path of reducing impacts by 1-2% per year. 

 

1

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

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2. Introduction 

United Taconite is located in northern Minnesota, with mining facilities near Eveleth, Minnesota. 

United Taconite’s processing facilities are located near Forbes, Minnesota. This report describes the 

background and methods for the selection of the Best Available Retrofit Technology (BART) as 

proposed by United Taconite for its taconite processing plant located near Forbes, MN. 

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

published regulations to address visibility impairment in our nation’s largest national parks and 

wilderness (“Class I”) areas in July 1999. This rule is commonly known as the “Regional Haze 

Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005)] and is found in 40 

CFR part 51, in 51.300 through 51.309. 

Within its boundary, Minnesota has two Class I areas – the Boundary Waters Canoe Area Wilderness 

and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility 

impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney 

Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State 

Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in 

these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward 

reaching the 2018 visibility goal for each of the state’s Class I areas. 

One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put 

in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART) 

analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to 

determine if a technology should be installed to improve visibility in Class I areas. The chosen 

technology is referred to as the BART controls, or simply BART. The SIP must require BART on all 

BART-eligible sources and mandate a plan to achieve natural background visibility by 2064. 

Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When 

reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi 

Nugget (Nugget), which are illustrated in the figure, are not currently in operation. The SIP must 

also include milestones for establishing reasonable progress towards the visibility improvement goals 

and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must make 

the requirements for BART sources enforceable through rules, administrative orders or Title V 

permit amendments. 

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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 U.S. EPA’s definition, reasonable progress means that there is no degradation of the 20 bestvisibility days, and the 20 worst-visibility days must have no more visibility impairment than the 20 

worst days under natural conditions by 2064.2

 Assuming a uniform rate of progress, the default glide 

path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state 

must submit progress reports every five years to establish their advancement toward the Class I area 

natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a 

slower rate of improvement may be proposed on the basis of cost or time required for compliance and 

non-air quality impacts. 

Note that the improvements required under the Regional Haze regulations are different from the 

BART requirements. Facilities subject to BART are not required to make all of the reasonable 

 

2

 70 FR No. 178 pp. 39104 to 39172. 

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progress towards improving regional haze in Class I areas. Rather, BART is but one of many 

measures which states may rely upon in making “reasonable progress” towards regional haze 

improvement goals. 

2.A BART Eligibility 

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

must meet the following three conditions: 

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

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

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

plants, sulfur recovery plants, etc.); 

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

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

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

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

visibility analyses. Installation of additional controls may be required to further reduce emissions of 

visibility impairing pollutants such as PM, 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 

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

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

technology, existing controls at a facility, the cost of compliance, the remaining useful life of a 

source, the energy and non-air quality environmental impacts of the technology, and the visibility 

impacts.3

 The five steps of a BART analysis are: 

Step 1 - Identify all Available Retrofit Control Technologies 

The first step in the analysis is to identify all retrofit control technologies which are 

generally available for each applicable emission unit. Available retrofit control 

technologies are defined by U.S. EPA in Appendix Y to Part 51 (Guidelines for BART 

Determinations under the Regional Haze Rule) as follows: 

Available retrofit technologies are those air pollution control technologies 

with a practical potential for application to the emissions unit and the 

regulated pollutant under evaluation. Air pollution control technologies can 

include a wide variety of available methods, systems, and techniques for 

control of the affected pollutant. Technologies required as BACT or LAER 

are available for BART purposes and must be included as control 

alternatives. The control alternatives can include not only existing controls 

for the source category in question, but also take into account technology 

transfer of controls that have been applied to similar source categories or gas 

streams. Technologies which have not yet been applied to (or permitted for) 

full scale operations need not be considered as available; we do not expect 

the source owner to purchase or construct a process or control device that 

has not been demonstrated in practice.4

Step 2 - Eliminate Technically Infeasible Options 

In the second step, the source-specific technical feasibility of each control option 

identified in step one is evaluated by answering three specific questions: 

a. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 

 

3

 40 CFR 51 Appendix Y 

4

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

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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.5

” 

However, the U.S. EPA further states that they “do not expect a source owner to 

conduct extended trials to learn how to apply a technology on a totally new and 

dissimilar source type.6

” 

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.7

” 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.8

” 

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 

technology9

.” 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 analysis10. 

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. 

 

5

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

6

 IBID 

7

 IBID 

8

 IBID 

9

 IBID 

10 IBID 

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EPA does not consider as “sufficient justification that a control option or emission 

limit is technically infeasible”. In general, the decisions on technical feasibility 

should be based on a combination of the evaluation of the chemical and engineering 

analysis and the information from vendor guarantees11. 

Step 3 - Evaluate Control Effectiveness 

In step three, the remaining controls are ranked based on the control efficiency at the 

expected emission rate (post-control) 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 protocol12, 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 dV value 

and the number of days the facility contributes more than a 0.5 deciview (dV) of 

 

11 IBID 12 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to 

BART in the State of Minnesota. 

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visibility impairment at each of the Class I areas, are used to establish the degree of 

improvement that can be reasonably attributed to each technology. 

The final step in the BART analysis is to select the “best” alternative using the results of steps 1 

through 5. In addition, the U.S. EPA and MPCA guidance states that the “affordability” of the 

controls should be considered, and specifically states: 

1. Even if the control technology is cost effective, there may be cases where the installation 

of controls would affect the viability of plant operations. 

2. There may be unusual circumstances that justify taking into consideration the conditions 

of the plant and the economic effects requiring the use of a given control technology. 

These effects would include effects on product prices, the market share, and profitability 

of the source. Where there are such unusual circumstances that are judged to affect 

plant operations, you may take into consideration the conditions of the plant and the 

economic effects of requiring the use of a control technology. Where these effects are 

judged to have severe impacts on plant operations you may consider them in the selection 

process, but you may wish to provide an economic analysis that demonstrates, in 

sufficient detail for public review, the specific economic effects, parameters, and 

reasoning. (We recognize that this review process must preserve the confidentiality of 

sensitive business information). Any analysis may also consider whether competing 

plants in the same industry have been required to install BART controls if this 

information is available.13

To complete the BART process, the analysis must “establish enforceable emission limits that reflect 

the BART requirements and requires compliance within a reasonable period of time14.” 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 basis15.” which could include the incorporation of 

other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR 

64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If 

technological or economic limitations make measurement methodology for an emission unit 

 

13 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 14 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 15 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 standards16.” 

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

the Minnesota SIP. 

 

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

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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 analyses17. The streamlined approach will allow both states and the 

facilities to focus their resources on the main contributors to visibility impairment. This section of 

the report follows the MPCA-approved streamlined BART analysis for taconite facilities and 

presents the results of the streamlined approach in Table 3-1. 

3.A Indurating Furnaces 

The indurating furnaces are sources 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 

furnaces are subject to the taconite MACT standard18 for the PM emissions. MPCA’s guidance for 

conducting a BART review states that “MPCA will rely on MACT standards to represent BART 

level of control for those visibility impairing pollutants addressed by the MACT standard unless 

there are new technologies subsequent to the MACT standard, which would lead to cost-effective 

increases in the level of control.” [Attachment 2, March 2006, page 2]. Since the MACT standard 

was established very recently and becomes effective in 2006, the technology analysis is up-to-date. 

As a result, BART will be presumed to be equivalent to MACT for PM. 

A full BART analysis will be conducted for NOx and SO2 where applicable. 

3.B PM-Only Taconite MACT Emission Units 

In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from 

Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations. 

These sources operate near ambient temperature, only emit PM, and do not emit 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 [FR, December 18, 2002, page 77570]. Therefore, the emissions from the pellet coolers 

are considered to have a negligible impact on visibility impairment, and no control requirements 

under the MACT standard is consistent with the intention of the BART analysis. 

 

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

18 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

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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). These sources operate at ambient temperature, only 

emit PM, and do not emit NOx or SO2. Taconite MACT fugitive sources include the following: 

• Stockpiles (includes, but is not limited to, stockpiles of uncrushed ore, crushed ore, or 

finished pellets), 

• Material Transfer Points, 

• Plant Roadways, 

• Tailings basins, 

• Pellet loading areas, and 

• Yard areas. 

Control of emissions from these fugitive PM sources is maintained through a fugitive control plan, as 

required by the MACT standard and as required by the facility’s Title V air permit. The fugitive 

controls consist of primary controls, and contingent measures to prevent or mitigate fugitive PM 

emissions. The controls and measures are site specific and are appropriate to seasonal and weather 

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

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

be presumed to be equivalent to MACT according to MPCA guidance. 

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

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

A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard. 

They include units such as: 

• Additive storage and handling 

• Concentrate storage and handling 

Considering all PM emissions which are subject to the BART standard, the PM emissions from the 

above units typically represent less than 2.5% of PM emissions from the facility, which are subject to 

BART. Relative to NOx and SO2, PM is not a major visibility impairing pollutant. 

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The point source emission units are typically controlled by baghouses, which achieve high levels of 

control for PM. Since these units already have the best control equipment for PM emissions, and 

since the PM emissions from these sources are small relative to the total PM emissions that are 

subject to the BART standard, additional control of these sources can be presumed to have minimal 

impact on visibility improvement in Class I areas. For the controlled sources, existing controls will 

be considered BART consistent with direction from MPCA in the May 18, 2006 meeting. No further 

analysis will be required to establish BART for these sources. 

The fugitive sources are controlled by measures described in the fugitive control plan as required by 

the facility Title V operating permit. Fugitive control plans are accepted as MACT and BACT for 

fugitive sources, including the recent taconite MACT standard and a BACT determination made in 

2006 for the mining industry. For the fugitive sources, the existing fugitive dust control plans will be 

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

3.E Other Combustion Units 

United Taconite has other combustion units that are subject to BART. The combustion units are 

sources of three visibility impairing pollutants: NOx, SO2, and PM. 

The remaining combustion sources consist of four small boilers (each less than 20 MMBtu/hr) and 10 

heaters to warm work areas during cold weather. It is important to note that the emissions from the 

indurating furnaces represent the vast majority of emissions of all visibility impairing pollutants, 

with the other combustion units typically contributing less than 1% of the total emissions of each 

pollutant from sources that are subject to BART. The emissions from all the remaining sources are 

small relative to the total emissions that are subject to the BART standard. Additional control of 

these sources can be presumed to have minimal impact on visibility improvement in Class I areas. 

As directed by MPCA in the May 18, 2006 meeting, United Taconite conducted an analysis for the 

remaining combustion sources to demonstrate that the impact on visibility is negligible (less than or 

equal to 0.05 deciviews19). The procedure for the analysis is detailed in section 3.F of this document. 

The results of that modeling demonstrated that the visibility impact of those sources is equal to 0.05 

deciviews. Therefore, the sources are considered to not cause or contribute to visibility impairment 

in Class I areas. Therefore, the existing operations will be considered BART. No further analysis 

will be required to establish BART for these sources. 

 

19 The threshold of perception of the human eye is 1-2 dV. 

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3.F Visibility Impact Modeling for Negligible Impacts 

As described in section 3.E of this document, this facility contains several sources that are assumed 

to have a negligible impact on visibility in Class I areas. In order to confirm this assumption, a 

modeling analysis was conducted to determine the impact of the emissions from these sources on 

visibility in Class I areas. The analysis consisted of the following: 

(1) Conduct air dispersion modeling for uncontrolled BART-eligible emission units and 

fugitive sources for the facility, as described in section 3.E above. The modeling was 

conducted based on the guidance in the BART Modeling Guidance as prepared by 

MPCA. One modeling analysis was conducted. The modeling was conducted on a 

focused grid (as previously agreed to with MPCA) which is based on the facility 

impacts as presented by MPCA in “Results of Best Available Retrofit Technology 

(BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota” 

(March 2006). 

(2) Count the days with a 98th percentile (21 over 3-yrs, 7 each year) change in visibility 

greater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5 

deciviews) at the modeled receptors with in the boundaries of each Class I area 

assessed over the 3-year period 2002-2004. 

(3) If the modeled emission sources result in a 98th percentile change in visibility less 

than or equal to 0.05 deciviews, the point and fugitive sources will be considered to 

not cause or contribute to visibility impairment in Class I areas. Therefore, the 

existing operations will be considered BART. No further analysis will be required to 

establish BART for these sources. 

(4) If the modeled emissions result in a 98th percentile change in visibility greater than 

0.05 deciviews, a full BART analysis will be conducted on the emission sources. 

