Appendix 9H 

 

Tilden Mining Company BART 

Technical Analysis 
1

West (Tilden) Analysis of Best Available Retrofit Technology (BART)

Table of Contents

1. Executive Summary , v

2. Introduction 1

2.A BART Eligibility 2

2.B BART Determinations :..3

3. Streamlined BART Analysis :..8

3.A Indurating Furnaces 8

3.B PM-Only Taconite MACT EmissionUnits 9

3.C Other CombustionUnits 9

4. Baseline Conditions andVisibility Impacts for BART Eligible Units 12

4.A MDEQ Subject-to-BART Modeling 12

4.B Facility Baseline Modeling 13

4.C Facility Baseline Modeling Results 15

5. BART Analysis for Indurating Furnaces :16

5.A Line 1 Indurating Furnace 16

5.A.i Sulfur Dioxide Controls 17

5.A.i.a STEP 1- Identify All Available Retrofit Control Technologies 17

5.A.i.b STEP 2 - Eliminate Teclmically Infeasible Options 17

5.A.i.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Technologies 23

5.A.i.d STEP 4 - Evaluate Impacts and Document the Results 23

5.A.i.e STEP 5 - Evaluate Visibility Impacts 26

5.A.ii Nitrogen Oxide Controls : 33

5.A.ii.a STEP 1- Identify All Available Retrofit Control Technologies 33

5.A.ii.b STEP i-Eliminate Technically Infeasible Options ·33

5.A.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Technologies 46

5.A.ii.d STEP 4 - Evaluate Impacts and Document the Results .46

5.A.ii.e STEP 5 - Evaluate Visibility Impacts 49

5.B Process Boilers 1 and 2 .55

5.B.i Sulfur Dioxide Controls: 55

5.B.i.a STEP 1 - Identify All Available Retrofit Control Technologies 55

5.B.i.b STEP 2 - Eliminate Technically Infeasible Options 55

5.B.i.c STEP 3-Evaluate Control Effectiveness ofRemaining Control

Technologies 59

5.B.i.d STEP 4 - Evaluate Impacts and Document the Results 59

5.B.i.e STEP 5 - Evaluate Visibility Impacts 61

5.B.ii Nitrogen Oxide Controls 62

5.B.ii.a STEP 1 - Identify All Available Retrofit Control Technologies 62

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5.B.ii.b STEP 2 Eliminate TeclmicallyInfeasible Options ..; 62

5.B.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 70

5.B.ii.d STEP 4 - Evaluate Impacts and Document the Results 71

5.B.ii.e STEP 5 - Evaluate Visibility Impacts 73

5.C Line I Dryer 81

5.C.i Sulfur Dioxide Controls 81

5.C.i.a STEP 1-IdentifY All Available Retrofit ControI.Teclmologies 81

5.C.i.b STEP 2 - Eliminate Teclmically Infeasible Options 81

5.C.i.,,- STEP3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 87

5.C.i.d STEP 4- Evaluate Impacts and Document the Results 87

5.A.ii.f STEP 5 - Evaluate Visibility Impacts 89

5.C.ii Nitrogen Oxide Controls 90

5.C.ii.a STEP 1 - IdentifY AllAvailable Retrofit Control Teclmologies 90

5.C.ii.b STEP 2 - Eliminate Teclmically Infeasible Options 90

5.C.ii.c STEP 3 - Evaluate Control Effectiveness ofRemaining Control

Teclmologies 98

5.C.ii.d STEP 4 - Evaluate Impacts and Document the Results 99

5.C.ii.e STEP 5 - Evaluate Visibility Impacts 101

6. Visibility Impacts 111

6.A Post-Control Modeling Scenarios 111

6.B Post-Control Modeling Results 111

7. Select BART 128

List of Tables

Table 3-1 Summary Table ofBART-Eligible Units Subject to a Streamlined BART Analysis 11

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 14

Table 4-2

Table 5-1

Table 5-2

Table 5-3

Table 5-4

Table 5-5

Table 5-6

Table 5-7

Table 5-8

Table 5-9

Baseline Visibility Modeling Results :: 15

Indurating Furnace S02 Control Teclmology - Availability, Applicability, and

Teclmical Feasibility 22

Indurating Furnace S02 Control Teclmology Effectiveness , 23

Indurating Furnace S02 Control Cost Summary 24

S02 Control Teclmology Impacts Assessment.. 25

Post-Control Modeling Scenarios 27

Post-Control S02 Modeling Scenarios - Modeling Input Data 29

Post-Control S02 Modeling Scenarios - Visibility Modeling Results 31

Post-Control S02 Modeling Scenarios - Visibility Improvements , 32

Indurating Furnace NOx Control Technology - Availability, Applicability, and

Teclmical Feasibility 45

11

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Table 5-30

Table 5-31

Table 5-32

. Table 5-18

Table 5-219

Table 5-20

Table 6-1

Table 6-2

Table 6-3

Table 6-4

Table 6-5

Table 5-21

Table 5-22

Table 5-23

Table 5-27

Table 5-28

Table 5-29

Table 5-30

Table 5-I0 Indurating Furnace NOx Control Technology Effectiveness --46

Table 5-I I Indurating Furnace NOx Control Cost Summary .....................................................•...47

Table 5-12 NOx Control Technology Impacts Assessment.. .48

Table 5-13 Post-Control NOx Modeling Scenarios...................................................................•...50

Control Scenario 50

Table 5-14 Post-Control NOx Modeling Scenarios - Modeling Input Data 52

Table 5-15 Post-Control NOx Modeling Scenarios - Visibility Modeling Results 53

Table 5-16 Post-Control NOx Modeling Scenarios - Visibility Improvements 54

Table 5-17 Process Boiler S02 Control Technology-Availability, Applicability, and Technical

Feasibility 59

Process Boiler S02 Control Technology Effectiveness .59

Process Boilers 1 and 2 S02 Control Cost Summary 60

Process Boilers 1 and 2 NO, Control Technology - Availability, Applicability and

Technical Feasibility 70

Backup Process Boiler NOx Control Technology Effectiveness 71

Process Boiler NOx Control Cost Summary , 72

Process Boiler NO, Control Technology - Other Impacts Assessment 73

Process Boiler Post-BART Modeling Scenarios 75

Process Boiler Post-BART NO, Modeling Scenarios - Modeling Input Data 78

Process Boiler Post-BART NO, Modeling Scenarios - Visibility Modeling Results 79

Process Boiler Post-BART NO, Modeling Scenarios - Comparison ofVisibility

Modeling Results to Baseline Modeling Results , 80

Table 5-29 Line 1 Dryer S02 Control Technology - Availability, Applicability, and Technical

Feasibility 87

Line I Dryer S02 Control Technology Effectiveness 87

Line I Dryer SO, Control Cost Summary 88

Line 1 Dryer NOx Control Technology - Availability, Applicability and Technical

Feasibility .......................................................................................................•..........98

Line 1 Dryer NOx Control Technology Effectiveness 99

Backup Process Boiler NO, Control Cost Summary 100

Line 1 Dryer NO, Control Technology - Other Impacts Assessment.. 101

Process Boiler Post-BART Modeling Scenarios 103

Process Boiler Post-BART NO, Modeling Scenarios - Modeling Input Data I08

Process Boiler Post-BART NO, Modeling Scenarios - Visibility Modeling Results .. 109

Process Boiler Post-BART NO, Modeling Scenarios - Comparison of Visibility

Modeling Results to Baseline Modeling Results 110

Post-Control Modeling Scenarios I 13

Post-Control NOx Modeling Scenarios - Modeling Input Data I 18

Post-Control Modeling Scenarios - Visibility Modeling Results I 19

Post-Control Modeling Scenarios - Visibility Modeling Results 120

Post-Control Modeling Results - Dollars per Deciview Improvement.. 121

Table 5-33

Table 5-34

Table 5-35

Table 5-36

Table 5-37

Table 5-38

Table 5-39

111

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Appendix A

AppendixB

Appendix C

AppendixD

AppendixE

AppendixF

List of Appendices

Control Cost Analysis Spreadsheets

Changes to MDEQ BART Modeling Protocol

Visibility Impacts Modeling Report

Applicable and Available Retrofit Teclrnologies

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

BART Analysis Procedure and Streamlined BART Approach

IV

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1. Executive Summary 

DRAFT LANGUAGE 

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming, 

Michigan in Marquette County. This report describes the background and methods for the selection 

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing 

plant located near Ishpeming, MI. 

Michigan Department of Environmental Quality (MDEQ) identified the six pieces of equipment that 

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

equipment includes Line 1 Kiln, Dryer, Cooler, Primary Crusher, and Process Boilers 1 and 2. Line 

1 Kiln is permitted for natural gas, coal and fuel oil and Line 1 Dryer, Process Boilers 1 and 2 are 

permitted for natural gas and fuel oil. Preliminary visibility modeling conducted by the MDEQ 

found that air emissions from Tilden’s facility “cause or contribute to visibility impairment” in a 

federally protected Class I area, therefore making the facility subject to BART. 

Guidelines included in 40 CFR §51 Appendix Y were used to propose BART for the subject units. 

The existing pollution control equipment includes wet scrubbers on the dryer, cooler, and primary 

crusher, which are designed to control particulate matter (PM). The wet scrubber on the dryer will, 

however, experience some collateral control of sulfur dioxide (SO2). The kiln PM is controlled with 

an electrostatic precipitator (dry). 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, Tilden proposes the following as BART: 

Line 1 Kiln 

• SO2 emissions of 28,000 lb per day for Line 1 when coal is burned 

• NOx limit as specified in Appendix 2 Schedule of Compliance in the Renewable Operating 

Permit 199600379 and with Rule 336.1801. 

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

technology (MACT) standard1. 

Line 1 Cooler 

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

technology (MACT) standard2. 

Boilers 1 and 2 

• SO2 emissions limit is regulated by limiting the sulfur content to 1.2% by weight, calculated 

on the basis on 18,000 BTU per pound when used oil is burned. 

• NOx is good combustion practices 

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

technology (MACT) standard3. 

Line 1 Dryer 

• SO2 emissions limit is regulated by limiting the sulfur content to 1.5% by weight, calculated 

on the basis on 18,000 BTU per pound when used oil is burned NOx emissions will be 

controlled 

• NOx is good combustion practices 

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

technology (MACT) standard4. 

Primary Crusher 

 

1

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

2

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

3

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

4

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

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

technology (MACT) standard5. 

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

impact from the BART eligible sources is 0.72 dV, which is below perceptible levels of one to two 

dV. Real impacts to the Class I areas from Tilden are expected to be even less than these modeled 

impacts. 

 

5

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

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2. Introduction 

Tilden Mining Company LC (Tilden) owns and operates an iron mining facility near Ishpeming, 

Michigan in Marquette County. This report describes the background and methods for the selection 

of the Best Available Retrofit Technology (BART) as proposed by Tilden for its taconite processing 

plant also located near Ishpeming, MI. 

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

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

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

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

CFR part 51, in 51.300 through 51.309. 

Within its boundary, Michigan has two Class I areas – the Isle Royale National Park (IRNP) and 

Seney Wilderness Area. By December 2007, MDEQ 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. 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. 

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 

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worst days under natural conditions by 2064.6 Assuming a uniform rate of progress, the default glide 

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

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

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

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

non-air quality impacts. 

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

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

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

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

improvement goals. 

