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Northshore Mining Company Analysis of Best Available Retrofit 

Technology (BART) 

Table of Contents 

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

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

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

2.B BART Determinations ................................................................................................................4

3. Streamlined BART Analysis ................................................................................................................9

3.A Indurating Furnaces ....................................................................................................................9

3.B PM-Only Taconite MACT Emission Units ................................................................................9

3.C Sources of fugitive PM that are subject to MACT standards....................................................10

3.D Non-MACT Units and Fugitive Sources (PM only).................................................................10

3.E Other Combustion Units ...........................................................................................................10

3.F Visibility Impact Modeling for Negligible Impacts..................................................................11

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ...............................................13

4.A MPCA Subject-to-BART Modeling .........................................................................................13

4.B Facility Baseline Modeling.......................................................................................................14

4.C Facility Baseline Modeling Results ..........................................................................................19

5. Full BART Analysis for BART Eligible Emission Units...................................................................21

5.A Indurating Furnace....................................................................................................................21

5.A.i Sulfur Dioxide Controls............................................................................................... 22

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 22

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 22

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

Technologies................................................................................................ 27

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 28

5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 30

5.A.ii Nitrogen Oxide Controls.............................................................................................. 30

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 31

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 31

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

Technologies................................................................................................ 43

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 44

5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 45

5.B External Combustion Sources...................................................................................................47

5.B.i Sulfur Dioxide controls................................................................................................ 47

5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 47

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 47
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5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control 

Technologies................................................................................................ 51

5.B.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 51

5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 53

5.B.ii Nitrogen Oxide Controls.............................................................................................. 54

5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 54

5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 54

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

Technologies................................................................................................ 61

5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 62

5.B.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 64

6. Visibility Impacts................................................................................................................................67

6.A Post-BART Modeling Scenarios...............................................................................................67

6.B Post-BART Modeling Results ..................................................................................................67

7. Select BART.......................................................................................................................................71

List of Tables 

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

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

Table 4-2 Baseline Visibility Modeling Results..........................................................................20

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

Technical Feasibility ..................................................................................................27

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness.........................................27

Table 5-3 Indurating Furnace SO2 Control Cost Summary ..........................................................29

Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility ..................................................................................................43

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness ........................................43

Table 5-6 Indurating Furnace NOx Control Cost Summary .........................................................44

Table 5-7 Backup Process Boiler SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility ..................................................................................................51

Table 5-8 Backup Process Boiler SO2 Control Technology Effectiveness ...................................51

Table 5-9 Backup Process Boiler SO2 Control Cost Summary....................................................52

Table 5-10 Backup Process Boiler NOx Control Technology – Availability, Applicability and 

Technical Feasibility ..................................................................................................61

Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness ..................................61

Table 5-12 Backup Process Boiler NOx Control Cost Summary....................................................62

Table 5-13 Backup Process Boiler NOx Control Technology – Other Impacts Assessment............63

Table 5-14 Backup Process Boiler NOx Post- BART Emission Rates for Emission Unit EU003 and 

EU004........................................................................................................................64

Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios .............................................65

Table 5-16 Backup process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data ..66
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Table 5-17 Backup Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling 

Results .......................................................................................................................66

Table 5-18 Backup Process Boiler Post-BART NOx Modeling Scenarios – Comparison of 

Visibility Modeling Results to Baseline Modeling Results..........................................66

Table 6-1 Post-BART Modeling Scenarios .................................................................................69

Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................70

Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to 

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

List of Figures 

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

List of Appendices 

Appendix A Control Cost Analysis Spreadsheets 

Appendix B Changes to MPCA BART Modeling Protocol 

Appendix C Visibility Impacts Modeling Report 

Appendix D Applicable and Available Retrofit Technologies for Indurating Furnaces 

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

Appendix F Applicable and Available Retrofit Technologies for Process Boilers 
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1. Executive Summary 

Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located 

at Babbit and a taconite processing plant located at Silver Bay. This report describes the background

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

NMC for its taconite processing plant. 

Minnesota Pollution Control Agency MPCA identified 36 pieces of equipment at NMC that were 

installed within the time window (1962-1977) that makes them subject to BART. The equipment 

includes two straight-grate indurating furnace lines (Furnaces 11 and 12) and two backup steam 

process boilers ( Process Boilers 1 and 2) that use natural gas and oil for fuel, as well material 

handling and/or storage units for ore, product, and additives. Preliminary visibility modeling 

conducted by the Minnesota Pollution Control Agency MPCA found that air emissions from NMC 

“cause or contribute to visibility impairment” in a federally protected Class I area, therefore making

the facility subject to BART. 

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

propose BART. The existing pollution control equipment on the furnace lines includes a wet walled 

electrostatic precipitator (WWESP) designed to control of particulate matter (PM) and sulfur dioxide 

(SO2). A dispersion modeling sequence of CALMET, CALPUFF, and CALPOST was used to assess 

the visibility impacts of the baseline emissions and after the application of candidate BART controls. 

Visibility impacts were evaluated in the selection of BART. Other criteria that the BART rules 

require to be considered include the availability of technology, costs of compliance, energy and 

environmental impacts of compliance, existing pollution control technology in use at the source, and 

the remaining useful life of the source. 

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

• SO2 emissions will be controlled by the existing WWESPs on the taconite furnaces. The 

process boilers will have no additional controls. NOx emissions will be controlled by good 

combustion practices for the taconite mining process for the furnaces and process boilers. 
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• PM emissions at the furnaces will be controlled as prescribed by the taconite maximum 

achievable control technology (MACT) standard1. The existing WWESPs adequately control 

PM emissions from the furnaces to meet the MACT standard. The process boilers will have 

no additional controls. 

The CALPUFF model is conservative, resulting in an over prediction of impacts2. This modeled 

high impact from the BART eligible sources is 1.1 deciviews (dV), slightly above perceptible levels 

of one to two dV. The modeling also shows that these sources do affect Class I area visibility at less 

than 10 percent of the time based on the model predicting an impact greater than 0.5dV only 34 to 38 

days per year. Real impacts to the Class I areas from NMC are expected to be even less than these 

modeled impacts. NMC will continue to evaluate energy efficiency projects and other mechanisms 

to reduce their visibility impairment pollutants emission rates. 

 

1

 40 CFR 63 Subpart RRRRR-and DDDDD NESHAPS: Taconite Iron Ore Processing and Industrial Commercial 

and Institutional Boilers and Process Heaters 

2

 Federal Register 70, 128 (July 6, 2005): 39123 
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2. Introduction 

Northshore Mining Company (NMC) is located in northern Minnesota, with mining facilities located 

at Babbit and a taconite processing plant located at Silver Bay.. This report describes the background 

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

NMC for its taconite processing plant. 

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

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

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

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

CFR part 51, in 300 through 309. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

permit amendments. 
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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. Facilities indicated in yellow are 

future facilities.

(Source MPCA BART-Strategy October 4, 2005) 

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

worst days under natural conditions by 20643

. Assuming a uniform rate of progress, the default glide 

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

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

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

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

non-air quality impacts. 

 

3

 See the preamble to the final BART and Regional Haze Rules, 70 FR No. 178, pp. 39104-39172 
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Note that the improvements required under the Regional Haze regulations are different from the 

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

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

measures which state may rely upon in making ‘reasonable progress” towards regional haze 

improvement goals. 