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

Emission 

Unit # Emission Unit Description 

VisibilityImpairing 

Pollutant1

Existing 

Limit1 

gr/dscf 

Maximum Daily 

lbs/day2

3.A Indurating Furnaces 

40 Line 1 Pellet Induration PM 0.01 426.4 

42 SV 048 Line 2 Pellet Induration PM 0.01 1932 

42 SV 049 Line 2 Pellet Induration PM 0.01 1248 

3.B PM-Only Taconite MACT Emission Units 

1 Crude Ore Unloading Pan Feeders PM 0.008 43.2 

2 SV008 Crude Ore Unloading PM 0.008 29.6 

2 SV009 Crude Ore Unloading PM 0.008 33.6 

4 Coarse Ore Surge Pan Feeders PM 0.008 18.1 

5 Third Stage Crusher 1 PM 0.008 47.2 

6 Third Stage Crusher 2 PM 0.008 0.0 

7 Third Stage Crusher 3 PM 0.008 0.0 

8 Third Stage Crusher 4 PM 0.008 0.0 

9 Third Stage Crusher 5 PM 0.008 0.0 

10 Third Stage Bins Conveyor PM 0.008 0.0 

11 Fourth Stage Crusher 1 PM 0.008 180.0 

12 Fourth Stage Crusher 2 PM 0.008 20.96 

13 Fourth Stage Crusher 3 PM 0.008 264 

14 Fourth Stage Crusher 4 PM 0.008 63.2 

15 Fourth Stage Crusher 5 PM 0.008 0 

16 Fourth Stage Crusher 6 PM 0.008 28.8 

17 Fourth Stage Crusher 7 PM 0.008 0 

18 Fourth Stage Crusher 8 PM 0.008 0 

19 Fourth Stage Trip/Bin/Convey PM 0.008 0 

20 Transfer House North PM 0.008 18.64 

22 Transfer House South PM 0.008 18.48 

23 No. 1 Rod Mill Feed PM 0.008 9.44 

24 No. 2 Rod Mill Feed PM 0.008 

25 No. 3 Rod Mill Feed PM 0.008 26.4 

26 No. 4 Rod Mill Feed PM 0.008 0 

27 No. 5 Rod Mill Feed PM 0.008 0 

33 Line 2 Grate Feed PM 0.008 42.4 

34 Line 2 Grate Discharge PM 0.008 128 

35 Line 2 Kiln Cooler Discharge PM 0.008 22.96 

35 Line 2 Kiln Cooler Discharge PM 0.008 68.8 

35 Line 2 Cooler Discharge Vibrating feeders PM 0.008 7.84 

36 Line 2 Pellet Cooler Exhaust PM 0.008 116.8 

37 Line 1 Grate Feed PM 0.008 0 

38 Line 1 Grate Discharge PM 0.008 0 

39 SV 116 Line 1 Kiln Cooler Discharge PM 0.008 23.76 

39 SV 045 Line 1 Kiln Cooler Discharge PM 0.008 24.64 

41 Line 1 Pellet Cooler Exhaust PM 0.008 65.76 

3.C Fugitive PM MACT Sources 

FS 001 Unpaved Roads - coarse tailings to tailings 

basin PM Fug Control Plan 

FS 002 Wind Erosion - Tailings Basin (Active Area) PM Fug Control Plan 

FS 005 Coarse Ore Surge Dump PM Fug Control Plan 

FS 012 Unpaved Roads - light truck traffic around 

plant PM Fug Control Plan 

FS 029 Fine Ore Surge (9F to 10 transfer) PM Fug Control Plan 

FS 030 Fine Ore Surge (10 to pile transfer) PM Fug Control Plan 

FS 031 Line 1 Pellet Transfer (21 to 21B) PM Fug Control Plan 

FS 033 Pellet Loadout Railcar loading PM Fug Control Plan 

FS 051 Line 1 Pellet transfer (21 to 22N/S) PM Fug Control Plan 

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

28 Limestone/Soda Ash Storage Bins PM 0.3 

29 Additive Unloading PM 0.3 

30 Line 2 Additive Storage Bins PM 0.3 

31 Line 2 Additive Addition PM 0.3 

FS 004 Wind Erosion - Concentrate Stockpile PM Fug Control Plan 

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13
Emission 

Unit # Emission Unit Description 

VisibilityImpairing 

Pollutant1

Existing 

Limit1 

gr/dscf 

Maximum Daily 

lbs/day2

3.E Other Combustion Units 

51 Fairlane Truck Shop Boiler PM 0.63

52 Fairlane New Shop Boiler PM 0.63

53 Fuel Handling Boiler #1 PM 0.63

54 Fuel Handling Boiler #2 PM 0.63

99 10 Makeup Heaters (F. Crusher Bldg) PM NA 1

PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping 

provisions, as presented in the MACT regulation, effective 10/30/2006. 

2

Based on baseline flow rates. 

3

0.6 lbs/million Btu heat input 

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14
4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance20, one of the factors to consider when determining 

BART for an individual source is the degree of visibility improvement resulting from the retrofit 

technology. The visibility impacts for this facility were estimated using CALPUFF, an U.S. EPA 

approved model recommended for comparing the visibility improvements of different retrofit control 

alternatives. However it is important to note that CALPUFF is a conservative model that over 

estimates real impacts. Therefore, although the CALPUFF baseline modeling results are important to 

comparing control alternatives on a relative basis they are do not accurately predict real impacts. 

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

consideration for the background atmospheric ammonia, ozone and meteorological data. 

Additionally, the interactions between the visibility impairing pollutants 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 estimate 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 emissions21. 

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 

 

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

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

Subject-to-BART in the State of Minnesota. Page 8. 

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16

utilization. The results of the modeling were presented in the document titled “Results of Best 

Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the 

State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that 

this facility is subject-to-BART. 

4.B Facility Baseline Modeling 

Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated. 

On behalf of United Taconite and the other Minnesota taconite facilities, Barr Engineering proposed 

changes to the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are 

presented in Appendix B. 

In addition, the maximum 24-hour emission rates were re-evaluated internally within United Taconite 

to verify 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 

changes at the facility that occurred after the submittal of the information requested by MPCA and to 

reflect combustion of permitted fuels. 

An energy efficiency project was implemented on Line 1 to recoup waste heat in 2005 thereby 

reducing natural gas fuel use on Line 1. The emissions of NOx from Line 1 were adjusted to 

represent the new baseline conditions. Following implementation of this change, stack testing was 

performed and the results indicate that NOx emissions were reduced by 46%.

The original baseline emissions were modeled for comparison to MPCA results. This data is 

summarized in Table 4-1. The full modeling analysis is presented in Appendix C. 
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 

Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

3.A Indurating Furnaces

40 

Line 1 

Pellet 

Induratio

n 

4776 Fuel oil 15,632 Nat gas 426.4 46 532024.98 5244399.88 140 1,3

42 

Line 2 

Pellet 

Induratio

n 

8292 Solid fuel 22,872 Nat Gas 1932 48 531995.03 5244364.98 153 1,3

42 

Line 2 

Pellet 

Induratio

n 

6880 Solid Fuel 25632 Nat Gas 1248 49 531983.41 5244432.55 153 1,3

3.B PM-Only Taconite MACT Emission Units 

1 

Crude 

Ore 

Unloadin

g Pan 

Feeders 

43.2 7 531,800 5,244,349 40 1,3

29.6 8 531,807 5,244,386 14 1,3

2 

Crude 

Ore 

Unloadin

g 

33.6 9 531,794 5,244,371 14 1,3

4 

Coarse 

Ore 

Surge 

Pan 

Feeders 

18.1 10 531,906 5,244,763 50 1,3

5 

Third 

Stage 

Crusher 

1 

47.2 11 532,024 5,244,668 191 1,3

6 

Third 

Stage 

Crusher 

2 

0.0 12 532,029 5,244,663 191 1,3

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17
Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

7 

Third 

Stage 

Crusher 

3 

0.0 13 532,034 5,244,659 196 1,3

8 

Third 

Stage 

Crusher 

4 

0.0 14 532,039 5,244,655 196 1,3

9 

Third 

Stage 

Crusher 

5 

0.0 15 532,049 5,244,646 202 1,3

10 

Third 

Stage 

Bins 

Conveyo

r 

0.0 16 532,053 5,244,639 196 1,3

11 

Fourth 

Stage 

Crusher 

1 

180.0 17 532,001 5,244,618 146 1,3

12 

Fourth 

Stage 

Crusher 

2 

20.96 18 532,013 5,244,608 146 1,3

13 

Fourth 

Stage 

Crusher 

3 

264 19 532,021 5,244,601 146 1,3

14 

Fourth 

Stage 

Crusher 

4 

63.2 20 532,027 5,244,596 146 1,3

15 

Fourth 

Stage 

Crusher 

5 

0 21 532,033 5,244,591 146 1,3

16 

Fourth 

Stage 

Crusher 

6 

28.8 22 532,037 5,244,588 150 1,3

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Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

17 

Fourth 

Stage 

Crusher 

7 

0 23 532,044 5,244,582 150 1,3

18 

Fourth 

Stage 

Crusher 

8 

0 24 532,050 5,244,577 150 1,3

19 

Fourth 

Stage 

Trip/Bin/

Convey 

0 25 532,057 5,244,571 150 1,3

20 

Transfer 

House 

North 

18.64 26 532,149 5,244,545 94 1,3

22 

Transfer 

House 

South 

18.48 28 532,124 5,244,507 97 1,3

23 

No. 1 

Rod Mill 

Feed 

9.44 29 532,205 5,244,359 111 1,3

24 

No. 2 

Rod Mill 

Feed 

0 30 532,147 5,244,407 

25 

No. 3 

Rod Mill 

Feed 

26.4 31 532,234 5,244,334 122 1,3

26 

No. 4 

Rod Mill 

Feed 

0 32 532,263 5,244,310 122 1,3

27 

No. 5 

Rod Mill 

Feed 

0 33 532,291 5,244,287 122 1,3

33 

Line 2 

Grate 

Feed 

42.4 39 532,014 5,244,408 126 1,3

34 

Line 2 

Grate 

Discharg

e 

128 40 531,978 5,244,368 117 1,3

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19
Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

35 

Line 2 

Kiln 

Cooler 

Discharg

e 

22.96 41 531,969 5,244,333 104 1,3

35 

Line 2 

Kiln 

Cooler 

Discharg

e 

68.8 70 531,933 5,244,338 124 1,3

35 

Line 2 

Cooler 

Discharg

e 

Vibrating 

feeders 

7.84 50 531,960 5,244,324 103 1,3

36 

Line 2 

Pellet 

Cooler 

Exhaust 

116.8 42 531,958 5,244,351 136 1,3

37 

Line 1 

Grate 

Feed 

0 43 532,043 5,244,376 92 1,3

38 

Line 1 

Grate 

Discharg

e 

0 44 532.009 5,244,347 96 1,3

23.76 116 531,992 5,244,311 115 13

39 

Line 1 

Kiln 

Cooler 

Discharg

e 

24.64 45 532,971 5,244,344 100 1,3

41 

Line 1 

Pellet 

Cooler 

Exhaust 

65.76 47 531,993 5,244,323 115 1,3

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20
Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

3.C Fugitive PM MACT Sources 

1 

Unpaved 

Roads - 

coarse 

tailings 

to 

tailings 

basin 

0.0 NA NA 

2 

Wind 

Erosion - 

Tailings 

Basin 

(Active 

Area) 

0.0 NA NA 

5 

Coarse 

Ore 

Surge Dump 

0.0 NA NA 

12 

Unpaved 

Roads - 

light 

truck 

traffic 

around 

plant 

0.0 NA NA 

29 

Fine Ore 

Surge 

(9F to 10 

transfer) 

0.0 NA NA 

30 

Fine Ore 

Surge 

(10 to 

pile 

transfer) 

0.0 NA NA 

31 

Line 1 

Pellet 

Transfer 

(21 to 

21B) 

0.0 NA NA 

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21
Emissio

n 

Unit ID 

Emission 

Unit 

Descripti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

33 

Pellet 

Loadout 

Railcar 

Loading 

0.0 NA NA 

51 

Line 1 

Pellet 

Transfer 

0.0 NA NA 

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

28 

Limeston

e/Soda 

Ash 

Storage 

Bins 

0.0 34 532,055 5,244,414 135 1,3

29 

Additive 

Unloadin

g 

0.0 35 532,072 5,244,398 60 1,3

30 

Line 2 

Additive 

Storage 

Bins 

0.0 36 532,015 5,244,447 157 1,3

31 

Line 2 

Additive 

Addition 

0.0 37 532,046 5,244,425 166 1,3

4 

Wind 

Erosion - 

Concentr

ate 

Stockpile 

0.0 NA NA 

3.E Other Combustion Units 

51 

Fairlane 

Truck 

Shop 

Boiler 

58.1 0.0 107 532,039 5,244,705 49 1,3

52 

Fairlane 

New 

Shop 

Boiler 

36.7 0.0 108 532,280 5,244,708 31 1,3

53 

Fuel 

Handling Boiler #1 

36.7 0.0 109 531,798 5,244,107 24 1,3

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C:\Documents and

Emissio

n 

Unit ID 

Emission 

Descr

 Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc

23

Unit 

ipti

on 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day

) 

Basis 

for 

SO2 

24-hr 

Actual 

Emissi

ons 

NOx 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

NOx 

24-hr 

Actual 

Emissi

ons 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissi

ons 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissi

ons 

Stac

k 

No. 

Easting Northing 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

Gro

(

54 

Fuel 

Handling Boiler #2 

36.7 0.0 110 531,802 5,244,101 24 1,3

99 

10 

Makeup 

Heaters 

(F. 

Crusher 

Bldg) 

176.4 0.0 99
4.C Facility Baseline Modeling Results 

The Minnesota BART modeling protocol22 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. The CALPOST output files provide the following 

two methods to assess the expected post-control 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 BART23, 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, 

this 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-control modeling analysis in section 6 of this document. Two 

baselines are shown. The first baseline represents burning natural gas on both Lines 1 and 2 and 

emission levels prior to installation of the heat recoup project on Line 1. The new baseline represents 

the emission levels after installation of the heat recoup project. 

The full modeling analysis is presented in Appendix C. 

 

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

Subject-to-BART in the State of Minnesota. Page 8. 23 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 

2002 2003 2004 

2002 – 2004 

Combined 

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 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

BWCA 3.5 121 4.0 116 4.7 103 4.0 340 

BWCA 3.0 114 3.4 115 4.0 97 3.4 326 

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5. BART Analysis for Indurating Furnaces 

As presented in section 3 and Table 3-1, the only sources at United Taconite that require a full BART 

analysis are the indurating furnaces. The BART analysis is required for SO2 and NOx. 

5.A Indurating Furnace 

The primary function of taconite indurating furnaces is to convert magnetic iron concentrate to a 

more highly oxidized iron in the form of a pellet that is sold to metallic iron and steel production 

facilities. “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The 

induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. The process 

requires large amounts of air for pellet oxidation and cooling. Process temperature control in all 

parts of the furnace is critical to minimize product breakage in the initial process stages, allow 

required oxidation reactions to occur, and adequately cool the product prior to subsequent handling 

steps. Directed air flow, heat recovery and fuel combustion are critical to controlling temperature 

and product quality in all parts of the furnace. 

United Taconite has grate/kiln furnaces, in which the pellets are dried on a grate and then transferred 

to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation section of the 

induration furnace is designed to operate at 2,400 oF and higher. This temperature is required to meet 

taconite pellet product specifications. Direct fired fuel combustion in the induration furnace is carried 

out at 300% to 400% excess air to provide sufficient oxygen for pellet oxidation. 

Air is used for combustion, pellet cooling, and as a source of oxygen for pellet oxidation. Due to the 

high-energy demands of the induration process, induration furnaces have been designed to recover as 

much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and preheat 

zones are heated with the hot gases generated in the pellet hardening/oxidation section and the pellet 

cooler sections. Each of these sections is designed to maximize heat recovery within process 

constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s energy is 

directed to the process instead of heating ambient air to combustion temperatures. 

United Taconite has two grate/kiln furnaces, Line 1 and Line 2. Line 1 is permitted to burn natural 

gas and fuel oil. Line 2 is permitted to burn natural gas, fuel oil, coal, and petroleum coke. Both 

lines are controlled by wet scrubbers. Line 1 also uses caustic reagent. The wet scrubbers are 

designed to remove PM and would be considered a high efficiency PM wet scrubber. Since collateral 

SO2 reductions occur within the existing wet scrubbers, they are considered low efficiency SO2

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scrubbers and will be evaluated as such within this BART analysis. NOx is controlled through 

furnace design. 

5.A.i Sulfur Dioxide Controls 

One source of SO2 emissions in taconite production is trace amounts of sulfur in the iron concentrate 

and binding agents present in the green balls. Sulfur is also present in distillate fuel oil, that is a 

permitted fuel for both lines, and in coal and petroleum coke, that are permitted fuels on Line 2. 