2.A BART Eligibility 

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

must meet the following three conditions: 

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

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

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

plants, sulfur recovery plants, etc.); 

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

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

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

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

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

visibility impairing pollutants such as PM, PM10, PM2.5, SO2, NOx, and possibly Volatile Organic 

Compounds (VOCs) and ammonia. Sources built before the implementation of the Clean Air Act 

(CAA), which had previously been grandfathered, may also have to conduct such analyses and 

 

6

 70 FR No. 178 pp. 39104 to 39172. 

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possibly install controls, even though they have been exempted to date from any other CAA 

requirements. 

Once BART eligibility is determined, a source must then determine if it is “subject to BART.” A 

source is subject to BART if emissions “cause or contribute” to visibility impairment at any Class I 

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

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

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

are BART-eligible. 

2.B BART Determinations 

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

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

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

The 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.7 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 

 

7

 40 CFR 51 Appendix Y 

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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.8

Step 2 - Eliminate Technically Infeasible Options 

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

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

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

BART analysis? 

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.9” 

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.10” 

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

is undergoing the BART analysis? 

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

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

type.11” 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.12” 

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

not technically feasible? 

 

8

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

9

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

10 IBID 

11 IBID 

12 IBID 

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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 

technology13.” This also involves the identification of “irresolvable 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 analysis14. 

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

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

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

EPA does not consider the absence of a vendor guarantee to be a “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 guarantees15. 

Step 3 - Evaluate Control Effectiveness 

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

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

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

Step 4 - Evaluate Impacts and Document Results 

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

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

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

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

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

quality environmental impacts. 

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

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

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

 

13 IBID 

14 IBID 

15 IBID 

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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 protocol16, including receptor grid, meteorological 

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

Department of Environmental Quality (MDEQ). 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 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 

 

16 Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors 

Consortium. 

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

information is available.17

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 time18.” 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 basis19.” which could include the incorporation of 

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

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

technological or economic limitations make measurement methodology for an emission unit 

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

standard, or combination of these types of standards20.” 

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

the Michigan SIP. 

 

17 40 CFR 51 Appendix Y. Page 361. 

18 40 CFR 51 Appendix Y. Page 368. 

19 40 CFR 51 Appendix Y. Page 369. 

20 40 CFR 51 Appendix Y. Page 368. 

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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 analyses21. 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 MDEQ-approved streamlined BART analysis for taconite facilities and 

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

3.A Indurating Furnaces 

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

Relative to NOx and SO2, PM is not a major visibility impairing pollutant. Further, the indurating 

furnaces are subject to the taconite MACT standard22 for the PM emissions. MDEQ requested that 

Tilden submit a BART analysis approach August 31, 2006. Tilden submitted both the BART 

Analysis Procedures and Streamlined BART Approach on August 29, 2006. Tilden has performed the 

BART analysis as outlined in the August 29, 2006 submittals. The BART Analysis Procedures and 

Streamlined BART Approach dated August 29, 2006 is included in Appendix F for reference. 

The approach, as outlined in the August 29, 2006 Streamlined BART Approach, relies 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. Specifically in 40 CFR Part 51 

Appendix Y paragraph IV.C., it states: 

For VOC and PM sources subject to MACT standards, States may streamline the analysis by 

including a discussion of the MACT controls and whether any major new technologies have 

been developed subsequent to the MACT standards. We believe that there are many VOC and 

PM sources that are well controlled because they are regulated by the MACT standards, 

which EPA developed under CAA section 112. For a few MACT standards, this may also be 

true for SO2. Any source subject to MACT standards must meet a level that is as stringent as 

the best-controlled 12 percent of sources in the industry. Examples of these hazardous air 

pollutant sources which effectively control VOC and PM emissions include (among others) 

secondary lead facilities, organic chemical plants subject to the hazardous organic NESHAP 

 

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

22 40 CFR Subpart 63 RRRRR-NESHAPS: Taconite Iron Ore Processing 

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(HON), pharmaceutical production facilities, and equipment leaks and wastewater 

operations at petroleum refineries. We believe that, in many cases, it will be unlikely that 

States will identify emission controls more stringent than the MACT standards without 

identifying control options that would cost many thousands of dollars per ton. Unless there 

are new technologies subsequent to the MACT standards which would lead to cost effective 

increases in the level of control, you may rely on the MACT standards for purposes of 

BART. (emphasis added)

It is clear from EPA’s guidance that they are encouraging states to develop a streamlined BART 

analysis approach for sources regulated under a MACT. Since the Taconite MACT standard was 

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

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

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

3.B PM-Only Taconite MACT Emission Units 

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

Ore Crushing and Pellet Cooler operations. These sources operate near ambient temperature, only 

emit PM, and do not emit NOx or SO2. The Ore Crushing source operates 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. 

Since the MACT standard was established recently and became effective in October 31, 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 Streamlined BART Procedures submitted to 

MDEQ August 29, 2006. 

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

3.C Other Combustion Units 

The combustion units are sources of three visibility impairing pollutants: NOx, SO2, and PM. 

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Tilden facility has two process boilers that are subject to the boiler MACT23. 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 Streamlined BART Procedures submitted to MDEQ August 29, 2006 

Similar to the induration furnaces, the dryer is also subject to the Taconite MACT for PM. As a 

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

A full BART analysis will be conducted for NOx and SO2 where applicable for the process boilers 

and dryer. 

 

23 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 Analysi

Emission 

Unit # 

Emission Unit 

Description 

NOx

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

SO2

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

PM10

Max 24-hr 

Actual 

Emissions 

(lbs/day) 

MACT 

PM Emission 

Limit 

(gr/dscf) 

Stack 

Number 

3.A Indurating Furnace 

EUKILN1 Line 1 Indurating Furnace 26208.0 6552.0 4948.5 0.01 magnetite 0.03 hematite 

SVP0051711 

(South) and 

SVP0051981 

(North) 

3.B PM-Only Taconite MACT Emission Units 

EUPRIMARY

CRUSHER Primary Crusher 1 -- -- 25.7 0.008 SVA0011570 

EUCOOLER1 Line 1 Pellet Cooler Exhaust -- -- 5.9 0.008 SVP0025490 

3.C Other Combustion Units 

EUDRYER1 Line 1 Dryer 

88.3 199.2 529.0 0.61 SVP0082951

EUBOILER1 Process Boiler #1 

463.3 1.5 300.0 0.61 SVBLR.STK. T1 

EUBOILER2 Process Boiler #2 

463.3 1.5 300.0 0.61 SVBLR.STK. T1 

1PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as pres

regulation, effective 10/30/2006.

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4. Baseline Conditions and Visibility Impacts for 

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance24, one of the factors to consider when determining 

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

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

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

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

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

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

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

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

Additionally, the interactions between the visibility impairing pollutants NOx, SO2, PM2.5, PM10, and 

background ammonia can play a large part in predicting impairment. It is therefore important to take 

a multi-pollutant approach when assessing visibility impacts. 

In order to estimate the visibility improvement resulting from the retrofit technology, the source must 

first be modeled at baseline conditions. Per U.S. EPA 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 emissions25. 

4.A MDEQ Subject-to-BART Modeling 

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

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

accordance with the Regional Haze Rule. The modeling by MDEQ was conducted using CALPUFF, 

as detailed in the “Single Source Modeling to Support Regional Haze BART Modeling Protocol”, 

March 21, 2006, Lake Michigan Air Directors Consortium. The modeling by MDEQ was conducted 

using emission rate information submitted by the facility in the annual emissions reporting. The 

emissions were reported in units of pounds per year and divided by the annual hours per year of 

operation to calculate a pound per hour (lb/hr) emission rate. The lb/hr emission rate was then 

multiplied by 24 hours to calculate the pounds per day (lb/day) emission rate. The lb/day is to reflect 

 

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

25 40 CFR Part 51 Appendix Y 

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the maximum actual emissions during a 24-hour period under steady-state operating conditions 

during periods of high capacity utilization. The modeling conducted by MDEQ demonstrated that 

this facility is subject-to-BART as stated in the letter from MDEQ on March 17, 2006 

4.B Facility Baseline Modeling 

Prior to re-creating the MDEQ visibility impairment model, the modeling method was re-revaluated. 

On behalf of Tilden and Empire, Barr Engineering proposed changes to the modeling. In discussions 

with MDEQ, it was indicated that most aspects of the modeling were flexible, so long as the changes 

were documented and appropriate files were included for their review with submittal of results. 

Details of the modifications to the model are included in Appendix B. 

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

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

high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect combustion 

of permitted fuels. 

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

summarized in 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 

Emissi

on 

Unit 

ID 

Emission 

Unit 

Description 

SO2 

Max. 

24-hr 

Actual 

Emissi

ons 

(lb/day) 

Basis 

for SO2 

24-hr 

Actual 

Emissi

ons 

NOx Max. 

24-hr 

Actual 

Emissions 

(lb/day) 

Basis for 

NOx 24-

hr 

Actual 

Emissio

ns 

PM2.5 

Max. 24-

hr Actual

Emission

s (lb/day) 

Basis 

for 

PM2.5 

24-hr 

Actual 

Emissio

ns 

PM10 

Max. 24-

hr Actual

Emission

s (lb/day) 

Basis 

for 

PM10 

24-hr 

Actual 

Emissio

ns 

Stack 

No. 

Latitud

e Longitude 

Height 

of 

openin

g 

from 

ground 

(ft) 

Ba

Elev

o

o

Gro

(f

3.A Indurating Furnaces 

EUKI

LN1 

Line 1 

Pellet 

Induration 

6552.0 COAL 26,208.0 Nat gas 3,610.1 MACT SVP00 51981 46.440 84994 -87.653 40738 240 14

 1,338.4 MACT SVP00 51711 46.440 75383 -87.651 32336 160 14

3.B PM-Only Taconite MACT Emission Units 

EUP

RIMA

RYCRUSHER 

PRIMARY 

CRUSHER 25.7 MACT SVA00 11570 46.439 33071 -87.651 52770 15 14

EUCOOL

ER 

Line 1 

Cooler 5.9 MACT SVP00 25490 46.439 79916 -87.648 27887 151 14

3.C PM-Only Other Combustion MACT Emission Units 

EUD

RYE

R1 

Line 1 

Dryer 199.2 COAL 88.3 NAT. GAS 529.0 MACT SVP00 82951 46.440 75383 -87.651 32336 119 14

EUB

OILE

R1 

Process 

Boiler #1 1.5 FUEL OIL 463.3 NAT. GAS 300.0 MACT SVBLR .STK.T 1 46.440 91784 -87.654 12418 130 14

EUB

OILE

R2 

Process 

Boiler #2 1.5 FUEL OIL 463.3 NAT. GAS 300.0 MACT SVBLR .STK.T 1 46.440 91784 -87.654 12418 130 14

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4.C Facility Baseline Modeling Results 

The Michigan BART modeling protocol26 describes the CALPUFF model inputs, including the 

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

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

two methods to assess the expected post-control visibility improvement: 

• 98th Percentile: As defined by federal guidance, a source "contributes to visibility 

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

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

I area receptor. 

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

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

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

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

this facility is considered to contribute to visibility impairment in Class I areas because the modeled 

98th percentile of the baseline conditions exceeds the threshold of 0.5 dV. The results of this 

modeling are also utilized in the post-control modeling analysis in section 6 of this document. The 

full modeling analysis is presented in Appendix C. 