2.A BART Eligibility 

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

must meet the following three conditions: 

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

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

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

plants, sulfur recovery plants, etc.); 

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

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

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

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

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

visibility impairing pollutants such as PM, 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. 
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2.B BART Determinations 

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

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

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

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

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

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

impacts.4 The five steps of a BART analysis are: 

Step 1 - Identify all Available Retrofit Control Technologies 

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

generally available for each applicable emission unit. Available retrofit control 

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

Determinations Under the Regional Haze Rule) as follows: 

Available retrofit technologies are those air pollution control technologies 

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

regulated pollutant under evaluation. Air pollution control technologies can 

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

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

are available for BART purposes and must be included as control 

alternatives. The control alternatives can include not only existing controls 

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

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

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

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

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

has not been demonstrated in practice.5

Step 2 - Eliminate Technically Infeasible Options 

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

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

 

4

 40 CFR 51 Appendix Y 

5

 Federal Register 70, No. 128 (July 6, 2005): 39164
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1. Is the control technology “available” to the specific source which is undergoing the 

BART analysis? 

The U.S. EPA states that a control technique is considered “available” to a specific 

source “if it has reached the stage of licensing and commercial availability.6” 

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

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

dissimilar source type.7” 

2. Is the control technology an “applicable technology” for the specific source which 

is undergoing the BART analysis? 

In general, a commercially available control technology, as defined in question 1, 

“will be presumed applicable if it has been used on the same or a similar source 

type.8” If a control technology has not been demonstrated on a same or a similar 

source type, the technical feasibility is determined by “examining the physical and 

chemical characteristics of the pollutant-bearing stream and comparing them to the 

gas stream characteristics of the source types to which the technology has been 

applied previously.9” 

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

not technically feasible? 

This question addresses specific circumstances that “preclude its application to a 

particular emission unit.” This demonstration typically includes an “evaluation of 

the characteristics of the pollutant-bearing gas stream and the capabilities of the 

technology10.” 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 analysis11. 

 

6

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

7

 IBID 

8

 IBID 

9

 IBID 

10 IBID 

11 IBID 
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It is also important to note that vendor guarantees can provide an indication of 

technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone 

to be sufficient justification that a control option will work.” Conversely, the U.S. 

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

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

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

analysis and the information from vendor guarantees12. 

Step 3 - Evaluate Control Effectiveness 

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

expected emission rate (post BART) as compared to the emission rate before addition 

of controls (pre-BART) for the pollutant of concern. 

Step 4 - Evaluate Impacts and Document Results 

In the fourth step, an engineering analysis documents the impacts of each remaining 

control technology option. The economic analysis compares dollar per ton of pollutant 

removed for each technology. In addition it includes incremental dollar per ton cost 

analysis to illustrate the economic effectiveness of one technology in relation to the 

others. Finally, Step Four includes an assessment of energy impacts and other non-air 

quality environmental impacts. 

Economic impacts were analyzed using the procedures found in the U.S. EPA Air 

Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost 

estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air 

Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model 

version 7.5 were used. Vendor cost estimates for this project were used when 

applicable. The source of the control equipment cost data are noted in each of the 

control cost analysis worksheets as found in Appendix A. 

Step 5 - Evaluate Visibility Impacts 

The fifth step requires a modeling analysis conducted with U.S. EPA -approved models 

such as CALPUFF. The modeling protocol13, including receptor grid, meteorological 

data, and other factors used for this part of the analysis were provided by the Minnesota 

 

12 IBID 

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

BART in the State of Minnesota. 
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Pollution Control Agency. The model outputs, including the 98th percentile dV value 

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

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

improvement that can be reasonably attributed to each technology. 

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

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

controls should be considered, and specifically states: 

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

of controls would affect the viability of plant operations. 

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

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

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

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

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

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

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

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

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

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

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

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

information is available.14

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

the BART requirements and requires compliance within a reasonable period of time15.” 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 basis16.” which could include the incorporation of 

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

 

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

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

16 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 
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64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If 

technological or economic limitations make measurement methodology for an emission unit 

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

standard, or combination of these types of standards

17.” 

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

the Minnesota SIP. 

 

17 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 
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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 analyses18. The streamlined approach will allow both states and the 

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

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

the results of the streamlined approach. 

3.A Indurating Furnaces 

The indurating furnaces are sources of three visibility impairing pollutants: NOx, SO2, and PM. The 

indurating furnaces is subject to the taconite MACT standard19 for the PM emissions. MPCA’s 

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

represent BART level of control for those visibility impairing pollutants addressed by the MACT 

standard unless there are new technologies subsequent to the MACT standard, which would lead to 

cost-effective increases in the level of control.” [Attachment 2, March 2006, page 2]. Since the 

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

analysis is up-to-date. As a result, BART will be presumed to be equivalent to MACT for PM and no 

further analysis will be required to establish BART for PM for this source. 

A full BART analysis will be conducted for 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. 

 

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

19 40 CFR 63 Subpart 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). No equipment that emits fugitive PM has been 

identified at NMC as potentially BART-eligible equipment, so these sources are not required to be 

addressed. Therefore, no further analysis will be required to establish BART for these sources. 

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

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

They include units such as: 

• Bentonite storage and handling 

• Additive storage and handling 

• Concentrate storage and handling 

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

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

BART. 

The point source emission units are controlled by baghouses, which is a technology that achieves a 

high level of control for PM. Since these units already have control equipment for PM emissions, 

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

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

impact on visibility improvement in Class I areas. Existing controls will be considered BART 

consistent with direction from MPCA in the May 18, 2006 meeting. 

No equipment that emits fugitive PM has been identified at NMC as potentially BART-eligible 

equipment, so these sources are not required to be addressed. No further analysis will be required to 

establish BART for these sources. 

3.E Other Combustion Units 

The combustion units are sources of three visibility impairing pollutants: NOx, SO2, and PM. 
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NMC facility has two process boilers that are subject to the boiler MACT20. Since the boiler MACT 

standards were established recently and become effective in 2007, the technology analysis is up-todate. For the units subject to the boiler MACT standard, BART will be presumed to be equivalent to 

MACT for PM according to MPCA guidance. A full BART analysis will be conducted for NOx and 

SO2. 

The Northshore facility also has a powerhouse which will require a full BART analysis. That 

analysis is provided in a separate report. 

3.F Visibility Impact Modeling for Negligible Impacts 

The streamlined BART approach allows for a screening modeling demonstration of negligible 

visibility impacts for fugitive sources and combustion units other than indurating furnaces and 

process boilers. NMC does not have any potentially BART eligible sources that require screening 

modeling. 