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

See Appendix D for a comprehensive list of all potential retrofit control technologies that were 

evaluated. Many emerging technologies have been identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the 

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

information became apparent of the limited scope and scale of some of the technology applications. 

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

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for SO2 emission reduction. Within 

Step 2, the technical feasibility of the control option is discussed and determined. The following 

section describes retrofit SO2 control technologies that were identified as available and applicable in 

the original submittal and discusses aspects of those technologies that determine whether or not the 

technology is technically feasible for indurating furnaces. 

Wet Walled Electrostatic Precipitator (WWESP) 

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

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

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

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

rapping and fall into hoppers for collection and removal. 

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. 

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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. United Taconite currently employs a 

wet scrubber designed for removal of particulate matter, and it performs as a low efficiency SO2 wet 

scrubber. The addition of a WWESP would act as a polishing scrubber 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 used as scrubbing 

agents. Most wet scrubbers recirculate the scrubbing solution, which minimizes the wastewater 

discharge flow. However, higher concentrations of solids exist within the recirculated wastewater. 

For a wet scrubber to be considered a high efficiency 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 

could be as low as 30% control efficiency. A low efficiency SO2 scrubber 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: 

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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 minimal equipment is needed as compared to lime or 

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

equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating 

the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land 

filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air 

injection blower is needed to supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers on coal-fired utility boilers with excess 

oxygen of 2-3% is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency 

scrubbers. The highest control efficiencies can be achieved when SO2 concentrations are the highest. 

Unlike coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper 

oxidation of the pellet. The excess air dilutes the SO2 concentration as well as creates higher flow 

rates to control. Additionally, the varying sulfur concentration within the pellet causes fluctuations of 

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

of the wet scrubber. 

As stated in the beginning of this section, wet scrubbers are currently in place on the furnace 

exhausts and are believed to remove 15 to 30% of the SO2 in the exhaust. Taking into consideration 

the removal of SO2 from the low-efficiency primary PM scrubber as well as a polishing SO2 wet 

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

United Taconite has evaluated modifying the exiting scrubber on Line 2 to determine if 

improvements to SO2 removal could be accomplished. The concentration of caustic in the scrubbing 

water was increased to a pH of 8 for several hours and stack sampling was performed to evaluate the 

change in SO2 emissions. The SO2 emissions were not reduced. The materials of construction of the 

existing scrubbers would not withstand a higher pH than 7 or 8. An engineering study would be 

required to evaluate more extensive redesign of the existing scrubbers, such as modifying the spray, 

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increasing the contact time, recirculating the scrubber water, and retrofitting to allow use of a much 

higher pH. Quantifying the likelihood and magnitude of potential improvements to SO2 control 

would not be possible without a study, so this option could not be selected as BART. 

Based on the information contained within this report, a polishing 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. 

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. 

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Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically, reduced fuel usage translates into reduced 

pollution emissions. United Taconite recently installed heat recuperation on Line 1 and performed 

stack testing to quantify the emission reductions. Testing completed in May of 2005 revealed that 

NOx emissions were reduced by 46%. Differences in SO2 emissions are attributed to differences in 

ore composition. Therefore, this alternative will not be carried forward in this analysis for SO2, but 

will be carried forward for NOx. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has moved companies 

to evaluate alternate fuel sources. These fuel sources come in all physical forms – solid, liquid and 

gas. To achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels 

with lower sulfur content. Switching fuels trades one visibility impairment pollutant (SO2) for 

another (NOx), as induration furnaces 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 an 

option, not to direct the fuel choice.24 

Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility 

impairment pollutant for another, and the fact that BART is not intended to mandate a fuel switch, 

alternative fuels as an SO2 air pollution control technology will not be further evaluated in this 

report. However, similar to energy efficiency, facilities will continue to evaluate and implement 

alternate fuel usage as the feasibility arises. 

Coal Processing 

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. 

 

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

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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.25 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. 

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 crushing and drying is currently employed by United Taconite for Line 2 as an incidental option 

for SO2 reduction. In the process, raw coal is crushed and screened to remove rocks and other 

impurities. The crushed coal is then thermally processed to remove excess moisture. Coal crushing 

and drying is already in use, so further reductions from this control option are not possible. 

Therefore, it 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 as secondary controls to the existing indurating furnace wet scrubbers are 

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

 

25 The coal processing description provided herein is based on the K-Fuel® process under development by KFx, Inc. 

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

Technical Feasibility 

SO2 Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

Wet Scrubbing (Secondary) Yes Yes Yes 

Modification to Existing Wet 

Scrubber 

Yes Yes No 

Wet Walled Electrostatic 

Precipitator (WWESP) 

Yes Yes Yes 

Dry sorbent injection Yes Yes No 

Spray Dryer Absorption 

(SDA) 

Yes Yes No 

Alternative Fuels Yes Yes Yes – Not 

Required 

Energy Efficiency Projects Yes Yes Not Required 

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

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

options. The WWESP and high efficiency wet scrubbing control options listed in Table 5-2 would be 

considered polishing controls since a wet scrubber currently exists that achieves some control of SO2. 

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 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 the above alternatives on each 

stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. 

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EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that unit was 

scaled to each stack’s flow rate using the 6/10 power law as shown in the following equation: 

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

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 93% utilization and annual operating hours 

of 6600 hours for Line 1 and 8700 hours for Line 2. Operating costs of consumable materials, such as 

electricity, water, and chemicals were established based on the U.S. EPA control cost manual26 and 

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

Due to space considerations, 60%27 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 retrofit projects. See Appendix C 

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

Table 5-3 Indurating Furnace 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) 

 

Line 1 Pellet 

Induration $29,805,809 $7,441,650 $671,145 

Line 2 Pellet 

Induration $41,621,612 $17,974,280 $8,171 $22,600 

 

26 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 27 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 

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Control 

Technology 

Installed 

Capital Cost 

(MM$) 

Operating Cost

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental

Control 

Cost 

($/ton) 

Wet Scrubber 

(Additional) 

Line 1 Pellet 

Induration $20,773,230 $3,196,687 $384,402 

Line 2 Pellet 

Induration $28,067,807 $5,545,472 $3,361 Lowest 

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 $1,300 cost 

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant28. 

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

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost listed in Table 5-3 is intended to represent the incremental value of each 

technology as compared to the technology with the next highest level of control. 

 

28 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 control for Line 1 is far above the screening threshold for carrying either technology 

forward in this analysis. The cost of control for Line 2 is below the screening threshold for both 

technologies, however the incremental cost of a WWESP is higher than the screening threshold, so a 

polishing wet scrubber will be carried forward in this analysis. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for wet scrubbers and WWESPs 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 

• Ponding for scrubber 

discharge will be limited 

because of site space 

constraints 

• Additional solid 

waste/sludge generation 

• Process downtime/lost 

production during 

installation 

Wet Walled 

Electrostatic 

Precipitator 

(WWESP) 

• Additional electrical 

consumption due to 

operation of the ESP 

• Additional water 

consumption and 

wastewater generation 

• Increased facility waterbalance and water quality 

issues 

• Ponding for scrubber 

discharge will be limited 

because of site space 

constraints 

• Additional solid 

waste/sludge generation 

(or increased sulfate 

loading to wastewater for 

caustic reagent) 

• Process downtime/lost 

production during 

installation 

• Plume visibility 

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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. 

Predicted 24-Hour Maximum Emission Rates 

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

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

maximum 24-hour average project emission rate. In the visibility impacts analysis for SO2, the 

emissions from the sources undergoing a full BART SO2 analysis were adjusted to reflect the 

projected 24-hour maximum SO2 emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-5 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated SO2 control technologies. Table 5-6 provides a summary 

of the SO2, NOx, and PM10 emissions for each modeling scenario, and Table 5-7 provides a summary 

of the modeling input data. 
Table 5-5 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reduction 

6 Base (Wet PM Scrubbers) N G on L1 & L2; Prior to Heat Recoup on Line 1 

SV 046 EU 040 Line 1 0% 8 0% SV 048 EU 042 Line 2 0% 20 0% SV 049 EU 042 Line 2 0% 22 0% 

8 Base (Wet PM Scrubbers) Solid fuels on L2; Fuel Oil on L1;Heat recoup on L1 

SV 046 EU 040 Line 1 0% 199 46% SV 048 EU 042 Line 2 0% 346 0% SV 049 EU 042 Line 2 0% 267 0% 

2 Base (Wet PM Scrubbers) N G on L1 & L2; with Heat Recoup L1 

SV 046 EU 040 Line 1 0% 8 46% SV 048 EU 042 Line 2 0% 20 0% SV 049 EU 042 Line 2 0% 22 0% 

1 Base (Wet PM Scrubbers) Solid fuels on L2; N G on L1; with Heat Recoup L1 

SV 046 EU 040 Line 1 0% 8 46% SV 048 EU 042 Line 2 0% 346 0% SV 049 EU 042 Line 2 0% 287 0% 

3 Wet Walled ESP on Line 2 Solid fuels on L2; N G on L1; Heat Recoup L1 

SV 046 EU 040 Line 1 0% 8 0% SV 048 EU 042 Line 2 80% 69 0% SV 049 EU 042 Line 2 80% 57 0% 

4

Wet SO2 Scrubber 

on Line 2 

(secondary 

scrubber) 

Solid fuels on L2; NG on L1; 

Heat Recoup on L1 

SV 046 EU 040 Line 1 0% 8 0 SV 048 EU 042 Line 2 60% 138 0 SV 049 EU 042 Line 2 60% 115 0 

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 Table 5-6 Post-Control SO2 Modeling Scenarios - Modeling Input Data 

C:\Docu

Control 

Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base 

Elevation of 

Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow R

ex

(acf

All 

46 EU 040 Line 1 532024.98 5244399.88 140 1382 10 36948 EU 042 Line 2 531995.03 5244364.98 153 1371 12 34649 EU 042 Line 2 531983.41 5244432.55 153 1378 12 380
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Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for SO2 are presented in Table 5-8. The 

results summarize the 98th percentile dV value and the number of days the facility contributes more 

than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the postcontrol modeling scenarios to the baseline conditions is presented in Table 5-9. It is important to note 

that Scenarios 6, 8, 2 and 1 are all baseline conditions using permitted fuels, as described in Table 5-

5. To evaluate the impact of add-on SO2 controls in Scenarios 3 and 4 the results are compared to 

Scenario 1, which uses the same fuels without SO2 controls. 

 As illustrated in Tables 5-8 and 5-9, the highest facility baseline visibility contribution is 4.7 dV 

(Scenario 6-both lines using natural gas, prior to the heat recoup project on Line 1). Installing heat 

recoup on Line 1 reduced that impact by 0.7 dV to 4.0 dV due to NOx emission reductions (Scenario 

2-both lines using natural gas, after the heat recoup project). The facility is currently operating under 

Scenario 1, consisting of natural gas on Line 1 and solid fuels on Line 2. The modeled visibility 

impact under Scenario 1 is 2.0 dV. A polishing wet scrubber would potentially reduce the visibility 

contribution by 0.1 dV at a cost of over $28 million in installed capital cost and a total annual cost of 

over $5.5 million per year. This would result in a cost per deciview reduction of over $50 million 

per deciview. A WWESP on Line 2 would potentially reduce the visibility impact by 0.1 dV over 

$41 million in installed capital cost and a total annual cost of $16.9 million per year. This would 

result in a cost per deciview reduction of $117 million per deciview. 

Visibility impacts with NOx controls are presented in Section 6. 
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Table 5-8 Post-Control SO2 Modeling Scenarios - Visibility Modeling Results 

2002 2003 2004 

2002 – 200

Combined 

Scenario # 

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 

Modeled 98th

Percentile 

Value 

(deciview) 

N

ex

6 Base BWCA 3.5 121 4.0 116 4.7 103 4.0 8 Base BWCA 1.6 78 2.1 74 2.2 62 2.0 2 Base BWCA 3.0 114 3.5 115 4.0 97 3.5 1 Base BWCA 1.5 66 1.9 67 2.0 53 1.8 

3 BWCA 1.3 57 1.6 62 1.9 47 1.6 4 BWCA 1.4 59 1.7 65 1.9 49 1.7 

Table 5-9 Post-Control SO2 Modeling Scenarios - Visibility Improvements 

C:\Docu

Modeling Results 

0 2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

3 BWCA 0.1 9 0.3 5 0.1 6 0.2 204 BWCA 0.1 7 0.2 2 0.1 4 0.1 13

Scenarios 3 and 4 are compared to Scenario 1, consisting of solid fuels on Line 2 and after the installation of heat recoup on Line 
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: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed from fuel combustion as nitrogen compounds in the fuel are 

oxidized. 

• 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. 

In taconite furnaces, thermal NOx production is a function of the residence time, free oxygen, 

and temperature, primarily in the flame area of the furnace. 

• 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 furnaces. 

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With the understanding of how NOx is formed, available and applicable control technologies were 

evaluated. See Appendix D for the current status of the availability and applicability of retrofit 

control technologies. 

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for NOx emission reduction. Within 

Step 2, the technical feasibility of the control option was also discussed and determined. The 

following describes retrofit NOx control technologies that were identified as available and applicable 

in the original submittal and discusses aspects of those technologies that determine whether or not 

the technology is technically feasible for indurating furnaces. 

External Flue Gas Recirculation (EFGR) 

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

thereby reducing thermal 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 

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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 normal NOx control efficiency range for EFGR is 30% to 50%. 

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

1. The exhaust gas in an induration furnace typically has an oxygen content that is close to 

ambient, or 18% oxygen, vs. a boiler which has 2% - 3% oxygen. In a boiler, the flue gas 

is relatively inert so it can be used as a diluent for flame temperature reduction. Taconite 

waste gas has much higher oxygen level; thus use of taconite waste gas for EFGR would 

be equivalent to adding combustion air instead of an inert gas. 

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

F in order to meet 

product specifications. Existing burners are designed to meet these process conditions. 

Application of EFGR would reduce flame temperatures. Lower flame temperatures 

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

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

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

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

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

equipment failures. 

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

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

Low- 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. 

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 

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

molecular nitrogen (N2) over nitric oxide (NO). The estimated NOx control efficiency for LNB in 

high temperature applications is 10%. Low NOx burners have been installed in the preheating section 

of a straight grate furnace at another taconite plant. If LNB were to be applied in the indurating zone 

of the furnace, the reduced flame temperatures associated with LNB would adversely affect taconite 

pellet product quality. LNB has not been applied to the indurating zone of any grate-kiln taconite 

furnace. Therefore, this option is not viable. 