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 

IRNP 0.714 19 0.722 11 0.599 11 0.674 41 

 

26 Single Source Modeling to Support Regional Haze BART Modeling Protocol, March 21, 2006, Lake Michigan Air Directors 

Consortium. Page 3. 

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5. BART Analysis for Indurating Furnaces 

As presented in section 3 and Table 3-1, the following sources at Tilden require a full BART analysis 

for SO2 and NOx: 

 Line 1 Indurating Furnace; 

 Process Boilers 1 and 2; and 

 Line 1 Dryer. 

The BART analyses for these sources are presented in sections 5.A, 5.B, and 5.C, respectively. 

5.A Line 1 Indurating Furnace 

The primary function of taconite indurating furnaces is to convert magnetic or hematite 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. 

The Line 1 Indurating Furnace is a grate/kiln furnace, in which the pellets are dried on a grate and 

then transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation 

section of the induration furnace is designed to operate at 2,400 oF and higher. This temperature is 

required to meet taconite pellet product specifications. Direct-fired fuel combustion in the induration 

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

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

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

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

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

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

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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. 

Tilden has two grate/kiln furnaces, Line 1 and Line 2. Line 1 is subject-to-BART and Line 2 is not 

subject to BART because Line 2 was installed outside the BART applicability time window. Line 1 is 

permitted to burn natural gas, coal and fuel oil. Line 1 is controlled by an electrostatic precipitator 

(ESP). The ESP is designed to remove PM and would be considered a high efficiency PM ESP Kiln 

1 has a PM limit of 0.065 per 1000 pounds of exhaust gas and 200 pounds per hour. NOx is 

controlled through furnace design and type of fuel usage. During high ozone alert days, coal is 

burned to reduce the amount of NOx generation. The SO2 is controlled through furnace design and 

type of fuel usage. Kiln 1 has a SO2 limit of 28,000 lbs per day. 

5.A.i Sulfur Dioxide Controls 

There are two sources of SO2 emissions from the Line 1 Indurating Furnace: 

1. SO2 emissions from the trace amounts of sulfur in the iron concentrate and binding agents 

present in the green balls; and 

2. SO2 emission from the sulfur in distillate fuel oil and coal, which are the permitted fuels. 

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 MDEQ on October 6, 2006 with the 

status of the technology as it was understood at that time. Appendix D presents the current status of 

the general availability 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 1, the technical feasibility of the control option was also discussed and determined. The 

following 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. 

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Wet Walled Electrostatic Precipitator (WWESP) 

An ESP applies electrical forces to separate suspended particles from the flue gas stream. The 

suspended particles are given an electrical charge by passing through a high voltage DC corona 

region in which gaseous ions flow. The charged particles are attracted to and collected on oppositely 

charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers 

for collection and removal. 

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

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

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

absorber. 

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

as SO2 flue gas concentration, fuel used, and ore composition. Tilden currently employs an ESP 

designed for removal of particulate matter. The existing ESP does not have the capacity to handle 

the additional loading of sulfate particulates. To add a WWESP to the process, it would be necessary 

to install it in series with the existing ESP. A control efficiency of a WWESP ranges from 30-80% 

dependent upon the process specific operating parameters. 

Based on the information contained within this report, a WWESP is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

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

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

liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing 

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

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

For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require 

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

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

rod scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently 

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

collateral emission reduction. 

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

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

reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

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

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and 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 oxygen

concentrations 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. The indurating furnace SO2 concentration would be considered low due to the high air 

flow rates required to assure product quality. 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. 

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Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone 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. Depending on the residence time and gas stream temperature, DSI control efficiency for an 

indurating furnace is estimated at 55%. 

Based on the information contained within this report, DSI is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

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. 

Based on the information contain with this report, SDA is considered a technically feasible 

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, Tilden has already implemented energy 

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

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

evaluated in this report. However, it should be noted that Tilden 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 moved companies 

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

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

capable of burning fuels with lower sulfur content than the existing fuels. Switching fuels trades one 

visibility impairment pollutant (SO2) for another (NOx), as induration furnaces emit significantly less 

NOx when burning solid fuels. Therefore, if this option is pursued, the impact on emissions of all 

visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the 

net benefit of a particular alternative fuel. 

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

option, not to direct the fuel choice.27 

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

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

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

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

alternate fuel usage as the feasibility arises. 

Coal Processing 

Pre-combustion coal processing techniques have been proposed as one strategy to reduce 

uncontrolled SO2 emissions. Coal processing technologies are being developed to remove moisture 

and potential contaminants from the coal prior to use. 

These processes typically employ both mechanical and thermal means to increase the quality of coal 

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine 

enters a first stage separator where it is crushed and screened to remove large rock and rock 

material.28 The processed coal is then passed on to an intermediate storage facility prior to being sent 

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks 

into the thermal processors where steam is injected. Moisture in the coal is released under these 

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock 

 

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

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

 process under development by KFx, Inc. 

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and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock. 

The second pressurized lock is vented into a water condenser to return the processor to atmospheric 

pressure and to flash cool the coal. Water, removed from the process at various points, and 

condensed process steam are reused within the process or treated prior to being discharged. 

To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and 

extended trials to identify potential impacts on plant systems, including the furnaces, material 

handling, and emission control systems. Therefore, processed fuels are not considered commercially 

available, and will not be analyzed further in this BART analysis. 

Coal crushing and drying is currently employed by Tilden as an incidental option for SO2 reduction. 

In the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed 

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in 

use, so further reductions from this control option are not possible. Therefore, it will not be further 

evaluated in this report. 

Step 2 Conclusion 

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

available and applicable as secondary controls to the existing indurating furnace wet scrubbers are 

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

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

Technical Feasibility 

SO2 Pollution Control Technology Available? Applicable? 

Technically 

Feasible? 

Wet Walled Electrostatic Precipitator 

(WWESP) Yes Yes Yes 

Wet Scrubbing Yes Yes Yes 

Dry sorbent injection (DSI) Yes Yes Yes 

Spray Dryer Absorption (SDA) Yes Yes Yes 

Energy Efficiency Projects Yes Yes Project Dependent 

Alternative Fuels Yes Yes Yes – Not 

Required by BART 

Coal Processing No No No 

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

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

options. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

SDA 90% 

Wet Scrubber 80% 

WWESP 80% 

DSI 55% 

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

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

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

impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-3 details the expected costs associated with installation of the above alternatives on each 

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

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 six-tenths-factor rule 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 100% utilization and annual operating hours 

of 7680 hours. Operating costs of consumable materials, such as electricity, water, and chemicals 

were established based on the U.S. EPA control cost manual29 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

Due to space considerations, 60%30 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 

 

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

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

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

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

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

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

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

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

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

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

Table 5-3 Indurating Furnace SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SDA $167,260,397 $23,254,882 $22,407 

Wet Scrubber $34,869,327 $6,048,540 $6,557 

WWESP $52,638,755 $13,922,184 $15,091 

DSI $42,082,032 $9,975,786 $15,729 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant31. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. Based on the information presented in table 5-3, 

the wet scrubber is the only technology that requires analysis for visibility improvement, energy and 

other impacts. 

The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since only one of the technologies is cost effective, the incremental control 

cost is not applicable and is not presented in this analysis. 

Energy and Environmental Impacts 

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

Table 5-4 SO2 Control Technology Impacts Assessment 

Control 

Technology Energy Impacts Other Impacts 

Wet Scrubber Significant pressure drop results 

in higher electrical requirements 

• Additional water 

consumption and 

wastewater generation 

• Increased facility water 

balance and water quality 

issues 

• Ponding for scrubber 

discharge will be limited 

because of site space 

constraints 

• Additional solid 

waste/sludge generation 

• Process downtime/lost 

production during 

installation 

Table 5-4 notes that wet scrubbers would require additional water consumption. Michigan’s Upper 

Peninsula has experienced a drought in the past several years. Use of wet scrubbers would create 

additional demand for water, a resource that is already stressed due to the recent drought conditions. 

Because the cost of the remaining SO2 control technologies for Tilden Line 1 furnace is so high and 

 

31 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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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. This section of the report evaluates the visibility impacts of BART SO2 control for the 

Line 1 Indurating Furnace and the resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

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

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

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

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

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

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

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

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

of the modeling input data.

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Table 5-5 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

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Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

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Scenario Control Technology SO2 

Control 

Scenario SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour lbs/hr % Reductio

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

 SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0%  SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

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

Control Scenario SV # Emission Unit Stack Latitude Stack Longitude 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for SO2 are presented in Table 5-7. The 

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

than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the postcontrol modeling scenarios to the baseline conditions is presented in Table 5-8. 

As illustrated in Tables 5-7 and 5-8, the highest facility baseline visibility contribution is 0.72 dV. A 

wet scrubber (Scenario 2) would potentially reduce the visibility contribution by 0.1 dV at a cost of 

over $34 million in installed capital cost and a total annual cost of over $6.0 million per year. This 

would result in a cost per deciview reduction of over $60 million per deciview. 

Visibility impacts with NOx controls are presented in Section 6. 

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Table 5-7 Post-Control SO2 Modeling Scenarios - Visibility Modeling Results 

2002 2003 2004 

2002 – 200

Combined 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

N

ex

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 

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Table 5-8 Post-Control SO2 Modeling Scenarios - Visibility Improvements 

Modeling Results 

0 2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

.

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5.A.ii Nitrogen Oxide Controls 

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

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

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

oxidized. 

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

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

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

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

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

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

minor amounts of NOx are emitted as prompt NOx. 

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

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

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

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

were evaluated. 

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 

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

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

the burner tip. 

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

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

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

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

is relatively inert and oxygen starved 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. 

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

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

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

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

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

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

of a straight-grate furnace at another taconite plant; however, the Line 1 Indurating Furnace does not 

contain a pre-heat burner section. If LNB were to be applied in the indurating zone of the furnace, 

the reduced flame temperatures associated with LNB would adversely affect taconite pellet product 

quality. LNB has not been applied to the indurating or preheat zones of any grate-kiln taconite 

furnace. Therefore, this option is not technically feasible. 

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

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

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

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

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

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

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

the development phase and is not yet commercially available. 

Induced Flue Gas Recirculation Burners 

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

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

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

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

burners in high temperature applications is 25-50%. 

As noted above, taconite furnaces are designed to operate with oxygen levels near 18%. At these 

oxygen levels, flue gas recirculation is ineffective at NOx reduction, and it would adversely affect 

combustion because excessive amounts of oxygen would be injected into the flame pattern. In 

addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be 

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

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

would adversely affect taconite pellet product quality. 

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

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

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Energy Efficiency Projects 

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

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

pollution emissions. Due to the increased price of fuel, Tilden has already implemented energy 

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

reductions. Due to the uncertainty and generalization for this category, this will not be further 

evaluated in this report. However, it should be noted that Tilden 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 produces enough heat to offset the heat loss associated with air injection. Air injection 

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

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

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

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

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

flow of air from the pellet cooler32. Any reduction in NOx would be minor and incidental to the 

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

available and applicable technology, its NOx reduction potential is small and may be unsuccessful 

because of the design of the pellet cooler area. Ported kilns will not be further evaluated in this 

report. 