 

20 40 CFR 63 Subpart DDDDD-NESHAPS: ICI Boilers and Process Heaters 
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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis 

Emission 

Unit # Emission Unit Description 

VisibilityImpairing 

Pollutant 

Applicable 

Limit1 

gr/dscf 

Maximum Daily 

lbs/day2

3.A Indurating Furnaces 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 104 Furnace 11 Waste Gas PM 0.01 255 

EU 104 Furnace 11 Waste Gas PM 0.01 255 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 114 Furnace 12 Waste Gas PM 0.01 255 

EU 114 Furnace 12 Waste Gas PM 0.01 255 

3.B PM-Only Taconite MACT Emission Units 

EU 008 East Car Dump PM 0.008 32 

EU 010 Fine Crusher Bin Storage – East PM 0.008 45 

EU 016 Crushed Ore Conveyors – East PM 0.008 12 

EU 017 Fine Crushing Line 101 PM 0.008 8 

EU 018 Fine Crushing Line 102 PM 0.008 8 

EU 019 Fine Crushing Line 103 PM 0.008 8 

EU 020 Fine Crushing Line 104 PM 0.008 8 

EU 031 Concentrator Transfer Bin – East PM 0.008 8 

EU 044 Concentrator Bin - Section 101 PM 0.008 18 

EU 045 Concentrator Bin - Section 102 PM 0.008 18 

EU 046 Concentrator Bin - Section 103 PM 0.008 18 

EU 047 Concentrator Bin - Section 104 PM 0.008 18 

EU 048 Concentrator Bin - Section 105 PM 0.008 18 

EU 049 Concentrator Bin - Section 106 PM 0.008 18 

EU 050 Concentrator Bin - Section 107 PM 0.008 18 

EU 051 Concentrator Bin - Section 108 PM 0.008 18 

EU 052 Concentrator Bin - Section 109 PM 0.008 18 

EU 053 Concentrator Bin - Section 110 PM 0.008 18 

EU 120 Furnace 11 Discharge PM 0.008 95 

EU 121 Furnace 12 Discharge PM 0.008 95 

EU 122 Furnace 11 Screening PM 0.008 95 

EU 124 Furnace 12 Screening PM 0.008 95 

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

EU 077 Furnace 11 Day Bin Collector PM 0.01 4 

EU 078 Furnace 11 Air Slide Collector PM 0.01 4 

EU 079 Furnace 12 Day Bin Collector PM 0.01 4 

EU 080 Furnace 12 Air Slide Collector PM 0.01 4 

EU 081 East Pelletizer Bentonite Storage - Bin 3,4 PM 0.01 4 

EU 082 East Pelletizer Bentonite Storage - Bin 5,6 PM 0.01 4 

EU 083 Bentonite Unloading Collector PM 0.01 4 

EU 084 Supplemental Bentonite Unloading Collector PM 0.01 10 

3.E Other Combustion Units lb/mmBtu 

EU 003 Process Boiler #1 PM 0.6 45 

EU 004 Process Boiler #2 PM 0.6 45 

1

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

provisions, as presented in the MACT regulation, effective October 26, 2006. 

2

Based on baseline flow rates. 
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4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance21, 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 

alternatives22 (REFERNECE FED. GUIDANCE PREAMBLE pages 39127 – 39129 as appropriate). 

However it is important to note that CALPUFF is a conservative model that over estimates real 

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

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

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

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

Additionally, the interactions between the visibility impairing pollutants 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 estimatedetermine the visibility improvement resulting from the retrofit technology, the 

source must first be modeled at baseline conditions. Per MPCA guidance, the baseline, or pre-BART 

conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect

the maximum 24-hour actual emissions23

. 

4.A MPCA Subject-to-BART Modeling 

In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA 

completed modeling of the BART-eligible emission units at various facilities in Minnesota in 

accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF, 

as detailed in the “Best Available Retrofit Technology (BART) Modeling Protocol to Determine 

Sources Subject-to-BART in the State of Minnesota,” finalized in March 2006. The modeling by 

MPCA was conducted using emission rate information submitted by the facility. The emissions were 

 

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

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

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

Subject-to-BART in the State of Minnesota. Page 8. 
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reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions 

during a 24-hour period under steady-state operating conditions during periods of high capacity 

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

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

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

this facility is subject-to-BART. 

4.B Facility Baseline Modeling 

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

On behalf of NMC and the other Minnesota taconite facilities, Barr Engineering proposed changes to 

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

Appendix B. 

In addition, the maximum 24-hour emission rates were re-evaluated internally within NMC to 

confirm that the emission rates represent the maximum steady-state operating conditions during 

periods of high capacity utilization. The maximum 24-hour emission rates were not adjusted. 

The facility baseline data is summarized in the Table 4-1. The full modeling analysis is presented in 

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

EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

003 

Process 

Boiler #1 402 279 45 SV003 631471.5 5238482.8 131 

EU 

004 

Process 

Boiler #2 402 279 45 SV003 631471.5 5238482.8 131 

EU 

008 

East Car 

Dump NA NA NA NA 32 SV008 631224.7 5238953.7 83 

EU 

010 

Fine 

Crusher 

Bin 

Storage - 

East 

NA NA NA NA 45 SV010 631316.0 5238925.9 101 

EU 

016 

Crushed 

Ore 

Conveyo

rs - East 

NA NA NA NA 12 SV016 631314.1 5238884.6 69 

EU 

017 

Fine 

Crushing 

Line 101 

NA NA NA NA 8 SV017 631322.8 5238896.8 69 

EU 

018 

Fine 

Crushing 

Line 102 

NA NA NA NA 8 SV018 631328.6 5238905.9 69 

EU 

019 

Fine 

Crushing 

Line 103 

NA NA NA NA 8 SV019 631334.4 5238915.1 69 

EU 

020 

Fine 

Crushing 

Line 104 

NA NA NA NA 8 SV020 631341.2 5238924.2 69 

EU 

031 

Concentr

ator 

Transfer 

Bin - 

East 

NA NA NA NA 8 SV031 631455.6 5238785.1 83 

EU 

044 

Concentrator Bin - 

Section 

101 

NA NA NA NA 18 SV044 631473.1 5238808.5 93 

EU 

045 

Concentrator Bin - 

Section 

102 

NA NA NA NA 18 SV045 631486.7 5238828.7 93 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

046 

Concentrator Bin - 

Section 

103 

NA NA NA NA 18 SV046 631501.3 5238849.0 93 

EU 

047 

Concentrator Bin - 

Section 

104 

NA NA NA NA 18 SV047 631514.8 5238870.3 93 

EU 

048 

Concentrator Bin - 

Section 

105 

NA NA NA NA 18 SV048 631529.4 5238890.7 93 

EU 

049 

Concentrator Bin - 

Section 

106 

NA NA NA NA 18 SV049 631544.0 5238911.0 93 

EU 

050 

Concentrator Bin - 

Section 

107 

NA NA NA NA 18 SV050 631557.6 5238932.3 93 

EU 

051 

Concentrator Bin - 

Section 

108 

NA NA NA NA 18 SV051 631572.1 5238952.6 93 

EU 

052 

Concentrator Bin - 

Section 

109 

NA NA NA NA 18 SV276 631590.6 5238980.0 93 

EU 

053 

Concentrator Bin - 

Section 

110 

NA NA NA NA 18 SV053 631605.2 5239000.3 93 

EU 

077 

Furnace 

11 Day 

Bin 

Collector 

NA NA NA NA 4 SV077 631274.7 5238341.3 97 

EU 

078 

Furnace 

11 Air 

Slide 

Collector 

NA NA NA NA 4 SV078 631315.5 5238399.2 97 

EU 

079 

Furnace 

12 Day 

Bin 

Collector 

NA NA NA NA 4 SV079 631276.6 5238344.4 97 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