It is also important to note that there are other methods being developed for LNB which are not yet 

commercially available. Some incorporate various fuel dilution techniques to reduce flame 

temperatures; such as mixing an inert gas like CO2 with natural gas. Water injection to cool the 

burner peak flame temperature is also being investigated. This technique has already been 

successfully used for reducing NOx emissions from gas turbines and a straight grate taconite 

indurating furnace in the Netherlands. The water injection technique shows promise for high 

temperature applications, but will not be further investigated in this report as the technology is still in 

the development phase and is not yet commercially available. 

 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 noted above, taconite furnaces are designed to operate with oxygen levels near 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. 

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Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution 

emissions. United Taconite recently installed heat recuperation on Line 1 and performed stack 

testing to quantify the emission reductions. Testing completed in May of 2005 revealed that NOx

emissions were reduced 46%. This alternative will be carried forward in this analysis. 

Ported Kilns 

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the 

kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as 

it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is 

equipped with a closure device that opens when it is at the bottom position to inject air in the pellet 

bed, and closed when it rotates out of position. 

The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation 

reaction produces 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 reduces the carry over of the oxidation reaction into the pellet coolers. 

Ported kilns are potentially applicable to grate kilns. In the past, the technology was believed to 

reduce NOx formation. However, the technology vendor will not guarantee that ported kilns will 

reduce NOx emissions because controlling the oxygen in the firing zone is not possible due to the 

flow of air from the cooler29. Any reduction in NOx would be minor and incidental to the process 

improvement and specific to the individual furnace. Therefore, although this may be an available and 

applicable technology, it does not reduce NOx emissions and will not be further evaluated in this 

report. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has moved companies 

to evaluate alternate fuel sources. These fuel sources come in all physical forms – solid, liquid and 

gas. Reduction of NOx emissions through alternative fuel usage has been achieved at taconite grate 

kilns through the use of solid fuel. In these cases the reduction resulted due to changes from 

pulverized solid fuel dispersal in the kiln that resulted in lower flame temperature compared to other 

 

29 Telephone conversation with Metso, July 18, 2006. 

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fuels. Switching from natural gas or oil to solid fuel has a potential drawback in that I can exchange 

one visibility impairment pollutant (NOx) for another (SO2). 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 an 

option, not to direct the fuel choice.30 

Process Optimization with NOx CEMS or Other Parametric Monitoring 

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

emissions31. Parametric monitoring is a possible derivative of this alternative. 

Based on conversations with MPCA staff, this work practice would include process adjustments, or 

optimization, to minimize NOx emissions. The impact of the process adjustments would be measured 

using the NOx CEMS. This approach has been used in the electric utility industry to fine tune NOx 

emissions from boilers. 

One taconite plant has installed NOx CEMS to monitor emissions, but not to optimize NOx emissions 

through process fine tuning. That plant has experienced some reduction in NOx emissions, but these 

encompass multiple variables and are not attributed to process fine tuning with the NOx CEMS. 

Therefore, this alternative has not been demonstrated in the taconite industry. 

There are several concerns with utilizing process optimization as an available, applicable and 

technically feasible control option for the taconite industry: 

• Taconite furnaces are designed and operated to convert magnetite to hematite in the presence 

of excess oxygen and require heat input to initiate the reaction which is exothermic and 

releases heat once initiated. Fuel combustion is only part of the process and therefore this 

process is different from a boiler. 

 

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

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

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• The quality of the process feed materials to the furnace is variable at some taconite 

operations and product quality may be compromised by attempting to fine tune heat input to 

minimize NOx formation. 

• At some operations, the operating parameters which generally influence the rate of NOx

generation such as flame temperature, fuel usage and excess air are relatively constant during 

operation of the furnace, independent of process operation variability. This indicates that NOx

formation may not be dependent upon controllable operating parameters. In the absence of 

controllable parameters, process optimization would not be effective at controlling NOx

emissions. 

Based upon this information, there is no indication that further emission reductions would be 

achieved through process optimization, using NOx CEMS or other parametric monitoring, as a 

control technology. Therefore, process optimization as a control option will not be evaluated further 

in this report. 

Post Combustion Controls 

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. 

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 

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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) 

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 – 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 

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(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR 

and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the 

preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow 

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

recovery. 

The benefits of RSCR are: 

• Its high energy efficiency allows it to be used after SO2 and particulate controls. 

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

thermal efficiency of 60% to 70%. 

• Application of RSCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

There are several concerns about the technical feasibility and applicability of RSCR on an indurating 

furnace: 

• The composition of the indurating furnace flue gas is significantly different from the 

composition of the flue gas from the boilers that utilize RSCR; 

• The taconite dust is highly erosive and can cause significantly equipment damage. RSCR has 

a number of valves which must be opened and closed frequently to switch catalyst/heat 

recovery beds. These valves could be subject to excessive wear in a taconite application due 

to the erosive nature of the taconite dust; 

• RSCR has not been applied downstream of a wet scrubber. Treating a stream saturated with 

water may present design problems in equipment sizing for proper heat transfer and in 

corrosion protection; 

• RSCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by 

the local environment and have adverse impact. The impact of RSCR on mercury emissions 

needs to be studied to determine whether or not mercury oxidation is a problem and to 

identify mitigation methods if needed. 

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To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not 

been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace 

exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant 

would require research, test runs, and extended trials to identify potential issues related to catalyst 

selection, and impacts on plant systems, including the furnaces and emission control systems. It is 

not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of 

a demonstration project. The timeline required to perform such a demonstration project would likely 

be two years to develop and agree on the test plan, obtain permits for the trial, commission the 

equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and 

report on the results. The results would not be available within the time window for establishing 

emission limits to be incorporated in the state implementation plan (SIP) by December 2007. 

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

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

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

Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has 

been successfully implemented more widely and in higher airflow applications and will be carried 

forward in this analysis as available and applicable technology that is reasonably expected to be 

technically feasible. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

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 

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) 

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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. 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 the exhaust at United Taconite are typically less than 200 

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 

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 

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technology may apply to an indurating furnace, the furnace exhaust contains other ore components 

that may participate in side reactions. This technology has not been demonstrated on a taconite pellet 

indurating furnace. This raises uncertainties about how or whether the technology will transfer to a 

different type of process. 

The second component of the technical feasibility review includes determining if the technology is 

commercially available. Evaluations of LTO found that it has only been applied to small to medium 

sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility. 

For example, the current installations of LoTOx® are on sources with flue gas flow rates from 150 – 

35,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of up to 

726,000 acfm. Therefore, the application of LTO would be more than an order of magnitude larger 

than the biggest current installation. This large scale-up is contrary to good engineering practices 

and could be problematic in maintaining the current removal efficiencies. 

In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

demonstrated to be an effective technology in widespread application. 

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

indurating furnace: 

• The composition of the indurating furnace flue gas is significantly different from 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; 

• 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; 

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• 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 5-10. The technical 

feasibility as determined in Step 2 is also included in Table 5-10.

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Table 5-10 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas 

Recirculation (EFGR) Yes No No 

Low- NOx Burners Yes Yes No 

Induced Flue Gas 

Recirculation Burners Yes Yes No 

Energy Efficiency Projects Yes Yes Yes 

Ported Kilns 

(Applies to Grate Kilns Only) Yes Yes No 

Alternative Fuels Yes Yes Yes, Not 

Required 

Process Optimization using 

NOx CEMS Yes No No 

Non-Selective Catalytic 

Reduction (NSCR) Yes No No 

Selective Catalytic 

Reduction (SCR) with 

conventional reheat 

Yes Yes Yes 

Regenerative SCR Yes No No 

Selective Non-Catalytic 

Reduction (SNCR) Yes No No 

Low Temperature Oxidation 

(LTO) Yes No No 

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

Table 5-11 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

Table 5-11 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

SCR with Conventional 

Reheat 80% 

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

Table 5-12 summarizes the expected costs associated with installation of low NOx burners and SCR 

with conventional reheat. Capital costs were calculated based on the maximum 24-hour emissions, 

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54
U.S. EPA cost models, and vendor estimates. Vendor estimates for capital costs based on a specific 

flow rate were scaled to each stack’s flow rate using the 6/10 power law to account for the economy 

of scale. Operating costs were based on 93% utilization and annual operating hours of 6600 hours 

for Line 1 and 8700 hours for Line 2. Operating costs were proportionally adjusted to reflect site 

specific flow rates and pollutant concentrations. 

After a tour of the facility and discussions with facility staff, it was determined the space surrounding 

the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to 

transport materials to and from the building. A site-specific estimate for site-work, foundations, and 

structural steel was added based upon the facility site to arrive at the total retrofit installed cost of the 

control technology. The site specific estimate was based on Barr’s experience with recent actual 

retrofit costs. See Appendix C for a site plan of the facility. Additionally, the structural design of the 

existing building would not support additional equipment on the roof. The detailed cost analysis is 

provided in Appendix A. 

Table 5-12 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 (SCR) with Reheat 

Line 1 Pellet Induration $44,591,384 $23,923,236 $13,659 NA 

Line 2 Pellet Induration solid 

fuels $70,762,832 $35,189,143 $22,017 NA 

Line 2 Pellet Induration natural 

gas $72,222,298 $37,770,123 $4,736 NA 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

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

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

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

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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 pollutant32. 

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

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost column in Table 5-6 is intended to present the incremental value of each 

technology as compared to the technology with the next most effective alternative. Since none of the 

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

The cost of NOx control using SCR for Line 1 and Line 2 using solid fuels are over $12,000 per ton 

removed, which is above the screening threshold for further consideration. When Line 2 uses natural 

gas, the cost per ton removed is $4736, which is below the $12,000 screening level, but is more than 

a factor of three times the cost effectiveness threshold of $1000-$1300. this alternative is carried 

forward to analyze the energy and environmental impacts as well as visibility impacts. 

Energy and Environmental Impact 

The energy and non-air quality impacts for the remaining alternatives are presented in Table 5-13. 

Table 5-13 NOx Control Technology Impacts Assessment 

Control Technology Energy Impacts Other Impacts 

SCR with Reheat 

• Reheat would 

require additional 

natural gas use. 

• Ammonia slip, which 

contributes to regional 

haze. Ammonia reacts 

with NOx to form 

ammonium nitrate and 

SO2 to form ammonium 

sulfate particles. 

Ammonium sulfate is 

hygroscopic and bonds 

with water in the air to 

grow large particles. The 

 

32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 

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large particles formed by 

ammonium sulfate 

disproportionately 

contribute to visibility 

impairment . 

• Ammonia emissions will 

increase condensable PM 

emissions that will have 

possible PSD permitting 

implications. 

• Ammonia deposition onto 

nearby lakes and waters 

of the state and contribute 

nutrients and undesirable 

biological growth. 

• Additional safety and 

regulatory concerns 

associated with ammonia 

storage on site. 

• Possible oxidation of 

elemental mercury. 

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. 

Predicted 24-Hour Maximum Emission Rates 

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

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

maximum 24-hour average project emission rate. In the visibility impacts NOx modeling analysis, 

the emissions from the sources undergoing a full BART NOx analysis were adjusted to reflect the 

projected 24-hour maximum NOx emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-14 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOx control technologies. Table 5-15 provides a 

summary of the SO2, NOx, and PM10 emissions for each modeling scenario, and Table 5-16 provides 

a summary of the modeling input data. 

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Table 5-14 Post-Control NOx Modeling Scenarios 

Control 

Scenario SV # 

Emission Unit 

Descripition NOx Control Technology 

NOx 

% Reduction 

24-hr Max 

(lb/hr) 

6 Base: NG on L1 & L2; Prior 

to Heat Recoup on Line 1 

 SV 046 Line 1 SV 046 0% 1208 

 SV 048 Line 2 SV 048 0% 953 

 SV 049 Line 2 SV 049 0% 1068 

2 Base: NG on L1 & L2; with 

Heat Recoup on Line 1 

 SV 046 Line 1 SV 046 46% 651 

 SV 048 Line 2 SV 048 0% 953 

 SV 049 Line 2 SV 049 0% 1068 

7 

NG on L1 & L2; with Heat 

Recoup on Line 1; SCR on 

Line 2 

 

 SV 046 Line 1 SV 046 46% 651 

 SV 048 Line 2 SV 048 80% 191 

 SV 049 Line 2 SV 049 80% 214 

Table 5-15 Post-Control NOX Modeling Scenarios – Emissions Data 

Scenario Control Technology SO2 NOx

Control 

Scenario SV # Emission Unit SO2 NOx

% 

Reduction 

Max 

24-hour 

lbs/hr 

% 

Reduction 

Max 

24-hour 

lbs/hr 

6 Prior to Heat 

Recoup on Line 1 

Old Base: Prior 

to Heat Recoup 

on Line 1 

 

 SV 046 Line 1 SV 046 0% 8 0% 1208 

 SV 048 Line 2 SV 048 0% 20 0% 953 

 SV 049 Line 2 SV 049 0% 22 0% 1068 

2 

Base 

(Wet PM 

Scrubbers) 

New Base with 

Heat Recoup on 

Line 1 

 

 SV 046 Line 1 SV 046 0.0% 8 46% 651 

 SV 048 Line 2 SV 048 0.0% 20 0% 953 

 SV 049 Line 2 SV 049 0.0% 22 0% 1068 

7 

Base 

(Wet PM 

Scrubbers) 

NG on L1&L2; 

with Heat 

Recoup on Line 

1; SCR on Line 

2 

 

 SV 046 Line 1 SV 046 0.0% 8 46% 651 

 SV 048 Line 2 SV 048 0.0% 20 80% 191 

 SV 049 Line 2 SV 049 0.0% 22 80% 214 

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Table 5-16 Post-Control NOX Modeling Scenarios - Visibility Modeling Input Data 

Control 

Scenario 

SV 

# 

Emission Unit 

Descripition 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground

(ft) 

Base 

Elevation

from 

Ground 

(ft) 

Stack 

length, 

width or 

Diameter 

(ft) 

Flow 

Rate 

at Exit 

(acfm) 

Exit 

Temp 

(

o

F) 

All 

 46 Line 1 SV 046 532025 5244400 140 1382 10 369137 129 

 48 Line 2 SV 048 531995 5244365 153 1371 12 346000 127 

 49 Line 2 SV 049 531983 5244433 153 1378 12 380000 115 

Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for NOX are presented in Table 5-17. The 

results summarize 98th percentile dV value and the number of days the facility contributes more than 

a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the post-control 

modeling scenarios to the baseline conditions is presented in Table 5-18. 