Alternate Fuels 

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

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

 

32 Telephone conversation with Metso, July 18, 2006. 

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gas. Reduction of NOx emissions through alternative fuel usage has been achieved at taconite gratekilns through the use of solid fuel. In these cases the reduction resulted due to changes from 

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

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). Therefore, if this option is pursued, the 

impact on emissions of all visibility pollutants must be quantified and the cumulative visibility 

impact modeled to determine the net benefit of a particular alternative fuel. 

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

option, not to direct the fuel choice.33 

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

usage as the feasibility arises. 

Coal Processing 

Pre-combustion coal processing techniques have been proposed as one strategy to reduce 

uncontrolled NOx emissions. Coal processing technologies are being developed to remove moisture 

and potential contaminants from the coal prior to use. 

These processes typically employ both mechanical and thermal means to increase the quality of coal 

by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine 

enters a first stage separator where it is crushed and screened to remove large rock and rock 

material.34 The processed coal is then passed on to an intermediate storage facility prior to being sent 

to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks 

into the thermal processors where steam is injected. Moisture in the coal is released under these 

conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock 

and sulfur-forming pyrites. After treatment, the coal is discharged into a second pressurized lock. 

The second pressurized lock is vented into a water condenser to return the processor to atmospheric 

pressure and to flash cool the coal. Water, removed from the process at various points, and 

condensed process steam are reused within the process or treated prior to being discharged. 

 

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

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

 process under development by KFx, Inc. 

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To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and 

extended trials to identify potential impacts on plant systems, including the furnaces, material 

handling, and emission control systems. Therefore, processed fuels are not considered commercially 

available, and will not be analyzed further in this BART analysis. 

Coal crushing and drying is currently employed by Tilden as an incidental option for NOx reduction. 

In the process, raw coal is crushed and screened to remove rocks and other impurities. The crushed 

coal is then thermally processed to remove excess moisture. Coal crushing and drying is already in 

use, so further reductions from this control option are not possible. Therefore, it will not be further 

evaluated in this report. 

Process Optimization with Parametric Monitoring 

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

technically feasible control option for the taconite industry: 

• Typical 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 process optimization using parametric monitoring as a control technology. 

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

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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 the 

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

furnaces or similar combustion equipment. Therefore, this technology is not considered to be 

available and applicable, and therefore will not be further evaluated in this report. 

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Selective Catalytic Reduction (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

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

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

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

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

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

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

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

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

corrosion problems. 

A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F 

temperature range. However, these catalysts are very expensive. 

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

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

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (R-SCR) applies the Selective Catalytic Reduction (SCR) 

control process as described above 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 R-SCR 

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

preheating process. R-SCR 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 R-SCR are: 

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

• R-SCR has a thermal efficiency of 70% vs. standard heat exchangers which have a thermal 

efficiency of 60% to 70%. 

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• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

There are several concerns about the technical feasibility and applicability of R-SCR on an 

indurating furnace: 

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

composition of the flue gas from the boilers that utilize R-SCR; 

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

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

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

to the erosive nature of the taconite dust; 

• R-SCR has not been applied downstream of a wet scrubber. Treating a stream saturated with 

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

corrosion protection; 

• R-SCR 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, R-SCR 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 R-SCR at a taconite plant 

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

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

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

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

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

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

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

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

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

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

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

Therefore, R-SCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

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

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

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

technically feasible. 

Low Temperature Oxidation (LTO) 

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

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

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

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

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

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

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)

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Tri-NOx

®

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

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

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

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

®

 is 

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

(1,000 ppm NOx). NOx concentrations in the exhaust at Tilden are typically less than 200 ppm. 

Therefore, Tri-NOx

®

 is not applicable to taconite processing and will not be analyzed further in this 

BART analysis. 

Low Temperature Oxidation (LoTOx®) 

BOC Gases’ Lo-TOx®

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

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

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an 

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

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

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

generation. 

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

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

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

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 or any process beyond coal or gas fired boilers. 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 one 

million acfm. Therefore, the application of LTO would be more than two orders of magnitude larger 

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

and could be problematic in maintaining the current removal efficiencies. 

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

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

demonstrated to be an effective technology in widespread application. 

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

indurating furnace: 

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

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

• The taconite dust in the flue gas is primarily magnetite (Fe3O4) which would react with the 

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

there can be more than 185 pounds per hour of taconite dust in the flue gas which could 

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

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

generated or a decrease in the estimated control efficiency; 

• The ozone that would be injected into the flue gas would react with the SO2, converting the 

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

• 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 tried on taconite induration furnaces, on airflows of the 

magnitude of taconite furnace exhausts, nor on 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 

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45

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, LTO is technically infeasible on an indurating furnace and will not be evaluated 

further. 

Step 2 Conclusion 

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

available and applicable to the indurating furnace process are identified in Table 5-9. The technical 

feasibility as determined in Step 2 is also included in Table 5-9.

Table 5-9 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas 

Recirculation (EFGR) Yes No No 

Low NOx Burners (LNB) Yes Yes No 

Induced Flue Gas 

Recirculation Burners (IFGR) Yes Yes No 

Energy Efficiency Projects Yes Yes Project 

Dependent 

Ported Kilns 

(Applies to Grate-Kilns Only) Yes Yes No 

Alternative Fuels Yes Yes 

Yes 

- Not Required 

by BART 

Process Optimization Yes No No 

Non-Selective Catalytic 

Reduction (NSCR) Yes No No 

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NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

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 5-10 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

Table 5-10 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

SCR 

With conventional reheat 80% 

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

Table 5-11 summarizes the expected costs associated with installation of low NOx burners and SCR 

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

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 six-tenths-factor rule to account for the 

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

7680 hours for Line 1. Operating costs were proportionally adjusted to reflect site specific flow rates 

and pollutant concentrations. 

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

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

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

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

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

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

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47

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

provided in Appendix A. 

Table 5-11 Indurating Furnace NOx Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual 

Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SCR 

With conventional reheat 

$65,492,092 $31,055,581 $8,416 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $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. Based on the information presented in table 5-11, 

SCR with conventional reheat is the only technology that requires analysis for visibility 

improvement, energy and other impacts. 

 

35 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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The BART guidance documents also present a calculation method for incremental control cost which 

is intended to present the incremental value of each technology as compared to the next most 

effective alternative. Since only one of the technologies is cost effective, the incremental control 

cost is not applicable and is not presented in this analysis. 

The incremental control cost column in Table 5-11 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 Impact 

The energy and non-air quality impacts for the remaining alternatives are presented in Table 5-12. 

Table 5-12 NOx Control Technology Impacts Assessment 

Control Technology Energy Impacts Other Impacts 

SCR with Reheat 

Reheat would require 

additional natural gas 

use. 

• Ammonia slip, which 

contributes to regional 

haze. Ammonia reacts 

with NOx to form 

ammonium nitrate and 

SO2 to form ammonium 

sulfate particles. 

Ammonium sulfate is 

hygroscopic and bonds 

with water in the air to 

grow large particles. The 

large particles formed by 

ammonium sulfate 

disproportionately 

contribute to visibility 

impairment. 

• Ammonia emissions will 

increase condensable PM 

emissions that will have 

possible PSD permitting 

implications. 

• Ammonia deposition onto 

nearby lakes and waters 

of the state and contribute 

nutrients and undesirable 

biological growth. 

• Additional safety and 

regulatory concerns 

associated with ammonia 

storage on site. 

• Possible oxidation of 

elemental mercury. 

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

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

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

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

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

document. This section of the report evaluates the visibility impacts of BART NOx control and the 

resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

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

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

maximum 24-hour average project emission rate. In the visibility impacts analysis for NOx, 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 5-13 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOx control technologies. Table 5-14 provides a 

summary of the modeling input data.

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Table 5-13 Post-Control NOx Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat 80% 40.0 80% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 80% 14.6 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-14 Post-Control NOX Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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Post-Control Visibility Impacts Modeling Results 

Results of the post-control visibility impacts modeling for NOX are presented in Table 5-15. The 

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

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

modeling scenarios to the baseline conditions is presented in Table 5-16. 

As illustrated in tables 5-15 and 5-16, the facility baseline visibility contribution is 0.72 dV. 

Installing SCR with conventional reheat on Line 1 when natural gas is burned could potentially 

reduce the visibility contribution by 0.45 from Scenario 1.. 

Visibility impacts with SO2 controls are presented in section 6. 

Table 5-15 Post-Control NOX Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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Table 5-16 Post-Control NOX Modeling Scenarios - Visibility Improvements 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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5.B Process Boilers 1 and 2 

Two natural gas and fuel oil fired process boilers require BART analysis. These boilers provide 

steam required to operate the taconite plant, as needed. The boilers are only permitted to burn 

natural gas and used oil. 

5.B.i Sulfur Dioxide Controls 

Sulfur in the fuel is the only source of SO2 emissions from these boilers. The boilers 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. Many emerging technologies have been identified that are not currently commercially 

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 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 F presents the current status of the general availability of each technology. 

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

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

Step 1, the technical feasibility of the control option was also discussed and determined. The 

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

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

the technology is technically feasible for indurating furnaces. 

Wet Walled Electrostatic Precipitator (WWESP) 

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

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

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

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

rapping and fall into hoppers for collection and removal. 

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

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

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

absorber. 

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

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

WWESP is considered a technically feasible technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

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

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

liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic 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. 

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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’s exhaust 

would not have a high SO2 concentration, so the low end of the efficiency range would be expected. 

Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone 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. 

Based on the information contained within this report, DSI is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

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 a technically feasible 

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, Tilden has already implemented energy 

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

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

evaluated in this report. However, it should be noted that Tilden 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 also 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 be 

capable of burning fuels with lower sulfur content than the existing fuels. The process boilers are 

only permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO2

emission reductions through the use of alternate fuels are not an option and are 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.36 

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, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Coal Processing 

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

reductions. 

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 5-17. The technical feasibility 

as determined in Step 2 is also included in Table 5-17. 

 

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

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Table 5-17 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 Project Dependent 

Alternative Fuels Yes Yes Yes - Not Required by 

BART 

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

Table 5-18 describes the expected control efficiency from each of the remaining feasible control 

options when burning liquid fuels. 

Table 5-18 Process Boiler SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

SDA 90% 

Wet Scrubbing (High Efficiency) 80% 

WWESP 80% 

DSI 55% 

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

As illustrated in Table 5-18 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 5-19 details the expected costs associated with installation of the above alternatives on each 

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

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

scaled to each stack’s flow rate using the six-tenths-factor rule37 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 manual38 and engineering experience, and were adjusted for the specific flow rates 

and pollutant concentrations. 

The detailed cost analysis is provided in Appendix A. 

Table 5-19 Process Boilers 1 and 2 SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

SDA $56,323,180 $8,640,697 $38,403,097 

Wet Scrubber $9,309,297 $1,489,576 $7,447,882 

WWESP $17,123,526 $3,146,592 $15,732,959 

DSI $32,010,048 $4,892,432 $35,581,325 

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 

 

37 M.S. Peters and K.D. Timmerhaus, December, 2002 Plant Design and Economics for Chemical Engineers, Fifth 

Edition. 

38 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 MDEQ, then visibility modeling impacts, and energy and other impacts are 

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

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant39. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. Based on the information presented in table 5-19, 

the annualized pollution control costs for all of the technologies are above the $12,000 threshold. 

Therefore, no additional analysis for visibility improvement, energy and other impacts is required. 

The BART guidance documents also present a calculation method for incremental control cost which 

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 and is not presented in this analysis. 