080 

Furnace 

12 Air 

Slide 

Collector 

NA NA NA NA 4 SV080 631318.4 5238402.2 97 

EU 

081 

East 

Pelletizer 

Bentonite 

Storage - 

Bin 3,4 

NA NA NA NA 4 SV081 631311.2 5238408.2 129 

EU 

082 

East 

Pelletizer 

Bentonite 

Storage - 

Bin 5,6 

NA NA NA NA 4 SV082 631318.0 5238419.3 130 

EU 

083 

Bentonite 

Unloadin

g 

Collector 

NA NA NA NA 4 SV083 631320.9 5238422.4 127 

EU 

084 

Supplem

ental 

Bentonite 

Unloadin

g 

Collector 

NA NA NA NA 10 SV084 631331.9 5238426.5 117 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV101 631339.1 5238341.2 121 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV102 631344.3 5238338.3 121 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV103 631348.4 5238335.3 121 

EU 

104 

Furnace 

11 Waste 

Gas 

142 1498 255 SV105 631343.4 5238298.9 134 

EU 

104 

Furnace 

11 Waste 

Gas 

142 1498 255 SV104 631334.2 5238298.9 134 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV111 631361.5 5238372.7 121 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV112 631365.6 5238369.7 121 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV113 631370.7 5238366.8 121 

EU 

114 

Furnace 

12 Waste 

Gas 

142 1498 255 SV114 631354.5 5238331.4 134 

EU 

114 

Furnace 

12 Waste 

Gas 

142 1498 255 SV115 631362.7 5238325.5 134 

EU 

120 

Furnace 

11 

Discharg

e 

NA NA NA NA 95 SV120 631383.5 5238300.6 91 

EU 

121 

Furnace 

12 

Discharg

e 

NA NA NA NA 95 SV121 631405.9 5238332.1 91 

EU 

122 

Furnace 

11 

Screenin

g 

NA NA NA NA 95 SV122 631387.6 5238297.7 91 

EU 

124 

Furnace 

12 

Screenin

g 

NA NA NA NA 95 SV124 631380.9 5238282.5 91 
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4.C Facility Baseline Modeling Results 

The Minnesota BART modeling protocol24 describes the CALPUFF model inputs, including the 

meteorological data set and background atmospheric ammonia and ozone concentrations, along with 

the functions of CALPOST post processing.. The CALPOST output files provide the following two 

methods to assess the expected post-BART visibility improvement: 

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

identifies the Minnesota facilities that are subject to BART25, 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 However, the results also 

indicate that the highest modeled impact may not exceed human perceptibility which is on the order 

of one to two dV. In addition, the modeling shows that these emission sources cause or contribute to 

visibility impairment less than 10 % of the time, based on the modeling results predicting 34 to 38 

days annually above 0.5dV. The results of this modeling are also utilized in the post-BART modeling 

analysis in section 6 of this document. 

The full modeling analysis is presented in Appendix C. 

 

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

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

25 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources 

Subject-to-BART in the State of Minnesota. 
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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 1.1 34 1.1 34 1.3 38 1.1 106 
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5. Full BART Analysis for BART Eligible Emission 

Units 

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

5.A Indurating Furnace 

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

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

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

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

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

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

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

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

and product quality in all parts of the furnace. NMC uses a straight grate furnace, in which pellets 

move through the entire furnace on a traveling grate. The pellet hardening and oxidation section of 

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

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

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

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

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

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

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

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

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

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

NMC process has two straight-grate furnaces, Line 11 and Line 12 that are subject to BART. Line 

11 and 12 are permitted to burn natural gas and fuel oil. Both line’s emissions are controlled by wet 

walled electrostatic precipitators (WWESP) using caustic reagent. The existing WWESP already 

provides excellent control and removal of PM and SO2. 

Emissions of SO2 result from low amounts of sulfur present in the ore and potentially from fuel oil 

use. Stack testing using natural gas fuel has demonstrated the WWESP effectively removes SO2 to 
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one to two parts per million in the exhaust from the WWESPs. A recent BACT analysis for a similar 

furnace at NMC established an emissions limit of 10 parts per million SO2 using existing WWESPs. 

NOx is controlled through furnace design. The NMC furnaces emit the lowest tons of NOx/long ton 

product of any taconite producer making similar pellets. NMCs furnaces are of an early vintage. 

Furnaces 11 and 12 have numerous burners critically located to supply heat to the various furnace 

sections. The burner layout limits production capability for the size of the furnace. This furnace 

design is not used by any other taconite producer. 

The primary source of SO2 emissions in taconite production is from trace amounts of sulfur in the 

iron concentrate and binding agents present in the green balls. Sulfur is also present in distillate fuel 

oil that is one of the permitted fuels. 

5.A.i Sulfur Dioxide Controls 

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

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

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

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

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

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

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

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

Step 1 identified the available and applicable technologies for 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. 
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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. WWESPs are designed to remove emissions to levels less than 10 parts per million SO2 . 

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. NMC currently employs a WWESP 

designed for removal of particulate matter and SO2. The addition of a secondary 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 polishing WWESP is considered an available 

technology for SO2 reduction for this BART analysis. The existing WWESP already removes SO2 to 

a very low concentration. No other improvements are available to enhance the removal efficiency of 

the existing controls. Installation of a secondary WWESP is carried forward in this analysis. 

Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove 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 

packed-bed 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 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: 
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CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

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

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and 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, WWESPs are currently in place on the furnace exhausts 

and are believed to remove 80 to 95% of the SO2 in the exhaust. Taking into consideration of the 

removal of SO2 from the existing primary WWESP as well as a high efficiency SO2 polishing wet 

scrubber, an overall efficiency of the control train would then be well over 90%. 
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Based on the information contained within this report, a secondary 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 

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

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

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

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

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

content and will not be further evaluated in this report. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where 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. An example of an energy efficiency project could be to preheat incoming make-up air or 

pellet feed. Each project is very dependent upon the fuel usage, process equipment, type of product 

and many other variables. 

Due to the increased price of fuel, the facilities have already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and potentially emission reductions. It would be 

impossible to assign a general potential emission reduction for the energy efficient category. Due to 

the uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that facilities will continue to evaluate and implement energy efficiency 

projects as they arise. 

Alternate Fuels 

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

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

achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels with 

lower sulfur content. NMC has the capability to only burn natural gas and distillate fuel oil in its 

furnaces. Therefore this option is not applicable for SO2 reductions at NMC. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.26 

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

 

26 Federal Register 70, no. 128 (July 6, 2005): 39164
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Coal Processing 

Since NMC does not burn coal in Furnaces 11 and 12, this option is not applicable for SO2 reductions 

at NMC. 

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 WWESPs are 

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

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

Technical Feasibility 

SO2 Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

Secondary Wet Scrubbing (High 

Efficiency) 

Yes Yes Yes 

Secondary Wet Scrubbing (Low 

Efficiency) 

Yes Yes Yes 

Secondary Wet Walled Electrostatic 

Precipitator (WWESP) 

Yes Yes Yes 

Dry sorbent injection Yes Yes No 

Spray Dryer Absorption (SDA) Yes Yes No 

Alternative Fuels Yes No No 

Energy Efficiency Projects Yes Yes No 

Coal Processing Yes No No 

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

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

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

considered a polishing scrubber since a highly effective SO2 control WWESP currently exists. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Secondary Wet Walled Electrostatic Precipitator (WWESP) 80 

Secondary Wet Scrubber 60 
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5.A.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-2 above, the technically feasible control remaining provide varying levels of 

emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental 

impacts to better differentiate as presented below.

Economic Impacts 

Table 5-3 details the expected costs associated with installation of a secondary WWESP after the 

existing WWESP on each stack. Equipment design was based on the maximum 24-hour emissions, 

vendor estimates, and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. 

The cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the 

following equation: 

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

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

EPA models and factors. Operating costs were based on 93% utilization and 8339 operating hours 

per year. Operating costs of consumable materials, such as electricity, water, and chemicals were 

established based on the U.S. EPA control cost manual27 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

Due to space considerations, 60%28 of the total capital investment was included in the costs to 

account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was 

determined the space surrounding the furnaces is congested and the area surrounding the building 

supports vehicle and rail traffic to transport materials to and from the building. Additionally, the 

structural design of the existing building would not support additional equipment on the roof. 

Therefore, the cost estimates provide for additional site-work and construction costs to accommodate 

the new equipment within the facility. A site-specific estimate for site work, foundations, and 

structural steel was added to arrive at the total retrofit installed cost of the control technology. The 

site-specific estimate was based on Barr’s experience with similar projects. See Appendix C for an 

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

 

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

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

Secondary Wet Scrubber 

Furnace 11 Hood 

Exhaust $16,952,864 $2,401,349 $139,872 NA 

Furnace 11 Waste 

Gas $15,859,420 $2,201,975 $384,034 NA 

Furnace 12 Hood 

Exhaust $16,952,864 $2,401,349 $152,149 NA 

Furnace 12 Waste 

Gas $15,859,420 $2,201,975 $417,742 NA 

Secondary Wet Walled Electrostatic Precipitator (WWESP) 

Furnace 11 Hood 

Exhaust $23,617,556 $4,188,875 $182,993 NA 

Furnace 11 Waste 

Gas $21,846,389 $3,799,211 $496,949 NA 

Furnace 12 Hood 

Exhaust $23,617,556 $4,294,171 $204,058 NA 

Furnace 12 Waste 

Gas $21,846,389 $3,764,113 $535,575 NA 

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

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

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

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

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

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

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

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

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

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

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

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

evaluated for visibility improvement, energy and other impacts. 

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

technology as compared to the next most effective alternative. Since none of the secondary SO2

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

Energy and Environmental Impacts 

Because the cost of SO2 controls for the NMC furnaces is so high and does not meet a reasonable 

definition of cost effective technology, these technologies are removed from further consideration in 

this analysis. 

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

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

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

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

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

document. The economic impacts of additional, secondary controls for SO2 are not reasonably cost 

effective, so visibility impacts were not modeled for SO2 controls. Refer to Table 4-2 for a summary 

of the modeled 24-hour maximum emission rates and their computational basis for the existing 

controls for SO2. 

Visibility impacts with NOx controls are presented in section 6. Table 6-1 provides a summary of the 

SO2, NOx, and PM10 emissions for each modeling scenario. 

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 in the furnaces: thermal, fuel and prompt NOx. 

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

combustion. 

 

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

Processing Plant, Fairmont, MN Permit 09100059-002. 
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• 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. 

The NMC furnaces are first and second generation straight-grate furnaces that were built with lower 

grade steel and less refractory lining than the newer generations. As a result, the furnaces cannot 

survive the higher temperature conditions (both flame temperature and roof air conditions) achieved 

in newer indurating furnaces. Consequently, the ambient air in the ignition and combustion zone is 

much cooler, leading to lower thermal NOx generation. 

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 1, 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 

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 
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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 waste gas in an induration furnace typically has near atmospheric oxygen vs. a boiler 

which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so it can be used as 

a diluent for flame temperature reduction. Taconite waste gas has much higher oxygen 

level; thus use of taconite waste gas for EFGR would be equivalent to adding combustion 

air instead of an inert gas. 

2. The oxidation zone of induration furnaces needs to be above 2,400oF 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. This analysis utilizes the staged fuel design in the cost 

analysis because lower emission rates can be achieved with staged fuel burner than with a staged air 

burner. 

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

fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In 
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the secondary combustion zone, incomplete combustion products formed in the primary zone act as 

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

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

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

preheating section of a straight grate furnace at another taconite plant. If LNB were to be applied in 

the indurating section of the furnace, the reduced flame temperatures associated with LNB would 

adversely affect taconite pellet product quality. Low NOx burners have not been applied to the 

indurating section of any straight grate taconite furnace. 

However, NMC has a completely different combustion design compared to other furnaces. NMCs 

furnace design does not separate the preheat zone from the combustion zone and temperature control 

becomes a controlling variable for operation. Because the temperature in the indurating zone is 

critical to product quality, and because this is dependent on the preheat zone operation, it is not 

practical to control the furnace conditions in the preheat zone adequately to make low NOx burners a 

feasible option at NMC. 

It is also important to note that there are other methods being developed for low NOx burners 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. 

 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 required to operate at high oxygen levels.. 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 
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addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be 

up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. 

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

would adversely affect taconite pellet product quality. 

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

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

Energy Efficiency Projects 

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

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency 

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon 

the fuel usage, process equipment, type of product and so many other variables. 

Due to the increased price of fuel, the facilities have already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and potentially emission reductions. It would be 

impossible to assign a general potential emission reduction for the energy efficient category. Due to 

the uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that facilities will continue to evaluate and implement energy efficiency 

projects as they arise. 

Ported Kilns 

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

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

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

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

bed, and closed when it rotates out of position. 

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

reaction extracts enough heat to offset the heat loss associated with air injection. Air injection 

reduces the overall energy use of the kiln and produces a higher quality taconite pellet. Air injection 

also prevents carry over of the oxidation reaction into the pellet coolers. 

Ported kilns are applicable to grate kilns but not to straight grate indurating furnaces, as are present at 

NMC. Therefore, the ported kilns are not an applicable technology for this facility. 
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Alternate Fuels 

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

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

Reduction of 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 results in lower flame temperature compared to other fuels. 

Switching from natural gas or oil to solid fuel has a potential drawback in that it can exchange one 

visibility impairment pollutant (NOx) for another (SO2). More importantly, the design of the straight 

grate furnaces at NMC does not allow the use of solid fuels. Therefore, this option will not be 

further evaluated in this report. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.30

 

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

fuel usage as the feasibility arises. 

Process Optimization with 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 directly attributed to process fine tuning with the NOx 

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

 

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

31 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4. 
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There are several concerns with utilizing process optimization as an available, applicable and 

technically feasible control option for the taconite industry: 

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

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

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

process is different from a boiler. 

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

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

minimize NOx formation. 

• At some operations, the operating parameters which generally influence the rate of 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 the use of the 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.
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Non-Selective Catalytic Reduction (NSCR) 

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

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

primarily in natural gas combustion applications. 

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

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

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

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

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

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

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

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

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

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

this report. 

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction 

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

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

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

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. 
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Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) 

control process as described below with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

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

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

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

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

recovery. 

The benefits of RSCR are: 

• Its high energy efficiency allows it to be used after 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 other concerns about the technical feasibility and applicability of RSCR on an 

indurating furnace: 

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

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

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

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

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

to the erosive nature of the taconite dust; 

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

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

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

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

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

identify mitigation methods if needed. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

BART analysis. 

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

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

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

technically feasible. 

Low Temperature Oxidation (LTO) 

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

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

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

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

(1,000 ppm NOx). NOx concentrations in taconite exhaust at HTC 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 
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needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

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

generation. 

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

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

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

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

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

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

different type of process. 