As illustrated in tables 5-17 and 5-18, the facility baseline visibility contribution is 4.7 dV. Installing 

heat recoup on Line 1 reduced that impact by 0.7 dV to 4.0 dV. Installing SCR on Line 2 when 

natural gas is burned could potentially reduce the visibility contribution by 2.1 dV compared to 

Scenario 2, which includes the heat recoup project already installed on Line 1. Line 2 currently uses 

solid fuels (Scenario 1, see Table 5-5 through 5-9). The visibility improvement reflected in Scenario 

7 is realized when Line 2 uses natural gas, which is a permitted scenario, but does not reflect current 

operations. 

Visibility impacts with SO2 controls are presented in section 6. 

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Table 5-17 Post-Control NOX Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

6 BWCA 3.5 121 4.0 116 4.7 103 4.0 340 

2 BWCA 3.0 114 3.5 115 4.0 97 3.5 326 

7 BWCA 1.4 57 1.6 62 1.9 47 1.6 166 

Table 5-18 Post-Control NOX Modeling Scenarios - Visibility Improvements 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

2 BWCA 0.5 7 0.5 1 0.7 6 0.5 14 

7 BWCA 1.6 57 1.8 53 2.1 50 1.8 160 

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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 section 5 of this 

document. This section of the report evaluates the various BART control scenarios utilizing both 

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

6.A Post-Control Modeling Scenarios 

Steps 1-4 of the BART analysis identified the control technologies that were: 

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that 

met the requirements of the screening analysis of steps 1-4. 

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. Accordingly, this visibility improvement analysis evaluates several operating 

control scenarios that account for the various combinations of available NOx controls. In addition, 

two site-specific scenarios were developed so that the evaluation includes other operating scenarios 

and conditions that would improve visibility impairment. The post-control modeling scenarios, 

including those presented in Step 5 of section 5, are presented in Table 6-1. The modeling scenario 

stack parameters are presented in Table 6-2. 

6.B Post-Control Modeling Results 

Results of the post-control modeling scenarios are presented in Table 6-3. The results summarize 

98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of 

visibility impairment at each of the Class I areas. The comparison of the post-control modeling 

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scenarios to the baseline conditions is presented in Table 6-4. Additionally, Table 6-5 illustrates the 

scenarios on a $/dV basis. 

As mentioned in section 5.B.ii.e, the energy efficiency projects implemented at United Taconite will 

reduce its contribution to visibility impacts at Class I areas from 4.7 dV to 4.0 dV, which is a 

reduction of 15%. These reductions have already been implemented. They represent a significant 

contribution toward MPCA’s default glide-path goal of reducing impacts by 1.67% per year. 
Table 6-1 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 NOx 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction Max 24-hour lbs/hr % Reduction Max 24-hour lbs/hr 

M

6 Base (Wet PM Scrubbers) Base:NG on L1 & L2;Prior to Heat Recoup on L1 

SV 046 Line 1 SV 046 0% 8 0% 1208 SV 048 Line 2 SV 048 0% 20 0% 953 SV 049 Line 2 SV 049 0% 22 0% 1068 

8 Base (Wet PM Scrubbers) Base: Solid fuel on L2; fuel oil on L1; heat recoup on L1 

SV 046 Line 1 SV 046 0.0% 199 46% 651 SV 048 Line 2 SV 048 0.0% 346 0% 203 SV 049 Line 2 SV 049 0.0% 287 0% 173 

2 Base (Wet PM Scrubbers) Base:NG on L1&L2; heat recoup on L1 

SV 046 Line 1 SV 046 0.0% 8 46% 651 SV 048 Line 2 SV 048 0.0% 20 0% 953 SV 049 Line 2 SV 049 0.0% 22 0% 1068 

1 Base (Wet PM Scrubbers) Base: Solid fuel on L2; NG on L1; heat recoup on L1 

SV 046 Line 1 SV 046 0.0% 8 46% 651 SV 048 Line 2 SV 048 0.0% 346 0% 203 SV 049 Line 2 SV 049 0.0% 287 0% 173 

3 Wet Walled ESP on Line 2 Base Solid Fuel on L2; NG on L1; heat recoup on L1 

SV 046 Line 1 SV 046 0% 8 0% 651 

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Scenario Control Technology SO2 NOx 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction Max 24-hour lbs/hr % Reduction Max 24-hour lbs/hr 

M

SV 048 Line 2 SV 048 80% 69 0% 203 SV 049 Line 2 SV 049 80% 57 0% 173 

4

Wet SO2 Scrubber on 

Line 2 

(secondary scrubber) 

Base Solid Fuel on L2; NG 

on L1; heat recoup on L1 

SV 046 Line 1 SV 046 0% 8 0 651 SV 048 Line 2 SV 048 60% 138 0 203 SV 049 Line 2 SV 049 60% 115 0 173 

7 Base (Wet PM Scrubbers) Base: NG on L1&L2; heat recoup on L1; SCR on L2 

SV 046 Line 1 SV 046 0.0% 8 46% 651 SV 048 Line 2 SV 048 0.0% 20 80% 191 SV 049 Line 2 SV 049 0.0% 22 80% 214 

Table 6-2 Post-Control NOX Modeling Scenarios - Modeling Input Data 

Control 

Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

Base 

Elevation of 

Ground 

(ft) 

Stack 

length, 

width, or 

Diameter 

(ft) 

Flow R

ex

(acf

All 

46 Line 1 SV 046 532024.98 5244399.88 140 1382 10 369148 Line 2 SV 048 531995.03 5244364.98 153 1371 12 346049 Line 2 SV 049 531983.41 5244432.55 153 1378 12 3800

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Table 6-3 Post-Control Modeling Scenarios - Visibility Modeling Results 

2002 2003 2004 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Modeled 

98th

Percentil

e Value 

(deciview

) 

No. of 

days 

exceedin

g 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 

Mod

9

Perc

Va

(dec

6 Base BWCA 3.5 121 4.0 116 4.7 103 48 Base BWCA 1.6 78 2.1 74 2.2 62 22 Base BWCA 3.0 114 3.5 115 4.0 97 31 Base BWCA 1.5 66 1.9 67 2.0 53 1

3 WWESP BWCA 1.3 57 1.6 62 1.9 47 1

4 Secondary Wet 

Scrubber BWCA 1.4 59 1.7 65 1.9 49 1

7 SCR with Nat 

Gas on Line 2 

BWCA 1.6 57 1.8 53 2.1 50 1

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Table 6-4 Post-Control Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

0 2002 2003 2004 2002-

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

2 BWCA 0.5 7 0.5 1 0.7 6 0.5 3 BWCA 0.1 9 0.3 5 0.1 6 0.2 4 BWCA 0.1 7 0.2 2 0.1 4 0.1 7 BWCA 1.6 57 1.8 53 2.1 50 1.8 

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Scenario SO2 NOx Annualized Cost ($/yr) 

Improved 

Modeled 98th 

Percentile 

Value 

(∆-dV) 

$/d

2 

Base (Wet PM Scrubbers) 

Solid fuels on L2; NG on L1; Heat Recoup on L1 -- 0.7 --

3 

Wet Walled ESP on Line 2 

Solid fuels on L2; NG on L1; Heat Recoup on L1 $16,872,571 0.1 $117,

4 

Wet SO2 Scrubber on 

Line 2 (secondary scrubber) 

Solid fuels on L2; NG on L1; Heat Recoup on L1 $5,590,498 0.1 $52,

7 

Base (Wet PM Scrubbers) 

Nat Gas with SCR on L2; NG with heat recoup on L1 $37,770,123 2.1 $17,

Table 6-5 Post-Control Modeling Results – Dollars per Deciview Improvement 

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C:\Docu
7. Select BART 

BART for United Taconite is determined to be as described below. 

For SO2, polishing add-on controls are not cost effective. Therefore, BART is determined to be 

existing controls. The corresponding SO2 emissions limit is 2 lb per million Btu heat input for Line 1 

when liquid fuel is burned. For Line 2, the BART limit is 4 lb per million Btu heat input when solid 

fuel is burned or 2 lb per million Btu heat input when liquid fuel is burned. 

For NOx, the reduction due to the heat recuperation project on Line 1is selected as BART. Other addon controls for NOx are not cost effective. The NOx reductions for the heat recuperation project have 

been established through stack testing on Line 1. This represents a reduction in NOx emissions by 

557 lb per hr. Heat recoup is integral to the process, therefore no limitation is required. 

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

The overall improvement in visibility contribution is a reduction by 15%. This represents a 

significant contribution to the default glide path of reducing impacts by 1-2% per year. The schedule 

for implementation of controls is by October 30, 2006, well in advance of the 5-year time-frame 

required for BART implementation. 

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Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis<Table 1 >: Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton

Selective Catalytic Reduction (SCR) + ReheatLine 1 Pellet Induration 80% 399.7 1751.5 $44,591,384 $23,923,236 $13,659 NA

Line 2 Pellet Induration 80% 35.0 1598.3 $70,762,832 $35,189,143 $22,017 NALine 2 Pellet Induration NG 80% 188.7 7975.8 $72,222,298 $37,770,123 $4,736 NAEnergy Efficiency Project - Heat Recoup on Line 1Line 1 Pellet Induration 46% --- --- ---

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton

Wet Walled Electrostatic Precipitator (WWESP)Line 1 Pellet Induration 80% 2.8 11.1 $29,805,809 $7,441,650 $671,145 NA

Line 2 Pellet Induration 80% 549.9 2199.7 $41,621,612 $17,974,280 $8,171 $22,600Wet Scrubber (Additional)Line 1 Pellet Induration 60% 5.5 8.3 $20,773,230 $3,196,687 $384,402 NALine 2 Pellet Induration 60% 1099.9 1649.8 $28,067,807 $5,545,472 $3,361 NA

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsCost Summary 
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis<Table 2>: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 1 Pellet Induration Study Year 2006

Emission Unit Number EU 040Stack/Vent Number SV 046

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042Stack/Vent Number SV 048 & 049Line 1 furnacemmbtu 190

Line 2 furnace mmbtu 400 Reference

Item Unit Cost Units Cost Year Data Source No

Operating Labor 45.31 $/hr 2006 Site Specific - United Taconite.

Maintenance Labor 47.22 $/hr 2006 Site Specific - United Taconite. Construction Labor Rate.

Electricity 0.04 $/kwh 2006 Site Specific - United Taconite. Purchased Cost.

Natural Gas 12.81 $/mscf 2006 Site Specific - United Taconite. $12.02/MMBtu @ 1066 Btu/scf.

Water 2.07 $/mgal 2006 Site Specific - United Taconite. Purchased Cost.

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 3.13 $/mgal 2006 Site Specific - United Taconite. Purchased Cost.

Chemicals & SuppliesLime 88.98 $/ton 88.98 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 484.56 $/ton 280 2003 United Taconite 2006 costOtherSales 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

Operating InformationAnnual Op. Hrs EU040 6599 Hours BART spreadsheet. Maximum hours of operation 2004-

Annual Op. Hrs EU042 8688 Hours BART spreadsheet. Maximum hours of operation 2004-

Utilization Rate 93%Equipment Life 20 yrsStandardized Flow RateSV 046 308,345 scfm @ 32o F Calculated.SV 048 & 049 615,086 scfm @ 32o F Calculated.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsUtility Chem$ Data 
Line 2 furnace mmbtu 400 Reference

Item Unit Cost Units Cost Year Data Source No

TemperatureSV 046 129 Deg F BART spreadsheet.SV 048 & 049 121 Deg F BART spreadsheet. Weighted average.Moisture ContentSV 046 13.8% 2005

Y:\23\69\948 United Taconite Post EERP Testing\Data\Waste Gas Stack. Average from test results in : Line 1 

SV 048 & 049 13.8% 2005 Y:\23\69\872 United Tac\Data. Weighted average from test results Actual Flow RateSV 046 369,137 acfm BART spreadsheet.SV 048 & 049 726,000 acfm BART spreadsheet.Standardized Flow RateSV 046 330,907 scfm @ 68o F Calculated.SV 048 & 049 660,092 scfm @ 68o F Calculated.Dry Std Flow RateSV 046 285,110 dscfm @ 68o F Calculated.SV 048 & 049 568,896 dscfm @ 68o F Calculated.

Max Emis Actual Emissions lb/hr ton/year

Pollutant Lb/Hr Ton/year ('04&'05 Max) ppmv ppmv lb/mmbtu

Nitrous Oxides (NOx)SV 046 651.3 2,151.2 319 240.2 3.428070175 2005 plus 10%SV 048 & 049 375.2 1,633.3 92 91.4 8.279997057 2004 plus 10%SV 048 & 049 with NG only 2021.0 8,164.5 495 457.0Sulfur Dioxides (SO2)SV 046 4.2 13.9 1 1.1 2004 plus 10%SV 048 & 049 632.2 2,749.7 111 110.5 2004 plus 10%estimatecalculated valueknown or assumed datarequired data

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046

Standardized Flow Rate 308,345 scfm @ 32o F

Expected Utilization Rate 93% Temperature 129 Deg FExpected Annual Hours of Operation 6,599 Hours Moisture Content 13.8%

Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F

Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTSCapital Costs Direct Capital Costs Purchased Equipment (A) 5,420,940 Purchased Equipment Total (B) 22% of control device cost (A) 6,586,442 Installation - Standard Costs 67% of purchased equip cost (B) 4,412,916

 Installation - Site Specific Costs 6,200,000 Installation Total 4,412,916 Total Direct Capital Cost, DC 10,999,359 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,754,272Total Capital Investment (TCI) = DC + IC 29,805,809Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,935,246 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,506,404Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,441,650

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 651.3 2,151.2 0% 2151.2 - NA

Sulfur Dioxide (SO2) 13.9 4.2 80% 2.8 11.1 671,145

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.3 CUECost Workbook Version 1.0, USEPA Document Page 2.