Energy and Environmental Impacts 

Since none of the SO2 technologies are cost effective for the process boilers, the energy and non-air 

quality impacts were not assessed for the SO2 control equipment technologies for the process boilers. 

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. Since none of the SO2 technologies are cost effective for the process boilers, the visibility 

impacts were not evaluated. 

 

39 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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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 boiler. 

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. Many emerging technologies have been identified that are not currently 

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6, 

2006 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 F presents the current status of the general availability of each 

technology. 

5.B.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 process boilers. 

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External Flue Gas Recirculation (EFGR) 

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

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

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

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

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

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

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

the burner tip. Due to the current configuration of the burners, 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. 

Based on the information contained within this report, LNB is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Overfire Air (OFA) 

Overfire air (OFA) 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 peak combustion temperature and limiting the availability of 

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oxygen in the combustion zone where NOx is most likely to be formed. OFA is considered 

compatible with the LNB. The estimated NOx control efficiency for LNB with OFA is 50-67%. 

Based on the information contained within this report, OFA with LNB is considered a technically 

feasible technology for NOx reduction for this BART analysis. 

Induced Flue Gas Recirculation (IFGR) 

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%. 

Based on the information contained within this report, IFGR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

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, Tilden has already implemented energy efficiency projects. Each 

project carries its own fuel usage reductions and potential emission reductions. Due to the 

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

However, it should be noted that Tilden 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 also 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. 

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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.40 

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, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Low Excess Air 

Operating a boiler with low excess air is a method to minimize peak flame temperature and excess 

oxygen which therefore minimizes the production of NOx. Operating a boiler with low excess air 

also optimizes the fuel efficiency as less air is heated up in the combustion chamber. 

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage. 

Therefore, the boilers at Tilden are operated with low excess air within the constraints of the boilers. 

Therefore, low excess air will not be further evaluated in this report. However, similar to energy 

efficiency and alternate fuels, the facility will continue to evaluate boiler optimization including 

operating at low excess air. 

Reburning 

Reburning is a technology used with solid fuels. Process boilers are not cable of burning solid fuel, 

therefore this technology will not be further evaluated. 

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, 

 

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

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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; therefore, NSCR is 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 (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

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. 

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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 (R-SCR) 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 R-SCR 

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

preheating process. R-SCR 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 R-SCR are: 

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

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

thermal efficiency of 60% to 70%. 

• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

To date, R-SCR 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, 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. 

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

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

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

Therefore, R-SCR 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. 

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. 

Based on the information contained within this report, a SNCR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Low Temperature Oxidation (LTO) 

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

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

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

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

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

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

NO + O3 → NO2 + O2 (1) 

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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. 

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 

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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 5-20. The technical feasibility 

as determined in Step 2 is also included in Table 5-20.

Table 5-20 Process Boilers 1 and 2 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 (LNB) Yes Yes Yes 

Low NOx Burners with Overfired Air 

(LNB/OFA) Yes Yes Yes 

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes 

Low Excess Air Yes Yes 

Yes 

(already 

implemented) 

Reburning Yes Yes No 

Energy Efficiency Projects Yes Yes Project 

Dependent 

Alternative Fuels Yes Yes 

Yes 

- Not Required 

by BART 

Non-Selective Catalytic Reduction (NSCR) Yes Yes Yes 

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 5-21 describes the expected control efficiency from the remaining technically feasible control 

option as identified in Step 2. 

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Table 5-21 Process Boiler NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Selective Catalytic Reduction (SCR) with 

Reheat 80% 

Low NOX Burner / Flue Gas Recirculation 

(LNB/FGR) 75% 

Regenerative Selective Catalytic Reduction 

(R-SCR) 70% 

Low NOX Burner / Overfire Air (LNB/OFA) 67% 

Low NOX Burner (LNB) 50% 

Selective Non-Catalytic Reduction (SNCR) 50% 

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

Table 5-22 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. 

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Table 5-22 Process Boiler NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

SCR with Reheat** $6,317,686 $2,528,225 $39,888 NA 

LNB/FGR $2,190,300 $270,904 $4,559 Lowest 

R-SCR** $16,117,290 $3,303,391 $59,563 NA 

LNB/OFA $3,031,714 $390,751 $7,361 NA 

LNB $1,320,909 $286,968 $7,244 NA 

SNCR $1,501,420 $426,135 $10,760 NA* 

* Control efficiency is equal to the option with the lowest cost per ton, LNB at 50%. 

** SCR and R-SCR were eliminated from further consideration due to high cost per ton.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant41. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. 

 

41 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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The incremental control cost listed in Table 5-22 represents the incremental value of each technology 

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

incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the 

capital and operating costs of remaining alternatives is also significant and may impact the viability 

of continued operation. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-23. 

Because the cost of the remaining NOx control technologies for the 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 5-23 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 

LNB/OFA - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

LNB/FGR - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

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 

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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 5-24 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOx control technologies. Table 5-25 provides a 

summary of the modeling input data. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-26. 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 5-27. 

Visibility impacts with SO2 controls are presented in section 6. 

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Table 5-27 Process Boiler Post-BART Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 EUKILN1 Wet Scrubber Good Combustion 80% 40.0 0.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 Practice 80% 14.6 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 EUKILN1 Low Sulfur Coal SCR w/reheat 0.0% 200.2 80% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0051711 Natural Gas 72.8 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-28 Process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate at exit 

(acfm) 

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,000 306,000 

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,135 

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,000 

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Table 5-29 Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling Result

Modeling Results 

2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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Table 5-30 Process Boiler Post-BART NOx Modeling Scenarios – Comparison of Visibility Modeling Results t

Results 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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5.C Line 1 Dryer 

The Line 1 Dryer requires a BART analysis. This Line 1 Dryer includes a combustion box in which 

natural gas and used oil is burned as fuel. The flue gas from the combustion box flows into a rotary 

dryer that repeatedly tumbles wet taconite ore concentrate through the flue gas stream to reduce the 

amount of entrained moisture in the taconite ore concentrated. The particulate emissions from the 

dryer are controlled by cyclones and impingement scrubbers in series. The dryer is only permitted to 

use natural gas and used oil for fuel. 

5.C.i Sulfur Dioxide Controls 

Sulfur in the fuel is the only source of SO2 emissions from the dryer. The Line 1 Dryer has low

emissions of SO2 due to the low sulfur content of the permitted fuels. In addition, collateral SO2

reductions occur within the existing impingment scrubbers, and therefore the existing scrubber is 

considered a low-efficiency SO2 scrubber. 

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

available. A preliminary list of technologies was submitted to MDEQ on October 6, 2006 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 F presents the current status of the general availability of each technology. 

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

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

Step 1, the technical feasibility of the control option was also discussed and determined. The 

following 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. 

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

as SO2 flue gas concentration and fuel used. Since Line 1 Dryer currently employs a wet scrubber 

designed for removal of particulate matter, the scrubber also performs as a low efficiency SO2 wet 

scrubber. The addition of a WWESP would act as a polishing SO2 control device and would 

experience reduced control efficiency due to lower SO2 inlet concentrations. 

Based on the information contained within this report, a WWESP is considered a technically feasible 

technology for SO2 reduction for this BART analysis. 

Wet Scrubbing (High and Low Efficiency) 

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

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

liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic 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 

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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 dryer and process boiler’s 

exhaust would not have a high SO2 concentration, so the low end of the efficiency range would be 

expected. 

As stated in the beginning of this section, a wet scrubber is currently in place on the Line 1 Dryer and 

is believed to remove approximately 30% of the SO2 in the exhaust. The addition of an additional 

SO2 scrubber would act as a polishing SO2 control device and would experience reduced control

efficiency due to lower SO2 inlet concentrations. 

A Minnesota taconite facility has evaluated modifying the exiting scrubber on the kiln exhaust, 

which is similar to the dryer exhaust stream, to determine if improvements to SO2 removal could be 

accomplished. The concentration of caustic in the scrubbing water was increased to a pH of 8 for 

several hours and stack sampling was performed to evaluate the change in SO2 emissions. The SO2

emissions were not reduced. The materials of construction of the existing scrubbers would not 

withstand a higher pH than 7 or 8. An engineering study would be required to evaluate more 

extensive redesign of the existing scrubbers, such as modifying the spray, increasing the contact 

time, recirculating the scrubber water, and retrofitting to allow use of a much higher pH. 

Quantifying the likelihood and magnitude of potential improvements to SO2 control would not be 

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

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Based on the information contained within this report, a wet scrubber is considered a technically 

feasible technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection (DSI) of lime/limestone 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. 

The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew 

points. Exhaust gases leaving the Line 1 Dryer is currently treated for removal of particulate matter 

using a wet scrubber. Due to the high water content in the dryer flue gas, 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 for the Line 1 Dryer. 

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%. 

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The Line 1 Dryer flue gas stream is high in water content and is exhausted at or near their dew 

points. Gases leaving the dryer are currently treated for removal of particulate matter using a wet 

scrubber. The exhaust temperature is typically in the range of 100 oF to 150 oF and is saturated with 

water. For comparison, a utility boiler exhaust operates at 350 o

F or higher and is not saturated with 

water. Under dryer 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. 

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, Tilden has already implemented energy 

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

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

evaluated in this report. However, it should be noted that Tilden 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 also 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 be 

capable of burning fuels with lower sulfur content than the existing fuels. The Line 1 Dryer is only 

permitted to burn natural gas and used oil, which are both low in sulfur content. Therefore SO2

emission reductions through the use of alternate fuels are not an option and are not applicable to the 

Line 1 Dryer. 

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.42 

 

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

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Therefore, due to the limited fuel burning capabilities of the Line 1 Dryer 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, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Coal Processing 

Since the Line 1 Dryer is not permitted to burn solid fuel, this option is not applicable for SO2

reductions. 

STEP 2 Conclusion 

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

available and applicable to the Line 1 Dryer are identified in Table 5-29. The technical feasibility as 

determined in Step 2 is also included in Table 5-29. 

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Table 5-29 Line 1 Dryer 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 No 

Dry Sorbent Injection (DSI) Yes Yes No 

Energy Efficiency Projects Yes Yes Project Dependent 

Alternative Fuels Yes Yes Yes – Not required by 

BART 

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

Table 5-30 describes the expected control efficiency from each of the remaining feasible control 

options for the Line 1 Dryer. 

Table 5-30 Line 1 Dryer SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Scrubbing (High Efficiency) 80% 

Wet Walled Electrostatic Precipitator (WWESP) 80% 

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

As illustrated in Table 5-30 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 5-31 details the expected costs associated with installation of a WWESP and wet scrubber. 

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 six-tenths-factor rule as shown in the following equation: 

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

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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 100% utilization and 7650 operating hours 

per year, which is very conservative based on historic operating data. Operating costs of consumable 

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

cost manual43 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 5-31 Line 1 Dryer SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Wet Scrubber $3,898,490 $684,207 $25,103 

Wet ESP (WWESP) $7,674,618 $1,429,065 $52,432 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

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

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impact analyses at an annualized cost of $12,000 per ton of controlled pollutant44. Therefore, all air 

pollution controls with annualized costs less than this screening threshold will be evaluated for 

visibility improvement, energy and other impacts. However, as presented in table 5-31, all of the 

available and applicable technologies for SO2 control for the Line 1 Dryer have annualized control 

costs greater than $12,000 per ton of controlled pollutant. Therefore, no additional impacts analysis 

is required. 