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

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

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

For example, the current installations of LoTOx®

 are on sources with flue gas flow rates from 150 –

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

400,000 acfm. Therefore, the application of LTO would be more than an order of magnitude larger 

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

and could be problematic in maintaining the current removal efficiencies. 

In addition, only two of BOC’s LoTOx®

 installations are fully installed and operational applications. 

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

demonstrated to be an effective technology in widespread application. 

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

indurating furnace: 

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

composition of the flue gas from the boilers and process heaters that utilize LTO; 

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

• 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.
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Step 2 Conclusion 

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

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

feasibility as determined in Step 2 is also included in Table 5-4.

Table 5-4 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas 

Recirculation (EFGR) Yes Yes No 

Low- NOx Burners Yes Yes No 

Induced Flue Gas 

Recirculation Burners Yes Yes No 

Energy Efficiency Projects Yes Yes No 

Ported Kilns Yes No No 

Alternative Fuels Yes Yes No 

Process Optimization using 

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

control options as identified in Step 2. 

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

SCR with Conventional Reheat 80% 
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5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-6 details the expected costs associated with installation of Low NOx burners. Capital costs 

were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor 

estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to each 

stack’s flow rate using the 6/10 power law to account for the economy of scale. Operating costs were 

based on 93% utilization and 8339 operating house per year. Operating costs were proportionally 

adjusted to reflect site specific flow rates and pollutant concentrations. 

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

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

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

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

control technology. The site specific estimate was based on Barr’s experience with similar projects. 

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

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

in Appendix A. 

Table 5-6 Indurating Furnace NOx Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual 

Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

Selective Catalytic 

Reduction (SCR) 

With Reheat 

 

Furnace 11 Hood 

Exhaust 

$25,735,488 $11,314,358 $155,784 NA 

Furnace 11 Waste 

Gas 

$23,344,084 $8,274,322 $46,771 NA 

Furnace 12 Hood 

Exhaust 

$25,912,320 $11,387,084 $162,309 NA 

Furnace 12 Waste 

Gas 

$24,026,527 $10,442,659 $61,107 NA 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Energy and Environmental Impacts 

Because the cost of NOx controls for NMC furnaces is so high and does not meet a reasonable 

definition of cost effective technology, this technology is removed from further consideration in this

analysis. 

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

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

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

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

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

document. The economic impacts of controls for NOx are not reasonably cost effective, so visibility 

impacts were not modeled for NOx controls. Refer to Table 4-2 for a summary of the modeled 24-

hour maximum emission rates and their computational basis for the existing controls for NOx. 

 

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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Visibility impacts with SO2 controls are presented in section 6. Table 6-1 provides a summary of the 

SO2, NOx, and PM10 emissions for each modeling scenario, 
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5.B External Combustion Sources 

Two natural gas and fuel oil fired process boilers require BART analysis. These boilers are back-up 

boilers to the main NMC Power House boilers to provide steam required to operate the taconite plant 

during Power House outages. These boilers are only permitted to use gas and distillate oil for fuel. 

5.B.i Sulfur Dioxide controls 

Sulfur in the fuel is the only source of SO2 emissions from these boilers. The boilers only have low 

emissions of SO2 due to the low sulfur content of the permitted fuels. 

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

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

evaluated. 

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

Step 1 identified the available and applicable technologies for 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 

and discusses aspects of those technologies that determine whether or not the technology is 

technically feasible for the process boilers. 

Wet Walled Electrostatic Precipitator (WWESP) 

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

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

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

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

rapping and fall into hoppers for collection and removal. 

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

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

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

absorber. 

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

as SO2 flue gas concentration and fuel used. Based on the definitions contained within this report, a 

WWESP is considered an available technology for SO2 reduction for this BART analysis. 
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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 is used as scrubbing 

agents. 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

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

overall reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

When that 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 is 80% to 90% 

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control 

efficiencies can be achieved when SO2 concentrations are the highest. The process boiler exhaust 

would not have a high SO2 concentration, so the low end of the efficiency range would be expected. 
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Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection involves the injection of a lime or limestone powder into the exhaust gas 

stream. The stream is then passed through a baghouse or ESP to remove the sorbent and entrained 

SO2. The process was developed as a lower cost FGD option because the mixing occurs directly in 

the exhaust gas stream instead of in a separate tower. Depending on the residence time and gas 

stream temperature, sorbent injection control efficiency is approximately 55%. Therefore DSI is 

technically feasible. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where 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. The normal SO2 control efficiency range for SDA is up to 90%. 

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

SO2 reduction for this BART analysis. 

Energy Efficiency Projects 

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

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

emissions. Due to the increased price of fuel, the facilities have already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. It would be impossible to assign a general potential emission reduction for the energy 

efficient category. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that facilities will continue to evaluate and 

implement energy efficiency projects as they arise.
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Alternate Fuels 

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

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

achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels with 

lower sulfur content. NMC has the capability to only burn low sulfur fuels, natural gas and distillate 

oil, in these process boilers. Therefore this option is not applicable to the process boilers. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.33

 

Therefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not 

intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be 

further evaluated in this report. 

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

fuel usage as the feasibility arises. 

Coal Processing 

Since NMC process boilers are not capable of burning solid fuel, this option is not applicable for SO2

reductions at NMC. 

STEP 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable to the process boilers are identified in Table 5-7. The technical feasibility as 

determined in Step 2 is also included in Table 5-7. 

 

33 Federal Register 70, no. 128 (July 6, 2005): 39164
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Table 5-7 Backup Process Boiler SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility 

SO2 Pollution Control 

Technology Available? Applicable? Technically Feasible? 

WWESP Yes Yes Yes 

Wet Scrubber Yes Yes Yes 

Spray Dry Absorption (SDA) Yes Yes Yes 

Dry Sorbent Injection (DSI) Yes Yes Yes 

Energy Efficiency Projects Yes Yes No 

Alternative Fuels Yes Yes No 

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

Table 5-8 describes the expected control efficiency from each of the remaining feasible control 

options when burning liquid fuels. 

Table 5-8 Backup Process Boiler SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80% 

Wet Scrubbing (High Efficiency) 80% 

Dry Sorbent Injection 55% 

Spray Dryer Absorption 90% 

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

As illustrated in Table 5-8 above, the technically feasible control remaining provide varying levels of 

emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental 

impacts to better differentiate as presented below.

Economic Impacts 

Table 5-9 details the expected costs associated with installation of a WWESP, wet scrubber, DSI and 

SDA on each stack. Equipment design was based on the maximum 24-hour emissions, vendor 

estimates, and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The 
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cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the 

following equation: 

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

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

EPA models and factors. Operating costs were based on 93% utilization and 7650 operating hours 

per year, which is very conservative, considering these are backup boilers. Operating costs of 

consumable materials, such as electricity, water, and chemicals were established based on the U.S. 

EPA control cost manual34 and engineering experience, and were adjusted for the specific flow rates 

and pollutant concentrations. 

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

A. 

Table 5-9 Backup Process Boiler SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

Wet ESP $11,808,857 $2,247,725 $36,558 NA 

Wet Scrubber $13,618,522 $1,869,933 $31,845 NA 

Dry Sorbent Injection and 

Baghouse $4,890,063 $1,409,010 $22,917 NA 

Spray Dryer and Baghouse $16,134,577 $2,751,525 $44,752 NA 

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

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

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

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

 

34 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 
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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 pollutant35. 