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 5,420,940

Instrumentation 10% of control device cost (A) 542,094MN Sales Taxes 6.5% of control device cost (A) 352,361Freight 5% of control device cost (A) 271,047

Purchased Equipment Total (B) 22% 6,586,442

Installation

Foundations & supports 4% of purchased equip cost (B) 263,458

Handling & erection 50% of purchased equip cost (B) 3,293,221Electrical 8% of purchased equip cost (B) 526,915Piping 1% of purchased equip cost (B) 65,864Insulation 2% of purchased equip cost (B) 131,729Painting 2% of purchased equip cost (B) 131,729

Installation Subtotal Standard Expenses 67% 4,412,916

Total Direct Capital Cost, DC 10,999,359Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,317,288Construction & field expenses 20% of purchased equip cost (B) 1,317,288Contractor fees 10% of purchased equip cost (B) 658,644Start-up 1% of purchased equip cost (B) 65,864Performance test 1% of purchased equip cost (B) 65,864Model Studies 2% of purchased equip cost (B) 131,729

Contingencies 3% of purchased equip cost (B) 197,593

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,754,272

Total Capital Investment (TCI) = DC + IC 14,753,631

Retrofit multiplier3 60% of TCI 8,852,178

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 29,805,809

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours 74,749Supervisor 15% 15% of Operator Costs 11,212

Maintenance

Maintenance Labor 47.22 $/Hr, 15.0 hr/wk, Annual Operating Hours 31,165

Maintenance Materials 1.00 % of Maintenance Labor 54,209

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 872 kW-hr, annual operating hours, 93% utilization 214,127Water 2.07 $/mgal, 1,846 gpm, annual operating hours, 93% utilization 1,406,804WW Treat Neutralization 3.13 $/mgal, 1,846 gpm, annual operating hours, 93% utilization 2,127,197Caustic 484.56 $/ton, 11 lb/hr, 6598.9 hr/yr, 93% utilization 15,782

Total Annual Direct Operating Costs 3,935,246

Indirect Operating Costs

Overhead 60% of total labor and material costs 102,802Administration (2% total capital costs) 2% of total capital costs (TCI) 295,073Property tax (1% total capital costs) 1% of total capital costs (TCI) 147,536Insurance (1% total capital costs) 1% of total capital costs (TCI) 147,536Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,813,458

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,506,404

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,441,650See summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unitAmount Required 0Total Rep Parts Cost 0Installation Labor 0Total Installed Cost 0Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 369,137 10 668.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 34.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 87,305 169.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 872.3Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1845.69 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 10.61 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 6,599

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating LaborOp Labor 45.31 $/Hr 2.0 hr/8 hr shift 1,650 74,749 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours Supervisor 15% of Op. NA 11,212 15% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 15.0 hr/wk 660 31,165 $/Hr, 15.0 hr/wk, Annual Operating HoursMaint Mtls 1 % of Purchase Cost NA 54,209 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1Utilities, Supplies, Replacements & Waste Management

Electricity 0.040 $/kwh 872.3 kW-hr 5,353,163 214,127 $/kwh, 872 kW-hr, annual operating hours, 93% utilizationWater 2.07 $/mgal 1,845.7 gpm 679,616 1,406,804 $/mgal, 1,846 gpm, annual operating hours, 93% utilization

WW Treat Neutralization 3.13 $/mgal 1,845.7 gpm 679,616 2,127,197 $/mgal, 1,846 gpm, annual operating hours, 93% utilization

Caustic 484.56 $/ton 10.6 lb/hr 33 15,782 $/ton, 11 lb/hr, 6598.9 hr/yr, 93% utilization

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

See summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049

Standardized Flow Rate 615,086 scfm @ 32o F

Expected Utilization Rate 93% Temperature 121 Deg FExpected Annual Hours of Operation 8,688 Hours Moisture Content 13.8%

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTSCapital Costs Direct Capital Costs Purchased Equipment (A) 8,134,372 Purchased Equipment Total (B) 22% of control device cost (A) 9,883,262 Installation - Standard Costs 67% of purchased equip cost (B) 6,621,786

 Installation - Site Specific Costs 6,200,000 Installation Total 6,621,786 Total Direct Capital Cost, DC 16,505,048 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,633,459Total Capital Investment (TCI) = DC + IC 41,621,612Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 13,024,545 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,949,735Total Annual Cost (Annualized Capital Cost + Operating Cost) 17,974,280

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 375.2 1,633.3 0% 1633.3 - NA

Sulfur Dioxide (SO2) 2,749.7 632.2 80% 549.9 2,199.7 8,171

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.3 CUECost Workbook Version 1.0, USEPA Document Page 2.

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 8,134,372

Instrumentation 10% of control device cost (A) 813,437MN Sales Taxes 6.5% of control device cost (A) 528,734Freight 5% of control device cost (A) 406,719

Purchased Equipment Total (B) 22% 9,883,262

Installation

Foundations & supports 4% of purchased equip cost (B) 395,330

Handling & erection 50% of purchased equip cost (B) 4,941,631Electrical 8% of purchased equip cost (B) 790,661Piping 1% of purchased equip cost (B) 98,833Insulation 2% of purchased equip cost (B) 197,665Painting 2% of purchased equip cost (B) 197,665

Installation Subtotal Standard Expenses 67% 6,621,786

Total Direct Capital Cost, DC 16,505,048Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,976,652Construction & field expenses 20% of purchased equip cost (B) 1,976,652Contractor fees 10% of purchased equip cost (B) 988,326Start-up 1% of purchased equip cost (B) 98,833Performance test 1% of purchased equip cost (B) 98,833Model Studies 2% of purchased equip cost (B) 197,665

Contingencies 3% of purchased equip cost (B) 296,498

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,633,459

Total Capital Investment (TCI) = DC + IC 22,138,507

Retrofit multiplier3 60% of TCI 13,283,104

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 41,621,612

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours 98,411Supervisor 15% 15% of Operator Costs 14,762

Maintenance

Maintenance Labor 47.22 $/Hr, 15.0 hr/wk, Annual Operating Hours 31,165

Maintenance Materials 1.00 % of Maintenance Labor 81,344

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,716 kW-hr, annual operating hours, 93% utilization 554,444Water 2.07 $/mgal, 3,630 gpm, annual operating hours, 93% utilization 3,642,680WW Treat Neutralization 3.13 $/mgal, 3,630 gpm, annual operating hours, 93% utilization 5,508,013Caustic 484.56 $/ton, 1,580 lb/hr, 8687.8 hr/yr, 93% utilization 3,093,727

Total Annual Direct Operating Costs 13,024,545

Indirect Operating Costs

Overhead 60% of total labor and material costs 135,409Administration (2% total capital costs) 2% of total capital costs (TCI) 442,770Property tax (1% total capital costs) 1% of total capital costs (TCI) 221,385

Insurance (1% total capital costs) 1% of total capital costs (TCI) 221,385

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,928,786

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,949,735

Total Annual Cost (Annualized Capital Cost + Operating Cost) 17,974,280See summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unitAmount Required 0Total Rep Parts Cost 0Installation Labor 0Total Installed Cost 0Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 726,000 10 1,314.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 68.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 171,708 333.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,715.6Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3630.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 1580.42 lb/hr causticOperating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating LaborOp Labor 45.31 $/Hr 2.0 hr/8 hr shift 2,172 98,411 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours Supervisor 15% of Op. NA 14,762 15% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 15.0 hr/wk 660 31,165 $/Hr, 15.0 hr/wk, Annual Operating HoursMaint Mtls 1 % of Purchase Cost NA 81,344 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1Utilities, Supplies, Replacements & Waste Management

Electricity 0.040 $/kwh 1715.6 kW-hr 13,861,102 554,444 $/kwh, 1,716 kW-hr, annual operating hours, 93% utilization

Water 2.07 $/mgal 3,630.0 gpm 1,759,749 3,642,680 $/mgal, 3,630 gpm, annual operating hours, 93% utilizationWW Treat Neutralization 3.13 $/mgal 3,630.0 gpm 1,759,749 5,508,013 $/mgal, 3,630 gpm, annual operating hours, 93% utilization

Caustic 484.56 $/ton 1,580.4 lb/hr 6,385 3,093,727 $/ton, 1,580 lb/hr, 8687.8 hr/yr, 93% utilization

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

See summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet Scrubber

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046

Standardized Flow Rate 308,345 scfm @ 32o F

Expected Utilization Rate 93% Temperature 129 Deg FExpected Annual Hours of Operation 6,599 Hours Moisture Content 13.8%Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F

Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTSCapital Costs Direct Capital Costs (1) Purchased Equipment (A)  Purchased Equipment Total (B) 22% of control device cost (A)  Installation - Standard Costs 85% of purchased equip cost (B)  Installation - Site Specific Costs  Installation Total  Total Direct Capital Cost, DC  Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 

Total Capital Investment (TCI) = DC + IC Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc.  Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost Total Annual Cost (Annualized Capital Cost + Operating Cost) 

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 651.3 2,151.2 0% 2151.2 - NA

Sulfur Dioxide (SO2) 13.9 4.2 60% 5.5 8.3 384,402

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.

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) MN Sales Taxes 7% of control device cost (A) Freight 5% of control device cost (A) 

Purchased Equipment Total (B) 22% 

Installation

Foundations & supports 12% of purchased equip cost (B) Handling & erection 40% of purchased equip cost (B) 

Electrical 1% of purchased equip cost (B) Piping 30% of purchased equip cost (B) 

Insulation 1% of purchased equip cost (B) Painting 1% of purchased equip cost (B) 

Installation Subtotal Standard Expenses 85% 

Total Direct Capital Cost, DC Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 

Construction & field expenses 0% of purchased equip cost (B) Contractor fees 5% of purchased equip cost (B) 

Start-up 1% of purchased equip cost (B) Performance test 1% of purchased equip cost (B) Model Studies NA of purchased equip cost (B) 

Contingencies 3% of purchased equip cost (B) 

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 

Total Capital Investment (TCI) = DC + IC 

Retrofit multiplier5 60% of TCI 

Sitework and foundations Site Specific Structural steel Site Specific Site Specific - Other Site Specific 

Total Site Specific Costs 

Total Capital Investment (TCI) Retrofit Installed 

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet Scrubber

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours Supervisor 15% 15% of Operator Costs 

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours Maintenance Materials 100% of maintenance labor costs 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 759 kW-hr, annual operating hours, 93% utilization 

Water 2.07 $/kgal, 346 gpm, annual operating hours, 93% utilization WW Treat Neutralization 3.13 $/kgal, 281 gpm, annual operating hours, 93% utilization Lime 88.98 $/ton, 4 lb/hr, annual operating hours, 93% utilization 

Total Annual Direct Operating Costs Indirect Operating Costs

Overhead 60% of total labor and material costs 

Administration (2% total capital costs) 2% of total capital costs (TCI) Property tax (1% total capital costs) 1% of total capital costs (TCI) 

Insurance (1% total capital costs) 1% of total capital costs (TCI) 

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 

Total Annual Cost (Annualized Capital Cost + Operating Cost) See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet Scrubber

Capital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Catalyst:Equipment Life 20 yearsCRF 0.0000Rep part cost per unit 0 $/ft3Amount Required 0 ft3Packing Cost 0 Cost adjusted for freight & sales taxInstallation 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 3CRF 0.3811Rep part cost per unit 0.00 $ eachAmount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 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 369,137 8.55 0.7 - 527.5 EPA Cost Cont Manual 6th ed Sec

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 14,027 gpm 1 60 0.7 - 226.0 EPA Cost Cont Manual 6th ed Sec

H2O WW Disch 346 gpm 1 60 0.7 - 5.6 EPA Cost Cont Manual 6th ed Sec

Other Total 759.1Reagent Use & Other Operating CostsCaustic Use 4.25 lb/hr SO2 2.50 lb NaOH/lb SO2 10.61 lb/hr Caustic

Lime Use 4.25 lb/hr SO2 0.96 lb Lime/lb SO2 4.09 lb/hr lime, lime addition at 1.1 times 

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acfCirculating Water Rate2 14,027 gpm

Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 346 gpm

Evaporation Loss4 = 65.82 gpm

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet Scrubber

Operating Cost Calculations Annual hours of operation: 6,599

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating LaborOp Labor 45.31 $/Hr 0.5 hr/8 hr shift 412 18,687 $/Hr, 0.5 hr/8 hr shift, Annual OperSupervisor 15% of Op. NA 2,803 15% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 0.5 hr/8 hr shift 412 19,475 $/Hr, 0.5 hr/8 hr shift, Annual OperMaint Mtls 100 % of Maintenance Labor NA 19,475 100% of Maintenance LaborUtilities, Supplies, Replacements & Waste ManagementElectricity 0.040 $/kwh 759.1 kW-hr 4,658,783 186,351 $/kwh, 759 kW-hr, annual operatinWater 2.07 $/kgal 346.4 gpm 127,538 264,005 $/kgal, 346 gpm, annual operating WW Treat Neutralization 3.13 $/kgal 280.5 gpm 103,302 323,334 $/kgal, 281 gpm, annual operating 

Lime 89.0 $/ton 4.1 lb/hr 13 1,116 $/ton, 4 lb/hr, annual operating hou

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

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet Scrubber

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049

Standardized Flow Rate 615,086 scfm @ 32o F

Expected Utilization Rate 93% Temperature 121 Deg F

Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8%

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTSCapital Costs Direct Capital Costs (1) Purchased Equipment (A) 

 Purchased Equipment Total (B) 22% of control device cost (A) 

 Installation - Standard Costs 85% of purchased equip cost (B) 

 Installation - Site Specific Costs  Installation Total  Total Direct Capital Cost, DC  Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 

Total Capital Investment (TCI) = DC + IC Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc.  Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost Total Annual Cost (Annualized Capital Cost + Operating Cost) 

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 375.2 1,633.3 0% 1633.3 - NA

Sulfur Dioxide (SO2) 2,749.7 632.2 60% 1099.9 1,649.8 3,361

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.