The BART guidance documents also present a calculation method for incremental control cost which 

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 and is not presented in this analysis. 

Energy and Environmental Impacts 

As presented in table 5-31, all of the available and applicable technologies for SO2 control for the 

Line 1 Dryer have annualized control costs greater than $12,000 per ton of controlled pollutant. 

Therefore, no energy and environmental impacts analysis was required. 

5.C.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. Since none of the SO2 technologies are cost effective for the process boilers, the visibility 

impacts were not evaluated. 

 

44 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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5.C.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 dryer. 

5.C.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. Many emerging technologies have been identified that are not currently 

commercially available. A preliminary list of technologies was submitted to MDEQ on October 6, 

2006 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 F presents the current status of the general availability of each 

technology. 

5.C.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 the Line 1 Dryer. 

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External Flue Gas Recirculation (EFGR) 

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

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

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

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

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

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

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

the burner tip. Due to the current configuration of the burners, the Line 1 Dryer does 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. 

Based on the information contained within this report, LNB is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

Overfire Air (OFA) 

Overfire air (OFA) 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 peak combustion temperature and limiting the availability of 

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oxygen in the combustion zone where NOx is most likely to be formed. OFA is considered 

compatible with the LNB. The estimated NOx control efficiency for LNB with OFA is 50-67%. 

Based on the information contained within this report, OFA with LNB is considered a technically 

feasible technology for NOx reduction for this BART analysis. 

Induced Flue Gas Recirculation (IFGR) 

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%. 

Based on the information contained within this report, IFGR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

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, Tilden has already implemented energy efficiency projects. Each 

project carries its own fuel usage reductions and potential emission reductions. Due to the 

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

However, it should be noted that Tilden 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 also 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 Line 1 Dryer is only capable 

of burning natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for 

the Line 1 Dryer and will not be considered further in this analysis. 

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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.45 

Therefore, due to the limited Line 1 Dryer 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, Tilden will continue to evaluate and implement alternate fuel 

usage as the feasibility arises. 

Low Excess Air 

Operating a burner with low excess air is a method to minimize peak flame temperature and excess 

oxygen which therefore minimizes the production of NOx. Operating a burner with low excess air 

also optimizes the fuel efficiency as less air is heated up in the combustion chamber. 

As previously stated, the increased price of fuel has pushed companies to evaluate fuel usage. 

Therefore, the Line 1 Dryer at Tilden is operated with low excess air within the constraints of the 

combustion chamber. Therefore, low excess air will not be further evaluated in this report. 

However, similar to energy efficiency and alternate fuels, the facility will continue to evaluate boiler 

optimization including operating at low excess air. 

Reburning 

Reburning is a technology used with solid fuels. The Line 1 Dryer is not cable of burning solid fuel; 

therefore this technology will not be further evaluated. 

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, 

 

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

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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; therefore, NSCR is 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 (SCR) and Regenerative Selective Catalytic Reduction 

(R-SCR) 

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. 

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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 (R-SCR) 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 R-SCR 

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

preheating process. R-SCR 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 R-SCR are: 

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

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

thermal efficiency of 60% to 70%. 

• Application of R-SCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

To date, R-SCR has been applied to wood-fired utility boilers. Application of this technology has 

not been applied to liquid and natural gas fired taconite dryers. Using R-SCR would require research, 

test runs, 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. 

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

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

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

Therefore, R-SCR 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. 

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. 

Based on the information contained within this report, a SNCR is considered a technically feasible 

technology for NOx reduction for this BART analysis. 

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. In addition, LoTOx has not 

been applied on a taconite dryer or similar process. 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 5-32. The technical feasibility 

as determined in Step 2 is also included in Table 5-32.

Table 5-32 Line 1 Dryer 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 Project 

Dependent 

Alternative Fuels Yes Yes 

Yes – Not 

required by 

BART 

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

Table 5-33 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

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Table 5-33 Line 1 Dryer NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Selective Catalytic Reduction (SCR) with 

Reheat 80% 

Low NOX Burner / Flue Gas Recirculation 

(LNB/FGR) 75% 

Regenerative Selective Catalytic Reduction 

(R-SCR) 70% 

Low NOX Burner / Overfire Air (LNB/OFA) 67% 

Low NOX Burner (LNB) 50% 

Selective Non-Catalytic Reduction (SNCR) 50% 

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

Table 5-34 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 six-tenths-factor rule to account for the economy of scale. Operating costs were based on 

100% utilization and 7650 operating hours per year, which is extremely conservative. 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. 

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Table 5-34 Line 1 Dryer NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

SCR with Reheat $6,439,029 $1,008,211 $83,472 NA 

LNB/FGR $1,087,058 $134,645 $11,891 $19,493 

R-SCR $5,445,064 $1,024,459 $96,934 NA 

LNB/OFA $888,317 $116,686 $11,535 $21,669 

LNB $432,579 $61,070 $8,090 Lowest 

SNCR $915,968 $278,929 $36,949 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 

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 MDEQ, then visibility modeling impacts, and energy and other impacts are 

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

impact analyses at an annualized cost of $12,000 per ton of controlled pollutant46. 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 5-34 represents the incremental value of each technology 

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

 

46 Michigan Department of Environmental Quality May 12, 2006 meeting. 

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incremental cost of SCR with reheat, R-SCR and SNCR are not reasonable. The magnitude of the 

capital and operating costs of remaining alternatives is also significant and may impact the viability 

of continued operation. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-35. 

Because the cost of the remaining NOx control technologies for the Line 1 Dryer 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 5-35 Line 1 Dryer 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 

LNB/FGR - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

5.C.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 5-36 provides a summary of the modeled 24-hour maximum emission rates and 

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their computational basis for the evaluated NOx control technologies. Table 5-37 provides a 

summary of the modeling input data. 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-38. 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 5-39. 

Visibility impacts with SO2 controls are presented in section 6. 

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Table 5-36 Line 1 Dryer Post-BART Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

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Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 Low Sulfur Fuel LNB w/OFA 0.0% 0.1 67.0% 

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106

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

EUBOILER2 Oil 

Natural Gas 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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107

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

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108

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

Table 5-37 Line 1 Dryer Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

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109

Table 5-38 Line 1 Dryer Post-BART NOx Modeling Scenarios - Visibility Modeling Results 

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

4 IRNP 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

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110

Table 5-39 Line 1 Dryer Post-BART NOx Modeling Scenarios – Comparison of Visibility 

Modeling Results to Baseline Modeling Results 

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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111

6. Visibility Impacts 

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

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

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

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

The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this 

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

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

6.A Post-Control Modeling Scenarios 

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

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

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

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

The interactions between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part 

in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing 

visibility impacts. Accordingly, this visibility improvement analysis evaluates several operating 

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

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

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

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

stack parameters are presented in Table 6-2. 

6.B Post-Control Modeling Results 

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

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

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

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112

scenarios to the baseline conditions is presented in Table 6-4. Notably, none of the post-control 

scenarios produces a visibility improvement that exceeds the perceptible threshold of 1-2 dV. 

Additionally, Table 6-5 illustrates the scenarios on a $/dV basis. The dollar per deciview ranges 

from $6.1 million to more than $79 million per dV of improvement. 

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113

Table 6-1 Post-Control Modeling Scenarios 

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% Base SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

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114

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 0.0% 0.1 0.0% 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

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115

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

15 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 0.0% 0.1 75.0% 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

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116

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 Low Sulfur Fuel LNB w/OFA 0.0% 0.1 67.0% 

123
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117

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

EUBOILER2 Oil 

Natural Gas 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 0.0% 0.1 67.0% 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

Good Combustion Practice 0.0% 8.3 0.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice 0.0% 200.2 72.8 0.0% 

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 0.0% 8.3 50.0% 

124
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118

Scenario Control Technology SO2 

Control Scenario

SV # Emission Unit SO2 NOx % Reduction 

Max 

24-hour 

lbs/hr % Reduct

Natural Gas 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat 0.0% 200.2 72.8 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice 80% 80% 40.0 14.6 0.0% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat 80% 80% 40.0 14.6 80% 80% 

SVP0082951 EUDRYER1 

Low Sulfur Fuel 

Oil 

Natural Gas 

LNB 0.0% 8.3 50.0% 

SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 0.0% 0.1 50.0% 

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

Control Scenario SV # Emission Unit Stack Easting 

(utm) 

Stack Northing 

(utm) 

Height of 

Opening from 

Ground 

(ft) 

Base Elevation 

of Ground 

(ft) 

Stack length, 

width, or 

Diameter 

(ft) 

Flow Rate 

(acfm

All Scenarios SVP0051981 SVP0051711 EUKILN1 46.44084994 

46.44075383 

-87.653 

40738 

-87.651 

32336 

240 160 

1474 

19.3 13.5 

842,0306,0

 SVP0082951 EUDRYER1 46.44075383 -87.651 32336 119 1474 6.3 57,13

SVBLR.STK.