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

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost column in Table 5-9 is intended to present the incremental value of each 

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

cost effective, the incremental control cost is not applicable. 

Energy and Environmental Impacts 

Because the cost of SO2 controls for the NMC process boilers is so high and does not meet a 

reasonable definition of cost effective technology, these technologies are removed from further 

consideration in this analysis. 

5.B.i.e STEP 5 – Evaluate Visibility Impacts 

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

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

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

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

document. The economic impacts of controls for SO2 are not reasonably cost effective, so visibility 

impacts were not modeled for SO2 controls. Refer to Table 4-2 for a summary of the modeled 24-

hour maximum emission rates and their computational basis for the existing controls for SO2. 

Visibility impacts with NOx controls are presented in Section 6. Table 6-1 provides a summary of 

the SO2, NOx, and PM10 emissions for each modeling scenario.

 

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

Processing Plant, Fairmont, MN Permit 09100059-002.
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5.B.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 as nitrogen compounds in the fuel is oxidized in the combustion 

process. 

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

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

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

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

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

minor amounts of NOx are emitted as prompt NOx. 

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

5.B.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 F for the current status of the availability and applicability of retrofit 

control technologies. 

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

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

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

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

discusses aspects of those technologies that determine whether or not the technology is technically 

feasible for the process boilers. 

External Flue Gas Recirculation (EFGR) 

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

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

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

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

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

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 
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this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. Process boilers 1 and 2 do not have the capability of control at the burner tip. 

Therefore, this option is not technically feasible and will not be further evaluated in this report. 

Low NOx Burners (LNB) 

Low- 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 a staged 

combustion process that is designed to split fuel combustion into two zones. In the primary zone, 

NOx formation is limited by either one of two methods. Under staged air rich (high fuel) condition, 

low oxygen levels limit flame temperatures resulting in less NOx formation. The primary zone is 

then followed by a secondary zone in which the incomplete combustion products formed in the 

primary zone act as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, 

excess air will reduce flame temperature to reduce NOx formation. In the secondary zone, 

combustion products formed in the primary zone act to lower the local oxygen concentration, 

resulting in a decrease in NOx formation. Low NOx burners typically achieve NOx emission 

reductions of 25% - 50% for process boilers. 

Overfire Air (OFA) 

Overfire air diverts a portion of the total combustion air from the burners and injects it through 

separate air ports above the top level of burners. OFA is a NOx control technology typically used in 

boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates an initial 

fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of 

thermal NOx by lowering combustion temperature and limiting the availability of oxygen in the 

combustion zone where NOx is most likely to be formed. OFA is considered compatible with the 

LNB and is a technically feasible option for further NOx reduction. However, due to the small size 

and number of burners, OFA is not desirable alternative for NMC process boilers and will not be 

considered for further BART analysis. 

Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low- 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 50-75%.
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Energy Efficiency Projects 

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

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency 

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon 

the fuel usage, process equipment, type of product and so many other variables. 

Due to the increased price of fuel, the facilities have already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and potentially emission reductions. It would be 

impossible to assign a general potential emission reduction for the energy efficient category. Due to 

the uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that facilities will continue to evaluate and implement energy efficiency 

projects as they arise. 

Alternate Fuels 

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

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

achieve reduction of NOx emissions through alternative fuel usage, the source must be currently 

burning a high NOx emitting fuel relative to other fuels. The boilers are only capable of burning 

natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for the process 

boilers and will not be considered further in this analysis. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.36 

Therefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to 

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further 

evaluated in this report 

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

fuel usage as the feasibility arises. 

 

36 Federal Register 70, no. 128 (July 6, 2005): 39164
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Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the combustion process. The 

two main techniques in commercial service include the selective non catalytic reduction (SNCR) 

process and the selective catalytic reduction (SCR) process. There are a number of different process 

systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

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

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

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

alternatives is described below. 

Non-Selective Catalytic Reduction (NSCR) 

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

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

primarily in natural gas combustion applications. 

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

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

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

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

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

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

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

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

liquid fuels. Therefore, this technology will not be further evaluated in this report. 

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction 

SCR is a post-combustion 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: 
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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 

(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. 

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

been applied to liquid and natural gas fired boilers. Using RSCR would require research, test runs, 
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and extended trials to identify potential issues related to catalyst selection, and impacts on plant 

systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming 

in advance of a demonstration project. The timeline required to perform such a demonstration project 

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

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

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

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

2007. 

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

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

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

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

BART analysis. 

Selective Non-Catalytic Reduction (SNCR) 

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F, 

reaction (2) will dominate. This control option is considered feasible. 

Low Temperature Oxidation (LTO) 

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

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®. 
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NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

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

(1,000 ppm NOx). 

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

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

demonstrated to be an effective technology in widespread application. Consequently, the technical 

feasibility of LTO as technically infeasible for this application and will not be evaluated further. 

Step 2 Conclusion 

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

available and applicable to the process boilers are identified in Table 5-10. The technical feasibility 

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

Table 5-10 Backup Process Boiler NOx Control Technology – Availability, Applicability and 

Technical Feasibility 

NOx Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas Recirculation (EFGR) Yes Yes No 

Low-NOx Burners Yes Yes Yes 

Overfired Air Yes Yes No 

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes 

Energy Efficiency Projects Yes Yes No 

Alternative Fuels Yes Yes Not required 

Non-Selective Catalytic Reduction (NSCR) Yes Yes No

Selective Catalytic Reduction (SCR) Yes Yes Yes 

Regenerative SCR Yes Yes No 

Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes 

Low Temperature Oxidation (LTO) Yes No No 

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

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

control options as identified in Step 2. 

Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Low-NOx Burners 50% 

Low-NOx Burners with IFGR 75% 

SCR 90% 

Selective Non-Catalytic Reduction (SNCR) 50% 
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5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-12 details the expected costs associated with installation of NOx controls. Capital costs were 

calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. 

Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate

using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% 

utilization and 7650 operating hours per year, which is extremely conservative, since they are backup 

boilers. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant 

concentrations. 

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

surrounding the boilers is congested and the area surrounding the building supports vehicle and rail 

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

foundations, and structural steel was added based upon the facility site to arrive at the total retrofit 

installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally, 

the structural design of the existing building would not support additional equipment on the roof. The

detailed cost analysis is provided in Appendix A. 

Table 5-12 Backup Process Boiler NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Operating Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental

Control 

Cost 

($/ton) 

Low NOx Burner $90,775 $14,915 $723 NA 

Low NOx Burner / 

IFGR $518,713 $330,367 $10,675 $30,626 

Selective Catalytic 

Reduction (SCR) $5,563,529 $1,120,061 $30,160 NA 

Selective NonCatalytic Reduction 

(SNCR) 

$925,876 $250,181 $12,126 NA 

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

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

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

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an 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 
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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 pollutant37. 

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

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost listed in Table 5-12 represents the incremental value of each technology 

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

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-13. 

Because the cost of the remaining NOx control technologies for the NMC process boilers is so high 

and does not meet a reasonable definition of cost effective technology, these technologies are 

removed from further consideration in this analysis. 

Table 5-13 Backup Process Boiler NOx Control Technology – Other Impacts Assessment 

Control 

Option Energy Impacts Other Impacts 

LNB - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

IFGR/LNB - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

 

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

Processing Plant, Fairmont, MN Permit 09100059-002.
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5.B.ii.e STEP 5 – Evaluate Visibility Impacts 

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

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

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

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

document. This section of the report evaluates the visibility impacts of BART 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-BART emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. In the visibility impacts 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. 