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5Instrumentation 10% of control device cost (A) MN Sales Taxes 7% of control device cost (A) Freight 5% of control device cost (A) 

Purchased Equipment Total (B) 22% 6

Installation

Foundations & supports 12% of purchased equip cost (B) Handling & erection 40% of purchased equip cost (B) 2Electrical 1% of purchased equip cost (B) 

Piping 30% of purchased equip cost (B) 2Insulation 1% of purchased equip cost (B) Painting 1% of purchased equip cost (B) 

Installation Subtotal Standard Expenses 85% 5

Total Direct Capital Cost, DC 12

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) Construction & field expenses 0% of purchased equip cost (B) Contractor fees 5% of purchased equip cost (B) Start-up 1% of purchased equip cost (B) 

Performance test 1% of purchased equip cost (B) Model Studies NA of purchased equip cost (B) Contingencies 3% of purchased equip cost (B) 

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1

Total Capital Investment (TCI) = DC + IC 13

Retrofit multiplier5 60% of TCI 8

Sitework and foundations Site Specific 1Structural steel Site Specific 4Site Specific - Other Site Specific 

Total Site Specific Costs 6

Total Capital Investment (TCI) Retrofit Installed 28

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet Scrubber

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours Supervisor 15% 15% of Operator Costs 

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours Maintenance Materials 100% of maintenance labor costs 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,493 kW-hr, annual operating hours, 93% utilizatio Water 2.07 $/kgal, 681 gpm, annual operating hours, 93% utilization WW Treat Neutralization 3.13 $/kgal, 552 gpm, annual operating hours, 93% utilization Lime 88.98 $/ton, 608 lb/hr, annual operating hours, 93% utilization 

Total Annual Direct Operating Costs 2Indirect Operating Costs

Overhead 60% of total labor and material costs Administration (2% total capital costs) 2% of total capital costs (TCI) Property tax (1% total capital costs) 1% of total capital costs (TCI) Insurance (1% total capital costs) 1% of total capital costs (TCI) Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet Scrubber

Capital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Catalyst:Equipment Life 20 years

CRF 0.0000Rep part cost per unit 0 $/ft3

Amount Required 0 ft3Packing Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0

Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unit 0.00 $ eachAmount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 Total Installed Cost 0 Zero out if no replacement parts neededAnnualized Cost 0Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 726,000 8.55 0.7 - 1,037.5 EPA Cost Cont Manual 6th ed Section 

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 27,588 gpm 1 60 0.7 - 444.5 EPA Cost Cont Manual 6th ed Section 

H2O WW Disch 681 gpm 1 60 0.7 - 11.0 EPA Cost Cont Manual 6th ed Section 

Other Total 1493.0Reagent Use & Other Operating CostsCaustic Use 632.17 lb/hr SO2 2.50 lb NaOH/lb SO2 1580.42 lb/hr Caustic

Lime Use 632.17 lb/hr SO2 0.96 lb Lime/lb SO2 608.46 lb/hr lime, lime addition at 1.1 times th

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acfCirculating Water Rate2 27,588 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 681 gpm

Evaporation Loss4 = 129.46 gpm

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BART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet Scrubber

Operating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating LaborOp Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, Annual OperatinSupervisor 15% of Op. NA 3,690 15% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, Annual OperatinMaint Mtls 100 % of Maintenance Labor NA 25,640 100% of Maintenance LaborUtilities, Supplies, Replacements & Waste ManagementElectricity 0.040 $/kwh 1493.0 kW-hr 12,063,123 482,525 $/kwh, 1,493 kW-hr, annual operating Water 2.07 $/kgal 681.2 gpm 330,239 683,595 $/kgal, 681 gpm, annual operating houWW Treat Neutralization 3.13 $/kgal 551.8 gpm 267,482 837,218 $/kgal, 552 gpm, annual operating hou

Lime 89.0 $/ton 608.5 lb/hr 2,458 218,719 $/ton, 608 lb/hr, annual operating hour

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

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 7: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046

Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 308,345 scfm @ 32o F

Expected Utiliztion Rate 93% Temperature 129 Deg F

Expected Annual Hours of Operation 6,599 Hours Moisture Content 13.8%

Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F

Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment (A) 15,894,553

 Purchased Equipment Total (B) SCR Only 16,927,699

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,935,740

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 44,591,384

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 18,389,200

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 5,534,036

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 23,923,236

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,151.2 130.3 0.69 399.7 1,751.5 13,659

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 7: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 15,894,553

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,033,146

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 16,927,699

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 16% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 16% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,935,740

Total Plant Cost D A + B + C 22,507,337

Allowance for Funds During Construction (E)

Pre Production Costs (G) 2% of (D+E)) 450,147

Inventory Capital Reagent Vol * $/gal 289,894

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 23,247,378

Retrofit multiplier3 60% of TCI 13,948,427

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

Total Retrofit Capital 37,195,804

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 2.0 hr/8 hr shift, 6598.9 hr/yr 74,749

Supervisor 15% 15% of Operator Costs 11,212

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 348,711

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 5,919 kW-hr, 6598.9 hr/yr, 93% utilization 1,453,059

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 747,654

NA NA - 

Ammonia 0.12 $/lb, 8,542 lb/hr, 6598.9 hr/yr, 93% utilization 6,322,342

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 8,957,727

Indirect Operating Costs

Overhead 60% fixed O&M 62,942

Administration (2% total capital costs) 2% of total capital costs (TCI) 464,948

Property tax (1% total capital costs) 1% of total capital costs (TCI) 232,474

Insurance (1% total capital costs) 1% of total capital costs (TCI) 232,474

Capital Recovery 9.44% for a 20- year equipment life and a 7% interest rate 3,511,021 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,503,858

Total Annual Cost (Annualized Capital Cost + Operating Cost) 13,461,585

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 7: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 1,859 Plant Cap kW A 190,728

Est power platn eff 35% Unc Nox lb/mmBtu B 3.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant k 190,728 Capital Cost $/kW D $83.34 $15,894,552.62 Total SCR Equipment

Uncontrolled Nox t/y 2,151.2 Fixed O&M E $104,904.05

Annual Operating Hrs 8000 Variable O&M F $423,896.63

Uncontrolled Nox lb/mm 3.428 Ann Cap Factor G 0.82

Heat Input mmBtu/ H 6,000

SCR Capital Cost

Duty 1,859 MMBtu/hr Catalyst Area 897 ft2 1,352 f (h SCR)

Q flue gas 861,164 acfm Rx Area 1,032 27 f (h NH3)

NOx Cont Eff 80% (as faction) Rx Height 32.1 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 3.43 lb/MMBtu n layer 51 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 53.6 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 52 layers 34,003,097 f (vol catalyst)

Temperature 129 Deg F h SCR 252 ft f (h SCR)

Catalyst Volume 141,680 ft3 New/Retrofit R N or R 

Electrical Use

Duty 1,859 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 5,919.3

NOx in 3.43 lb/MMBtu

n catalyst layers 52 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 5919.3

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

2477 lb/hr Neat 1141.2 gal/hr

29% solution Volume 14 day inventory 383,433 gal $289,894 Inventory Cost

8542 lb/hr

Design Basis Baseline Em Baseline Emi Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.69

Nitrous Oxide 2,151.2 3.428 651.33

Actual 90,035 dscf/MMBtu

Method 19 Factor 9,200 dscf/MMBtu

Adjusted Duty 1,859 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 6,599

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 2.0 hr/8 hr shift 1,650 74,749 $/Hr, 2.0 hr/8 hr shift, 6598.9 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 11,212

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 348,711 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.040 $/kwh 5919.3 kW-hr 36,326,476 1,453,059 $/kwh, 5,919 kW-hr, 6598.9 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 190.7 mw 112 $747,654 Catalyst Replacement

7 Ammonia 0.12 $/lb 8542 lb/hr 52,424,372 6,322,342 $/lb, 8,542 lb/hr, 6598.9 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

<Table 8>: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046 Chemical Engineering

Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 308,345 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 129 Deg F 1998/1999 390

Expected Annual Hours of Operation 6,599 Hours Moisture Content 13.8% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F

Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 611,190

 Purchased Equipment Total (B) 22% of control device cost (A) 742,596

 Installation - Standard Costs 30% of purchased equip cost (B) 222,779

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,422,779

 Total Direct Capital Cost, DC 7,165,375

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 230,205

Total Capital Investment (TCI) = DC + IC 7,395,580

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 9,431,473

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,030,178

Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,461,651

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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BART Report - <Appendix A> Emission Control Cost Analysis

<Table 8>: - Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 611,190

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 61,119

MN Sales Taxes 6.5% of control device cost (A) 39,727

Freight 5% of control device cost (A) 30,560

Purchased Equipment Total (B) 22% 742,596

Installation

Foundations & supports 8% of purchased equip cost (B) 59,408

Handling & erection 14% of purchased equip cost (B) 103,963

Electrical 4% of purchased equip cost (B) 29,704

Piping 2% of purchased equip cost (B) 14,852

Insulation 1% of purchased equip cost (B) 7,426

Painting 1% of purchased equip cost (B) 7,426

Installation Subtotal Standard Expenses 30% 222,779

Site Preparation, as required Site Specific 1,400,000

Buildings, as required Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Installation Total 6,422,779

Total Direct Capital Cost, DC 7,165,375

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 74,260

Construction & field expenses 5% of purchased equip cost (B) 37,130

Contractor fees 10% of purchased equip cost (B) 74,260

Start-up 2% of purchased equip cost (B) 14,852

Performance test 1% of purchased equip cost (B) 7,426

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 22,278

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 230,205

Total Capital Investment (TCI) = DC + IC 7,395,580

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,395,580

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr 18,687

Supervisor 15% 15% of Operator Costs 2,803

Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr 19,475

Maintenance Materials 100% of maintenance labor costs 19,475

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,368 kW-hr, 6598.9 hr/yr, 93% utilization 335,730

Natural Gas 12.81 $/mscf, 1,915 scfm, 6598.9 hr/yr, 93% utilization 9,035,303

Total Annual Direct Operating Costs 9,431,473

Indirect Operating Costs

Overhead 60% of total labor and material costs 36,264

Administration (2% total capital costs) 2% of total capital costs (TCI) 147,912

Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,956

Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,956

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 698,090 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,030,178

Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,461,651

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 4: -Summary of Utility, Chemical ans Supply Costs

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 369,137 19 0.6 1,367.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 369,137 23 0.6 1,655.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 1367.7

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 6,599

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 412 18,687 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr

Supervisor 15% of Op. NA 2,803 15% of Operator Costs

Maintenance

Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 412 19,475 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 19,475 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.040 $/kwh 1367.7 kW-hr 8,393,252 335,730 $/kwh, 1,368 kW-hr, 6598.9 hr/yr, 93% utilization

Natural Gas 12.81 $/mscf 1,915 scfm 705,149 9,035,303 $/mscf, 1,915 scfm, 6598.9 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

<Table 8>: - Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19 

Twi 129 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 564 Deg F - Temperature of waste gas out of heat recovery

Tfo 315 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 330,907 scfm - Flow of waste gas 

Qaf 1,915 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 332,822 scfm Flue Gas Cost in 1989 $'s $512,611

Current Cost Using CHE Plant Cost Index $611,190

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 9: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering

Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs EPRI Correlation 1998

 Purchased Equipment (A) 2005 22,410,519

 Purchased Equipment Total (B) SCR Only 23,867,203

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 3,976,665

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 70,762,832

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 28,175,324

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,013,819

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 35,189,143

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,633.3 8.7 0.02 35.0 1,598.3 22,017

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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EU042 SCR EU042 SCR 27 of 40
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BART Report - <Appendix A> Emission Control Cost Analysis

Table 9: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,410,519

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,456,684

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 23,867,203

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 3,976,665

Total Plant Cost D A + B + C 30,487,767

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 774,395

Inventory Capital Reagent Vol * $/gal 17,062

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 39,511,225

Retrofit multiplier3 60% of TCI 23,706,735

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

Total Retrofit Capital 63,217,960

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 592,668

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 5,133 kW-hr, 8687.8 hr/yr, 93% utilization 1,658,998

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 548,800

NA NA - 

Ammonia 0.12 $/lb, 503 lb/hr, 8687.8 hr/yr, 93% utilization 489,909

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 3,290,375

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,967,328 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,967,328

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,257,704

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EU042 SCR EU042 SCR 28 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 9: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 3,462 Plant Cap kW A 355,097

Est power platn eff 35% Unc Nox lb/mmB B 0.11 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 k 355,097 Capital Cost $/kW D $63.11 $22,410,519.46 Total SCR Equipment

Uncontrolled Nox t/y 1,633.3 Fixed O&M E $147,909.43

Annual Operating Hrs 8000 Variable O&M F $598,961.39

Uncontrolled Nox lb/mm 0.108 Ann Cap Factor G 0.82

Heat Input mmB H 6,000

SCR Capital Cost

SCR Capital Cost per EPRI Method

Duty 3,462 MMBtu/hr Catalyst Area 1,670 ft2 664 f (h SCR)

Q flue gas 1,603,311 acfm Rx Area 1,921 -8 f (h NH3)

NOx Cont Eff 80% (as faction) Rx Height 43.8 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.11 lb/MMBtu n layer 24 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 25.5 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 25 layers 29,505,985 f (vol catalyst)

Temperature 120.719008 Deg F h SCR 139 ft f (h SCR)

Catalyst Volume 122,942 ft3 New/Retrofit R N or R 

Electrical Use

Duty 3,462 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 5,133.3

NOx in 0.11 lb/MMBtu

n catalyst layers 25 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 5133.3

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

146 lb/hr Neat 67.2 gal/hr

29% solution Volume 14 day inventory 22,568 gal $17,062 Inventory Cost

503 lb/hr

Design Basis Baseline Em Baseline EmisMax Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.02

Nitrous Oxide 1633.31 0.108 375.17

Actual dscf/MMBtu 85,334

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 3,462 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8687.8 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs -

Maintenance 0.00

Maintenance Total 1.5 % of Total Capital Investment 592,668 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Rep 0.00

Electricity 0.040 $/kwh 5133.3 kW-hr 41,474,951 1,658,998 $/kwh, 5,133 kW-hr, 8687.8 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 140.0 mw 112 548,800 Catalyst Replacement

7 Ammonia 0.12 $/lb 503 lb/hr 4,062,288 489,909 $/lb, 503 lb/hr, 8687.8 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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EU042 SCR EU042 SCR 29 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 10: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering

Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 726,369

 Purchased Equipment Total (B) 15% of control device cost (A) 835,324

 Installation - Standard Costs 30% of purchased equip cost (B) 250,597

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,450,597

 Total Direct Capital Cost, DC 7,285,921

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 24,884,948

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 10: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 726,369

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 72,637

ND Sales Taxes 0.0% of control device cost (A) 0

Freight 5% of control device cost (A) 36,318

Purchased Equipment Total (B) 15% 835,324

Installation

Foundations & supports 8% of purchased equip cost (B) 66,826

Handling & erection 14% of purchased equip cost (B) 116,945

Electrical 4% of purchased equip cost (B) 33,413

Piping 2% of purchased equip cost (B) 16,706

Insulation 1% of purchased equip cost (B) 8,353

Painting 1% of purchased equip cost (B) 8,353

Installation Subtotal Standard Expenses 30% 250,597

Site Preparation, as required Site Specific 1,400,000

Buildings, as required Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Installation Total 6,450,597

Total Direct Capital Cost, DC 7,285,921

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 83,532

Construction & field expenses 5% of purchased equip cost (B) 41,766

Contractor fees 10% of purchased equip cost (B) 83,532

Start-up 2% of purchased equip cost (B) 16,706

Performance test 1% of purchased equip cost (B) 8,353

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,060

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,544,872

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 24,603

Supervisor 15% 15% of Operator Costs 3,690

Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 25,640

Maintenance Materials 100% of maintenance labor costs 256

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization 869,316

Natural Gas 12.81 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization 23,961,443