T1 

EUBOILER1 EUBOILER2 46.44091784 -87.654 12418 130 1474 7.5 192,0

125
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119

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

Modeling Results 

 2002 2003 2004 

2002-2004 

Scenario 

Limiting 

Class I 

Area 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Modeled 

98%ile 

∆dV 

# days 

over 

0.5 ∆dV 

Base IRNP 0.714 19.0 0.722 11.000 0.599 11.000 0.674 41 

1 IRNP 0.323 2.0 0.275 1.000 0.228 1.000 0.248 2 

2 IRNP 0.610 15.0 0.620 10.000 0.535 8.000 0.600 33 

3 IRNP 0.183 0.0 0.177 0.000 0.154 0.000 0.173 0 

4 IRNP 0.717 19.0 0.717 11.000 0.589 12.000 0.668 42 

5 IRNP 0.322 2.0 0.256 0.000 0.219 1.000 0.254 2 

6 IRNP 0.619 15.0 0.623 10.000 0.528 8.000 0.598 33 

7 IRNP 0.182 0.0 0.177 0.000 0.155 0.000 0.169 0 

8 IRNP 0.714 19.0 0.711 11.000 0.583 11.000 0.653 41 

9 IRNP 0.314 2.0 0.252 0.000 0.213 1.000 0.248 2 

10 IRNP 0.618 15.0 0.607 10.000 0.527 8.000 0.590 33 

11 IRNP 0.176 0.0 0.168 0.000 0.150 0.000 0.161 0 

12 IRNP 0.719 19.0 0.693 10.000 0.592 9.000 0.654 38 

13 IRNP 0.315 2.0 0.246 0.000 0.218 1.000 0.243 2 

14 IRNP 0.627 15.0 0.608 9.000 0.544 8.000 0.585 32 

15 IRNP 0.176 0.0 0.171 0.000 0.150 0.000 0.160 0 

16 IRNP 0.722 19.0 0.673 10.000 0.605 9.000 0.656 38 

17 IRNP 0.326 2.0 0.243 0.000 0.218 1.000 0.243 2 

18 IRNP 0.626 15.0 0.605 9.000 0.542 8.000 0.596 32 

19 IRNP 0.175 0.0 0.173 0.000 0.151 0.000 0.163 0 

20 IRNP 0.734 19.0 0.692 10.000 0.605 10.000 0.654 39 

21 IRNP 0.324 2.0 0.241 0.000 0.215 1.000 0.241 2 

22 IRNP 0.625 15.0 0.602 9.000 0.291 3.000 0.588 27 

23 IRNP 0.175 0.0 0.170 0.000 0.150 0.000 0.165 0 

24 IRNP 0.727 19.0 0.689 10.000 0.603 10.000 0.656 39 

25 IRNP 0.326 2.0 0.245 0.000 0.207 1.000 0.241 2 

26 IRNP 0.623 15.0 0.605 9.000 0.550 8.000 0.597 32 

27 IRNP 0.176 0.0 0.172 0.000 0.151 0.000 0.165 0 

28 IRNP 0.704 19.0 0.672 10.000 0.606 9.000 0.657 38 

29 IRNP 0.325 2.0 0.239 0.000 0.198 1.000 0.240 2 

30 IRNP 0.613 14.0 0.614 9.000 0.542 8.000 0.588 31 

31 IRNP 0.173 0.0 0.172 0.000 0.151 0.000 0.164 0 

126
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120

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

Modeling Results 

2002 2003 2004 2002-2004 

Scenario 

Limiting 

Class I 

Area 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

Days 

exceeding 

0.5 dV 

1 IRNP 0.391 17 0.447 10 0.371 10 0.426 39 

2 IRNP 0.104 4 0.102 1 0.064 3 0.074 8 

3 IRNP 0.531 19 0.545 11 0.445 11 0.501 41 

4 IRNP -0.003 0 0.005 0 0.01 -1 0.006 -1 

5 IRNP 0.392 17 0.466 11 0.38 10 0.42 39 

6 IRNP 0.095 4 0.099 1 0.071 3 0.076 8 

7 IRNP 0.532 19 0.545 11 0.444 11 0.505 41 

8 IRNP 0 0 0.011 0 0.016 0 0.021 0 

9 IRNP 0.4 17 0.47 11 0.386 10 0.426 39 

10 IRNP 0.096 4 0.115 1 0.072 3 0.084 8 

11 IRNP 0.538 19 0.554 11 0.449 11 0.513 41 

12 IRNP -0.005 0 0.029 1 0.007 2 0.02 3 

13 IRNP 0.399 17 0.476 11 0.381 10 0.431 39 

14 IRNP 0.087 4 0.114 2 0.055 3 0.089 9 

15 IRNP 0.538 19 0.551 11 0.449 11 0.514 41 

16 IRNP -0.008 0 0.049 1 -0.006 2 0.018 3 

17 IRNP 0.388 17 0.479 11 0.381 10 0.431 39 

18 IRNP 0.088 4 0.117 2 0.057 3 0.078 9 

19 IRNP 0.539 19 0.549 11 0.448 11 0.511 41 

20 IRNP -0.02 0 0.03 1 -0.006 1 0.02 2 

21 IRNP 0.39 17 0.481 11 0.384 10 0.433 39 

22 IRNP 0.089 4 0.12 2 0.308 8 0.086 14 

23 IRNP 0.539 19 0.552 11 0.449 11 0.509 41 

24 IRNP -0.013 0 0.033 1 -0.004 1 0.018 2 

25 IRNP 0.388 17 0.477 11 0.392 10 0.433 39 

26 IRNP 0.091 4 0.117 2 0.049 3 0.077 9 

27 IRNP 0.538 19 0.55 11 0.448 11 0.509 41 

28 IRNP 0.01 0 0.05 1 -0.007 2 0.017 3 

29 IRNP 0.389 17 0.483 11 0.401 10 0.434 39 

30 IRNP 0.101 5 0.108 2 0.057 3 0.086 10 

31 IRNP 0.541 19 0.55 11 0.448 11 0.51 41 

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121

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

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Base SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice Base SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

Base SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

1 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,055,581 0.447 $69,475,573

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

2 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,048,540 0.104 $58,159,038

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

3 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,104,122 0.545 $68,080,958

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

4 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Good Combustion Practice $61,070 0.01 $6,107,000

128
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122

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

5 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,165,192 0.466 $79,753,630

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

6 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,048,540 0.099 $61,493,020

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

7 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,104,121 0.545 $68,153,011

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas Good Combustion Practice 

8 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $303,758 0.016 $18,984,875

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

9 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,055,581 0.47 $66,652,096

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

129
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123

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

10 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,352,298 0.115 $55,237,373

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

11 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,407,880 0.554 $67,523,250

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

12 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $364,828 0.029 $12,580,275

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

13 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,420,409 0.476 $66,009,262

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

14 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,413,368 0.114 $56,257,614

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

15 SVP0051981 EUKILN1 Wet Scrubber SCR w/reheat $37,165,192 0.551 $67,450,439

130
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124

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

SVP0051711 

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/FGR 

16 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $390,751 0.049 $7,974,510

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

17 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,446,333 0.479 $65,649,965

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

18 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,439,291 0.117 $55,036,675

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

19 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,494,873 0.549 $68,296,672

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

20 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $451,821 0.03 $15,060,700

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 

131
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125

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

21 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,507,403 0.481 $65,503,956

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

22 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,500,362 0.12 $54,169,683

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

23 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,555,942 0.552 $68,036,127

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB w/OFA 

24 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $286,968 0.033 $8,696,000

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

25 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,391,089 0.477 $78,388,027

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

132
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126

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

26 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,335,508 0.117 $54,149,641

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

27 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,391,089 0.55 $67,983,798

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

Good Combustion 

Practice 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

28 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas Good Combustion Practice $348,038 0.05 $6,960,760

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

29 SVP0051981 SVP0051711 EUKILN1 Low Sulfur Coal Natural Gas SCR w/reheat $31,403,619 0.483 $65,017,845

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

30 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber Good Combustion Practice $6,396,578 0.108 $59,227,574

SVP0082951 EUDRYER1 

Low Sulfur 

Fuel Oil 

Natural Gas 

LNB 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

31 SVP0051981 SVP0051711 EUKILN1 Wet Scrubber SCR w/reheat $37,452,159 0.55 $68,094,834

SVP0082951 EUDRYER1 Low Sulfur Fuel Oil LNB 

133
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

127

Scenario Control Technology 

Control Scenario SV # Emission Unit SO2

NOx

Annualized Cost 

($/yr) 

Improved 

Modeled 98th

Percentile 

Value (∆-dV) 

$/dV 

Natural Gas 

 SVBLR.STK.T1 EUBOILER1 EUBOILER2 Low Sulfur Fuel Oil Natural Gas LNB 

134
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

128

7. Select BART 

DRAFT LANGUAGE 

BART for Tilden is determined to be as described below. 

Line 1 Indurating Furnace 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is 28,000 lb per day for Line 1 when coal is burned. 

For NOx, the reduction due to good combustion practices on Line 1 is selected as BART. Other addon controls for NOx are not cost effective. The corresponding NOx limit is specified in Appendix 2 

Schedule of Compliance in the Renewable Operating Permit 199600379 and with Rule 336.1801. 

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

Process Boilers 1 and 2 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is regulated by limiting the sulfur content to 1.2% 

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned. 

For NOx, the reduction due to good combustion practices is selected as BART. Other add-on controls 

for NOx are not cost effective. 

For PM, requirements compelled by the September 13, 2007 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

Line 1 Dryer 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit is regulated by limiting the sulfur content to 1.5% 

by weight, calculated on the basis on 18,000 BTU per pound when used oil is burned. 

For NOx, the reduction due to good combustion practices is selected as BART. Other add-on controls 

for NOx are not cost effective. 

135
Y:\22\52\080 Tilden BART\BART report\Tilden BART Report (2006-12-28).doc 

129

For PM, requirements compelled by the October 30, 2006 MACT standard constitute BART. The 

corresponding emissions limits are equivalent to the limits identified in Table 3-1. 

The schedule for implementation of controls is by October 30, 2006, well in advance of the 5-year 

time-frame required for BART implementation. 

136
Michigan Operations - West (Tilden) 12/

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

NOx Control Cost Summary 

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

Cost $

Selective Catalytic 

Reduction with Reheat 80% 923 3690 $65,492,092 $31,055,581 $8,4

SO2 Control Cost Summary 

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

Cost $

Spray Dry Baghouse 90% 115.3 1037.8 $167,260,397 $23,254,882 $22,4Wet Scrubber (Absorber)(after existing ESP) 80% 230.6 922.5 $34,869,327 $6,048,540 $6,5

Secondary Wet Walled Electrostatic Precipitator (WWESP)(after existing ESP)

80% 230.6 922.5 $52,638,755 $13,922,184 $15,

DSI Baghouse 55% 518.9 634.2 $42,082,032 $9,975,786 $15,7

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Furnace Control Costs.xlsCost Summary

137
Michigan Operations - West (Tilden) 12/27/2006

BART Report - Attachment A: Emission Control Cost AnalysisTable A.1: Process Boilers 1 and 2 and Line 1 Dryer Cost Summary

NOx Control Cost Summary 

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

Selective Catalytic Reduction (SCR) with ReheatProcess Boilers #1 and #2 80% 15.85 63.38 $6,317,686 $2,528,225 $39,888 n/a

Line 1 Dryer 80% 3.02 12.08 $6,439,029 $1,008,211 $83,472 n/aLow NOX Burner / Flue Gas Recirculation

Process Boilers #1 and #2 75% 19.81 59.42 $2,190,300 $303,758 $5,112 n/a

Line 1 Dryer 75% 3.77 11.32 $1,087,058 $134,645 $11,891 $19,493Regenerative Selective Catalytic Reduction (R-SCR)Process Boilers #1 and #2 70% 23.77 55.46 $16,117,290 $3,303,391 $59,563 n/aLine 1 Dryer 70% 4.53 10.57 $5,445,064 $1,024,459 $96,934 n/aLow NOX Burner / Overfire Air (OFA)

Process Boilers #1 and #2 67% 26.15 53.08 $3,031,714 $390,751 $7,361 na

Line 1 Dryer 67% 4.98 10.12 $888,317 $116,686 $11,535 $21,669Low NOX Burner

Process Boilers #1 and #2 50% 39.61 39.61 $1,320,909 $286,968 $7,244 n/a

Line 1 Dryer 50% 7.55 7.55 $432,579 $61,070 $8,090 n/aSelective Non-Catalytic Reduction (SNCR)Process Boilers #1 and #2 50% 39.61 39.61 $1,501,420 $468,772 $11,833 n/aLine 1 Dryer 50% 7.55 7.55 $915,968 $278,929 $36,949 n/a

SO2 Control Cost Summary 

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

Spray Dry BaghouseProcess Boilers #1 and #2 90% 0.03 0.23 $56,323,180 $8,640,697 $38,403,097 n/a

Line 1 Dryer 90% 0.03 0.23 $26,617,360 $4,025,029 $17,889,019 n/aWet ScrubberProcess Boilers #1 and #2 80% 0.05 0.20 $9,309,297 $1,489,576 $7,447,882 n/aLine 1 Dryer 80% 6.81 27.26 $3,898,490 $684,207 $25,103 n/aWet ESP (WWESP)Process Boilers #1 and #2 80% 0.05 0.20 $17,123,526 $3,146,592 $15,732,959 n/aLine 1 Dryer 80% 6.81 27.26 $7,674,618 $1,429,065 $52,432 n/aDSI BaghouseProcess Boilers #1 and #2 55% 0.11 0.14 $32,010,048 $4,892,432 $35,581,325 n/aLine 1 Dryer 55% 0.04 0.14 $26,023,184 $4,079,117 $29,666,302 n/a