Table 5-14 Backup Process Boiler NOx Post- BART Emission Rates for Emission Unit EU003 

and EU004 

Control 

Scenario SV # 

Emission Unit 

Description 

NOx

Control 

Technology 

% NOx

Reduction 

NOx

Annual 

Emission 

Rate 

(tons/year) 

NOx

24-hour 

Maximum 

Emission 

Rate (lb/day) 

 1 SV003 Process Boiler 1 Low Nox 

Burners 50% 25.5 279 

 1 SV003 Process Boiler 2 Low Nox 

Burners 50% 25.5 279 
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Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios 

Scenario Control Scenario Technology Modeling Emission Rate Input 

SO2 NOx PM2.5/PM10 

SO2 NOx PM 

% 

Reduced 

24-hr Max 

lb/hr 

% 

Reduced 

24-hr Max 

lb/hr 

% 

Reduced 

PM2.5 24-

hr Max. 

lb/hr 

% 

Reduc

0 Base Base Base 

 SV003 

Process 

Boilers 

1 & 2 

 0 33.5 0 23.3 0 0 

1 Base

LNB 

with 

IFGR

Base 

 SV003 

Process 

Boilers 

1 & 2 

 0.0% 33.5 50.0% 11.6 0 0 
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Table 5-16 Backup process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control 

Scenario SV # Emission Unit

Stack Easting 

LCC 

(km) 

Stack Northing 

LCC 

(km) 

Height of 

Opening 

from Ground 

(m) 

Base 

Elevation 

of Ground 

(m) 

Stack 

Diameter 

(m) 

Flow Rate 

at exit 

(acfm) 

Exit 

Temp 

(

oF) 

 1 SV003 Process 

Boilers 1 & 2 631471.5 5238482.8 131 611 6.5 59900 450 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-17. The results summarize 98th percentile dV value and the number of days the facility 

contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison 

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

Visibility impacts with SO2 controls are presented in section 6. 

Table 5-17 Backup Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling 

Results 

2002 2003 2004 

2002 – 2004 

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) 

No. of days 

exceeding 

0.5 deciview 

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 

1 BWCA 1.1 33 1.1 34 1.3 38 1.1 105 

Table 5-18 Backup Process Boiler Post-BART NOx Modeling Scenarios – Comparison of 

Visibility Modeling Results to Baseline Modeling Results 

2002 2003 2004 

2002 – 2004 

Combined 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

days 

exceeding 

0.5 

deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 

1 BWCA 0.0 1 0.0 0 0.0 0 0.0 1 
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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-BART Modeling Scenarios 

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

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

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

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

However, because there are limited control options available that meet the above criteria, there are 

limited available control combinations, or control scenarios, that must be considered. Additionally, 

the interactions between the visibility impairing pollutants 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 SO2 and 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-BART modeling 

scenarios, including those presented in Step 5 of section 5, are presented in Table 6-1. 

6.B Post-BART Modeling Results 

Results of the post-BART modeling scenarios are presented in Table 6-2. The results summarize 

98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of 
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68

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

scenarios to the baseline conditions is presented in Table 6-3. 

While the cost per ton of low NOx burners is $723, and is below the threshold of $1,000 to $1,300 per 

ton, they result in essentially no visibility improvement to the Class I areas. In the three years, 

additional controls would result in only one fewer day with a visibility impact of greater than 0.5 dV

and the change in the modeled worst day (98th percentile) is 0.007 deciviews, which is less than 1% 

of the total modeled BART impact. The cost of this marginal improvement is $4.3 million per 

deciview, considering the capital cost of $91,000 and the total annual cost of $15,000. 
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Table 6-1 Post-BART 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

0 

Base 

(existing 

design) 

Base 

(existing 

design) 

 SV101 Furnace 11 Hood Exh --- 11.8 --- 17.1  SV102 Furnace 11 Hood Exh 11.8 17.1  SV103 Furnace 11 Hood Exh 11.8 17.1  SV104 Furnace 11 Waste Gas --- 5.9 --- 62.4  SV105 Furnace 11 Waste Gas 5.9 62.4  SV111 Furnace 12 Hood Exh --- 11.8 --- 17.1  SV112 Furnace 12 Hood Exh 11.8 17.1  SV113 Furnace 12 Hood Exh 11.8 17.1  SV114 Furnace 12 Waste Gas --- 5.9 --- 62.4  SV115 Furnace 12 Waste Gas 5.9 62.4  SV003 Process Boilers 1 & 2 33.5 23.3 

1 Base 

Base on 

indurating 

furnace and 

Low NOx

Burners on the backup 

process 

boilers 

 SV101 Furnace 11 Hood Exh 11.8 --- 17.1  SV102 Furnace 11 Hood Exh 11.8 17.1  SV103 Furnace 11 Hood Exh 11.8 17.1  SV104 Furnace 11 Waste Gas 5.9 --- 62.4  SV105 Furnace 11 Waste Gas 5.9 62.4  SV111 Furnace 12 Hood Exh 11.8 --- 17.1  SV112 Furnace 12 Hood Exh 11.8 17.1  SV113 Furnace 12 Hood Exh 11.8 17.1  SV114 Furnace 12 Waste Gas 5.9 --- 62.4  SV115 Furnace 12 Waste Gas 5.9 62.4  SV003 Process Boilers 1 & 2 33.5 50.0% 11.6 
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70

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

2002 2003 2004 

2

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 9

Percentil

Value 

(deciview

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 1 BWCA 1.1 33 1.1 34 1.3 38 1.1 

Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Mo

Modeling Results 

0 2002 2003 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 

Imp

Mod

98

Perc

Va

(∆-

0 BWCA 1.1 34 1.1 34 1.3 38 11 BWCA 0.0 1 0.0 0 0.0 0 0
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7. Select BART 

BART for NMC is proposed to be as follows: 

Indurating Furnaces

For SO2, polishing add-on controls are not cost effective. Therefore, BART is proposed to be 

existing controls. The corresponding SO2 emissions limit would be 2.0 lbs/mmBtu, which equates to 

300 lb/hr per furnace based upon each furnace heat input rating of 150 mmBtu. 

For NOx, add on control are not cost effective. Therefore, BART is proposed to be the existing 

furnace design and permitted fuels. The corresponding NOx limit would be 176 lb/hr for each 

furnace. 

For PM, requirements compelled by the upcoming MACT standard constitute BART. The 

corresponding emissions limit would be 0.01 grains per dscf for the furnaces. 

Process Boilers

The process boilers are backup boilers for steam production normally supplied to the taconite plant 

from the power boilers. For SO2, add-on controls are not cost effective. Therefore, BART is 

proposed to be existing design and permitted fuels. The corresponding SO2 emissions limit would be 

0.6 lb/mmBtu for each boiler. 

For NOx, add-on controls would not accomplish a meaningful improvement in visibility. Therefore, 

BART is proposed to be existing design and permitted fuels. The corresponding NOx limit would be 

0.17 lb/mmBtu for each boiler. 

Other Taconite Sources 

For PM, requirements compelled by the upcoming MACT standard constitute BART. The 

corresponding emissions limit would be equivalent to the MACT limit. 

The schedule for implementation of these limits is within the 5-year time-frame required for BART 

implementation.