Total Annual Direct Operating Costs 24,884,948

Indirect Operating Costs

Overhead 60% of total labor and material costs 32,514

Administration (2% total capital costs) 2% of total capital costs (TCI) 150,897

Property tax (1% total capital costs) 1% of total capital costs (TCI) 75,449

Insurance (1% total capital costs) 1% of total capital costs (TCI) 75,449

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 712,183 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 10: -Summary of Utility, Chemical and Supply Costs

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 726,000 19 0.6 2,689.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 726,000 23 0.6 3,256.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2689.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr

Supervisor 15% of Op. NA 3,690 15% of Operator Costs

Maintenance 0%

Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr

Maint Mtls 100% % of Maintenance Labor NA 256 1% of Maintenance Labor

Utilities, Supplies, Rep 0%

Electricity 0.04 $/kwh 2689.8 kW-hr 21,732,896 869,316 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization

Natural Gas 12.81 $/mscf 3,858 scfm 1,870,042 23,961,443 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 10: -Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19 

Twi 121 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 561 Deg F - Temperature of waste gas out of heat recovery

Tfo 310 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 660,092 scfm - Flow of waste gas 

Qaf 3,858 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 663,950 scfm Flue Gas Cost in 1989 $'s $609,213

Current Cost Using CHE Plant Cost Index $726,369

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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BART Report - <Appendix A> Emission Control Cost Analysis

Table 11: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering

Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs EPRI Correlation 1998

 Purchased Equipment (A) 2005 23,080,776

 Purchased Equipment Total (B) SCR Only 24,581,027

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 4,083,739

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 72,222,298

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 30,618,541

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,151,583

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 37,770,123

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 8,164.5 46.7 0.12 188.7 7,975.8 4,736

Notes & Assumptions

1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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EU042 SCR NG EU042 SCR NG 34 of 40
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BART Report - <Appendix A> Emission Control Cost Analysis

Table 11: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,080,776

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,500,250

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 24,581,027

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 4,083,739

Total Plant Cost D A + B + C 31,308,664

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 790,813

Inventory Capital Reagent Vol * $/gal 91,914

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 40,423,391

Retrofit multiplier3 60% of TCI 24,254,035

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

Total Retrofit Capital 64,677,426

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 606,351

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 6,001 kW-hr, 8687.8 hr/yr, 93% utilization 1,939,332

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 548,800

NA NA - 

Ammonia 0.12 $/lb, 2,708 lb/hr, 8687.8 hr/yr, 93% utilization 2,639,110

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 5,733,593

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,105,091 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,105,091

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,838,684

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EU042 SCR NG EU042 SCR NG 35 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 11: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 3,462 Plant Cap kW A 355,097

Est power platn eff 35% Unc Nox lb/mmB B 0.58 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 k 355,097 Capital Cost $/kW D $65.00 $23,080,776.17 Total SCR Equipment

Uncontrolled Nox t/y 8,164.5 Fixed O&M E $152,333.12

Annual Operating Hrs 8000 Variable O&M F $626,908.01

Uncontrolled Nox lb/mm 0.584 Ann Cap Factor G 0.82

Heat Input mmB H 6,000

SCR Capital Cost

SCR Capital Cost per EPRI Method

Duty 3,462 MMBtu/hr Catalyst Area 1,670 ft2 767 f (h SCR)

Q flue gas 1,603,311 acfm Rx Area 1,921 -8 f (h NH3)

NOx Cont Eff 80% (as faction) Rx Height 43.8 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.58 lb/MMBtu n layer 28 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 29.8 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 29 layers 34,578,438 f (vol catalyst)

Temperature 120.719008 Deg F h SCR 156 ft f (h SCR)

Catalyst Volume 144,077 ft3 New/Retrofit R N or R 

Electrical Use

Duty 3,462 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 6,000.7

NOx in 0.58 lb/MMBtu

n catalyst layers 29 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 6000.7

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

785 lb/hr Neat 361.8 gal/hr

29% solution Volume 14 day inventory 121,571 gal $91,914 Inventory Cost

2708 lb/hr

Design Basis Baseline Em Baseline EmisMax Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.12

Nitrous Oxide 1633.31 0.584 375.17

Actual dscf/MMBtu 85,334

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 3,462 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8687.8 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs -

Maintenance 0.00

Maintenance Total 1.5 % of Total Capital Investment 606,351 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Rep 0.00

Electricity 0.040 $/kwh 6000.7 kW-hr 48,483,290 1,939,332 $/kwh, 6,001 kW-hr, 8687.8 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 140.0 mw 112 548,800 Catalyst Replacement

7 Ammonia 0.12 $/lb 2708 lb/hr 21,883,299 2,639,110 $/lb, 2,708 lb/hr, 8687.8 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xls

EU042 SCR NG EU042 SCR NG 36 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 12: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering

Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F

Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 726,369

 Purchased Equipment Total (B) 15% of control device cost (A) 835,324

 Installation - Standard Costs 30% of purchased equip cost (B) 250,597

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,450,597

 Total Direct Capital Cost, DC 7,285,921

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 24,884,948

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xls

EU042 Reheat NG EU042 Reheat NG 37 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 12: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 726,369

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 72,637

ND Sales Taxes 0.0% of control device cost (A) 0

Freight 5% of control device cost (A) 36,318

Purchased Equipment Total (B) 15% 835,324

Installation

Foundations & supports 8% of purchased equip cost (B) 66,826

Handling & erection 14% of purchased equip cost (B) 116,945

Electrical 4% of purchased equip cost (B) 33,413

Piping 2% of purchased equip cost (B) 16,706

Insulation 1% of purchased equip cost (B) 8,353

Painting 1% of purchased equip cost (B) 8,353

Installation Subtotal Standard Expenses 30% 250,597

Site Preparation, as required Site Specific 1,400,000

Buildings, as required Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Installation Total 6,450,597

Total Direct Capital Cost, DC 7,285,921

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 83,532

Construction & field expenses 5% of purchased equip cost (B) 41,766

Contractor fees 10% of purchased equip cost (B) 83,532

Start-up 2% of purchased equip cost (B) 16,706

Performance test 1% of purchased equip cost (B) 8,353

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,060

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,544,872

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 24,603

Supervisor 15% 15% of Operator Costs 3,690

Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 25,640

Maintenance Materials 100% of maintenance labor costs 256

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization 869,316

Natural Gas 12.81 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization 23,961,443

Total Annual Direct Operating Costs 24,884,948

Indirect Operating Costs

Overhead 60% of total labor and material costs 32,514

Administration (2% total capital costs) 2% of total capital costs (TCI) 150,897

Property tax (1% total capital costs) 1% of total capital costs (TCI) 75,449

Insurance (1% total capital costs) 1% of total capital costs (TCI) 75,449

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 712,183 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xls

EU042 Reheat NG EU042 Reheat NG 38 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 12: -Summary of Utility, Chemical and Supply Costs

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 726,000 19 0.6 2,689.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 726,000 23 0.6 3,256.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2689.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,688

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr

Supervisor 15% of Op. NA 3,690 15% of Operator Costs

Maintenance 0%

Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr

Maint Mtls 100% % of Maintenance Labor NA 256 1% of Maintenance Labor

Utilities, Supplies, Rep 0%

Electricity 0.04 $/kwh 2689.8 kW-hr 21,732,896 869,316 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization

Natural Gas 12.81 $/mscf 3,858 scfm 1,870,042 23,961,443 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xls

EU042 Reheat NG EU042 Reheat NG 39 of 40
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Appendix A> Emission Control Cost Analysis

Table 12: -Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19 

Twi 121 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 561 Deg F - Temperature of waste gas out of heat recovery

Tfo 310 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 660,092 scfm - Flow of waste gas 

Qaf 3,858 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 663,950 scfm Flue Gas Cost in 1989 $'s $609,213

Current Cost Using CHE Plant Cost Index $726,369

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xls

EU042 Reheat NG EU042 Reheat NG 40 of 40
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

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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
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 is 

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 United Taconite 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. 
De minimis Modeling 

As a part of the streamlined BART approach, a method for removing insignificant sources from further 

BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold 

would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis. 

For this facility, five sources were modeled, SV099, SV107, SV108, SV109, and SV110. The maximum 

98th percentile modeled impact for these sources was 0.05 dV, meeting the required de minimis threshold 

of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis

modeling is in the table below. 

Modeled 98th Percentile Impact 

2002 2003 2004 2002-2004 Maximum 

BWCA 0.04 0.05 0.04 0.04 0.05 

Voyageurs 0.03 0.03 0.03 0.03 0.03 

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. 
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UTAC Aerial Photo
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed without the full text not 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? Comments Bas

Combustion Controls

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

achieve complete burnout and to 

than NOx

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

therefore reduces flame tempera

3 Low-NOx Burners Y Y

Y 

(preheat 

burners)

Y 

(preheat 

burners)

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 --- Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel i

5 Low Excess Air Y N --- --- Need high O2 for process requirements and product quality Reduces oxygen content in flue g

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

lean zones

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

Combustion is staged by diverting lower ones or from the center to tfuel-lean zones 

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

Part of the total fuel heat input is 

above the primary (main burners) 

(re-burn zone), where hydrocarboelemental nitrogen

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

electrical demand throught efficie

10 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

decrease amount of fuel required 

11 Coal Drying Y N --- --- 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 --- --- --- Check on status of research Reduce flame temperature and e
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed without the full text not 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? Comments Bas

13 Ported Kilns Y Y

Y

(grate-kilns 

only)

N

(Metso says 

no NOx 

improvement)

Applicable to grate kilns. Provides additional oxygen for pe

energy use of the kiln 

14 Combustion Zone Cooling Y N --- --- 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)

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

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

16 Oxygen Enhanced Combustion N --- --- --- Research level A small fraction of the combustio17 Preheat Combustion N --- --- --- Research level

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

18 ROFA-ROTAMIX Y N --- --- 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 --- --- Optimization of combustion20 Parametric Monitoring Y N --- --- Optimization of combustion38 Catalyst Injection (EPS Technologies) N --- --- --- Research Level A combustion catalyst is directly i

delivered to the combustion site, the dynamics of the flame.

Post Combustion Controls

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

reduced by CO, resulting in nitrog

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

including NOx
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed without the full text not 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? Comments Bas

23 Low Temperature Oxidation (LTO) - LoTOx Y N --- --- 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

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 th

catalyst to convert NOx into N2 an

25 Regenerative SCR Y N --- --- Clean side only26 Selective Non-Catalytic Reduction (SNCR) Y N --- --- Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat Urea or ammonia-based chemica

convert NO to molecular nitrogen

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

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

Use of water, hydroxide and carbsolutions, molten alkali carbonatenitrogen.

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

Gas stream is sent through the re

direct fired oxidizer where polluta

destroyed.

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

Catalytic reduction of NOx in the 

catalytic oxidation of SO2 to SO3. 

passes through a novel glass-tub

hydrated to H2SO4 vapor and the

sulfuric acid (H2SO4).

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

ammonia injection upstream of a (SCR) catalyst incorporated in the 
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed without the full text not 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? Comments Bas

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

conversion of sulfur and nitrogen easily collected by conventional m

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

Utilizes a reactor in which SO2, N

dioxide (NO2), sulfuric acid, and m

thermal plasma.On recent project, the vender waapplications.

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 --- --- --- Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with co

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

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

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

Gas stream is passed through a fPollutants are adsorbed and degthe products carbon dioxide and w

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

Gas stream is passed through a fdeveloped, 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.htm
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed without the full text not 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? Comments Bas

2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Taconite BART Analysis

SO2 Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconite 

distributed without the full text of not 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?

Comments Basi

1 Wet Scrubbing (High Efficiency) Y Y Y Y Absorption and reaction using an alkali

2 Wet Scrubbing (Low Efficiency) Y Y Y Y Absorption and reaction using an alkali

3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y Suspended particles are separated from 

collected in hoppers

4 Dry sorbent injection Y Y Y N

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

particles are collected with a fabric filte

5 Spray Dryer Absorption (SDA) Y Y Y N Lime slurry is sprayed into an absorptio

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Natural gas is base case Use a fuel with lower sulfur content.

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

throught efficiency projects.

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

decrease amount of fuel required to ma

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

to be burned. Specific energy efficienc

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

Gas stream passes through a packed besupports the growth of active bacterial biodegraded or biotransformed into innwater, chloride ion in water, sulfate or n

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

An aqueous solution of proprietary diam

countercurrent absorption tower. The ri

giving a byproduct of pure, water satur

to the absorber.

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

Gas stream is passed through a filter baparticle, high-surface area metal oxide removed from the gases by adsorption.
Taconite BART Analysis

SO2 Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconite 

distributed without the full text of not 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?

Comments Basi

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

Dry sorbent injection upstream of the binjection upstream of a zeolitic selectivincorporated in the baghouse to reduce 

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

conversion of sulfur and nitrogen oxidecollected by conventional methods such 

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

Utilizes a reactor in which SO2, NOx, a

(NO2), sulfuric acid, and mercuric oxid

On recent project, the vender was doing 

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

Uses a regenerable sorbent to simultane

from coal-fired utility and industrial bo

a saleable sulfur by-product (liquid SO

NOx is converted to nitrogen and oxyg

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

SO2 in the flue gas reacts with copper o

alumina, to form copper sulfate. Ammoabsorption reactor and a selective catalreduces the nitric oxides in the flue gasis reduced in a regenerator with a reducconcentrated stream of SO2.

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

Catalytic reduction of NOx in the prese

catalytic oxidation of SO2 to SO3. The 

through a novel glass-tube condenser in 

and then condensed to a concentrated l

19 Cold Plasma N --- --- --- 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
Appendix E Clean Air Interstate Rule (CAIR)

Cost-Effective air pollution Controls

Comments

Reference Regulatory Body/Rule SO2 NOx SO2 NOx

BART 100 to 1000 100 to 1000 70 FR 39135BART 281 to 1296 70 FR 39135 Table BART 919 70 FR 39133BART Guidelines dispara

dollars per ton" in cexceed MACT and 

70_FR_25210_CAIR.pdf CAIR 1300 Estimated Margina

BART(proposed rule) 200-1000

BART proposed lis

SO2 control, which lb/MMBtu. Droppeflexibility to require bypasses aren't BABART.

BART(proposed rule)

0.2 lb/MMBtu for N

Recognizes that so

get this level. For t

cost vs. visibility va

CAIR(using IPM) 1000 1500CAIR ( 2009 in 1999$) 900 2400CAIR ( 2015 in 1999$) 1800 3000CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100

This was modeled 

Retrofitting Updatinmarginal values.

Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000

LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000

954-1134 was rule

for SO2. This did cSections XVII to XI

WRAP 3000EPA - Referenced by Wrap

References EPA-6

<$500/ton, Moderaover $3000/ton

WRAP_Trading_program_methodology.pdf

Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)

MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdf

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xls