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix A Tilden Process Boilers Control Costs.xlsCost Summary

138
Michigan Operations - West (Tilden)

BART Report - Changes to MDEQ BART Modeling ProtocolAppendix B

CALMET

Variable Description Value Default Comments

NX Number of X grid cells 66 n/a

NY Number of Y grid cells 39 n/a

XORIGKM Reference point coordinates for grid 180 n/a

YORIGKM Reference point coordinates for grid 612 n/a

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

NSSTA Number of Surface Stations 88 n/a 88 surface weather stationsNPSTA Number of Precipitation Stations 99 n/a 99 precipitation stations

Input Group 5

BIAS Surface/upper-air weighting factors -1, 11*0 12*0 Surface Layer is set to -1 since 

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

CALPUFF

Variable Description Value Default Comments

NX Number of X grid cells in met grid 66 n/a

NY Number of Y grid cells in met grid 39 n/a

XORIGKM Reference point coordinates for met grid 180 n/a

YORIGKM Reference point coordinates for met grid 612 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 66 n/a

JECOMP Y index of UR corner 39 n/a

Input Group 2Input Group 4Input Group 6Input Group 4

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix B Changes to MDEQ BART Modeling Protocol (WEST).xls

Sheet1

139
Cleveland Cliffs Michigan Operations - Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO not be distributed without the fuinformation is not taken out of c

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a generally available 

control technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible for 

this source? Approximate Control Efficiency

Comments Bas

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

2 Wet Scrubbing (Low Efficiency) Y Y Y Y <50% Absorption and reaction using an alka

3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y 80% Suspended particles are separated from 

collected in hoppers

4 Dry sorbent injection Y Y Y Y <55%

Pulverized lime or limestone is directlfabric filter. Dry sorption of SO2 onto 

solid particles are collected with a fab

5 Spray Dryer Absorption (SDA) Y Y Y Y <90% Lime slurry is sprayed into an absorpt

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific Natural gas is base case Use a fuel with lower sulfur content.

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

demand throught efficiency projects.

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

Site-specific decrease amount of fuel required to m

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

to be burned. Specific energy efficien

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

Gas stream passes through a packed bsupports the growth of active bacteriaare biodegraded or biotransformed intdioxide, water, chlor

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

An aqueous solution of proprietary di

countercurrent absorption tower. The 

stripping, giving a byproduct of pure, 

recycling to the a

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

Gas stream is passed through a filter b

particle, high-surface area metal oxide removed from the gases by adsorption

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls

140
Cleveland Cliffs Michigan Operations - Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO not be distributed without the fuinformation is not taken out of c

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a generally available 

control technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible for 

this source? Approximate Control Efficiency

Comments Bas

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

Dry sorbent injection upstream of the injection upstream of a zeolitic selectiincorporated in the baghouse to reduc

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

conversion of sulfur and nitrogen oxidcollected by conventional methods su

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

Utilizes a reactor in which SO2, NOx, 

dioxide (NO2), sulfuric acid, and merc

plasma.On recent project, the vender was doin

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

Uses a regenerable sorbent to simultan

from coal-fired utility and industrial b

to a saleable sulfur by-product (liquid 

the NOx

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

SO2 in the flue gas reacts with copper 

alumina, to form copper sulfate. Ammabsorption reactor and a selective catareduces the nitr

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

Catalytic reduction of NOx in the pres

catalytic oxidation of SO2 to SO3. The 

through a novel glass-tube condenser 

and then condensed to a

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

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Furnaces.xls

141
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

1 Wet Scrubbing (High Efficiency) Yes Yes Yes Yes Absorption and reaction using an alkaline reagent to produ

2 Wet Scrubbing (Low Efficiency) Yes Yes Yes Yes Absorption and reaction using an alkaline reagent to produ

3 Wet Walled Electrostatic Precipitator (WWESP) Yes Yes Yes Yes Existing fabric filter control Suspended particles are separated from the flue gas stream

hoppers

4 Dry sorbent injection Yes Yes Yes Yes

Pulverized lime or limestone is directly injected into the dsorption of SO2 onto the lime or limestone particle occurs 

a fabric filter

5 Spray Dryer Absorption (SDA) Yes Yes Yes Yes Lime slurry is sprayed into an absorption tower where SO2 

CaSO3/CaSO4

6 Alternative Fuels Yes Yes Yes

Yes (not 

required by 

BART)

Not permitted for other fuels. Use a fuel with lower sulfur content.

7 Load Reduction Yes Yes No --- Could reduce production This is a strategy to reduce load on a power plant by reduc

efficiency projects.

8 Energy Efficiency Projects Yes Yes Yes Yes Decrease amount of fuel required to make an acceptable p9 Coal Drying Yes Yes No --- Requires available excess heat source Dry coal will increase the as-burned BTU value, and there

Specific energy efficiency project

10 Bio Filters No --- --- --- Research level

Gas stream passes through a packed bed of specially engingrowth of active bacterial species. The pollutants in the gabiotransformed into innocuous products, such as carbon disulfate or nitrate ions in water.

11 CANSOLV Regenerable SO2 No --- --- --- Research level

An aqueous solution of proprietary diamine captures SO2 f

absorption tower. The rich solvent is regenerated by steam 

water saturated SO2 gas and lean solvent for recycling to th

12 Pahlman Process No --- --- --- Research level

Gas stream is passed through a filter baghouse in which spsurface area metal oxide sorbent have been deployed. Polladsorption.

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

142
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

13 SOx-NOx-Rox-Box No --- --- --- Technology has not been demonstrated Dry sorbent injection upstream of the baghouse for remov

upstream of a zeolitic selective catalytic reduction (SCR) creduce NOx emissions.

14 Electron (E-Beam) Process No --- --- --- No operating commercial 

applications on coal

Electron beam irradiation in the presence of ammonia to innitrogen oxides into components which can be easily collean ESP or baghouse.

15 Electrocatalytic Oxidation No --- --- --- Similar to cold plasma. Will keep watch for availability 

of this technology

Utilizes a reactor in which SO2, NOx, and mercury are oxi

acid, and mercuric oxide respectively using non-thermal pOn recent project, the vender was doing final trials on full

16 NOXSO No --- --- --- Commercial version of adsorption. Limited experience 

(proof-of-concept tests).

Uses a regenerable sorbent to simultaneously adsorb SO2 a

utility and industrial boilers. In the process, the SO2 is con

(liquid SO2, elemental sulfur, or sulfuric acid) and the NO

17 Copper-Oxide No --- --- --- Absorption and SCR. Experience limited to 

pilot scale.

SO2 in the flue gas reacts with copper oxide, supported on 

copper sulfate. Ammonia is injected into the flue gas beforcatalytic reduction-type reaction occurs that reduces the niregeneration step, the copper sulfate is reduced in a regenenatural gas, producing a concentrated stream of SO2.

18 SNOX No --- --- --- Early commercial development stage

Catalytic reduction of NOx in the presence of ammonia (N

SO2 to SO3. The exit gas from the SO3 converter passes th

which the SO3 is hydrated to H2SO4 vapor and then conde

acid (H2SO4).

19 Cold Plasma No --- --- --- Research level

1) This number is for reference only. It does not in any way rank the control technologies.

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

143
Cleveland Cliffs Michigan Operations BART Analysis

SO2 Control

Process Boilers

Available and Applicable Review 

Step 1 Step 2

This table is part of the CCMO Process Boiler BART 

without the full text of the report so that the inform

Reference No.

1

SO2 Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Principle

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D - Michigan Operations Control Technologies - Process Boilers.xls

SOx Process Boilers

144
145

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the formation ofN2 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx formation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tern erature

Need capacity of all Shut offthe fuel flow fi·om one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No burners for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create and fucl·lcan zones

Part of the total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes No primary (main burners) flames to create a reducing atmosphere zone),

where hydrocarbon radicals rcact with NOx to producc clemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the elcctrical demand through efficiency rojects,

s Yes Yes Yes Yes Decrease amount offuel re uircd to make an acce table roduct

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned, Specific energy efficiency project

g Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

eport\Appendix\Appendix 0 Michigan Operations Control Technologies Dryer.xls

1 of 4

12/21/2006
146

Cleveland Cliffs Michigan Operations BART Analysis

NOxControl

Oryer

Available and Applicable Review

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Alternate Fuels Yes Yes Yes required by facilities experience lower

BART) NOx when burning solid using a fuel with less nitrogen.

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and 

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination nfGFA and SCR. Wall-fired or 

18 ROFA-ROTAMIX Yes Yes Yes 'Yes the scenario that combines utilizes high velocity overflre air. Additional NO

OFAand SCR anunonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes "'-'-No---""---·'" be tuned to'impact NOx Optimization of combustion

emissions

CUrrent e,quipment cannot

20 Parametric Monitoring Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into the 

38 No Research Level to the combustion site, initiating chemical reactio

(EPS Technologies) the flame.

21 Non-Selective Catalytic Yes Yes Yes Yes Not ,efficient as other Under near stoichiometric conditions, in the pres

Reduction (NSCR) reduced by CO, resulting in nitrogen (N2) and ca

22 Low Temperature Oxidation Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxid

(LTD) Tri-NOx® NOx

Y:\22\52\OBO Tilden BART\BART report\Appendix\Appendix 0 Michigan Operations Control Technologies M Dryer.xls

NOx Dryer
147

Cleveland Cliffs Michigan Operations BART Analysis

NOx COl")trol

Dryer.

Available and Applicable Review

Revised: December 1, 2006

n Yes 

on Yes 

No

Yes Yes Yes

Has been included as an

"innovative" technology in

recent BACT analyses

from multiple facilities.

Need to inject at

appropriate temperature.

Applicable to clean

services.

Utilizes an oxidizing agent such as ozone to oxidize various pollutants including

NOx

Ammonia (NH)) is injected into the flue gas stream in the presence ofa catalyst to

convert NOx into Nz and water

Yes

Yes

No

Yes

Yes

No

Yes

Yes

Yes

YesYes

Yes

Yes

Yes

Yes

•.. j .",

For clean services. Too

much debris in flue gas

would poison catalyst

Still in research sta es.

Similar to TriNOx

Redundant to regenerative

. ...,r;

Urea or ammonia·based chemicals are injected into the flue gas stream to COnvert

NO to molecular nitrogen, N2, and water

Use of char activated carbon to adsorb oxides ofnitro en

Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions,

molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Gas stream is sent through the regenerative, recuperative, catalytic or direct fired

oxidizer where pollutants are heated to a combustion point and destroyed.

No

No

Early'col1li:nercial

development stage

Technology has not been

demonstrated

Catalytic reduction ofNOx in the presence of ammonia (NH]), followed by

catalytic oxidation ofS02 to SO]. The exit gas from the SO) converter passes

through a novel glass-tube condenser in which the SO] is hydrated to H2S04

vapor and then condensed to a concentrated liquid sulfuric acid (H2S04),

Dry sorbent injection upstream ofthe baghouse for removal of SOx and ammonia

injection upstream ofa zeolitic selective catalytic reduction (SCR) catalyst

incorporated in the baghouse to reduce NOx emissions.

eport\Appendix\Appendix D Michigan Operations Control Technologies 7 Dl)Ier.xls

.

30f4

1212112006
148

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

No operating commercial Electron beam irradiation in the presence of ammo

32 Electron (E-Beam) Process No applications on coal conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ESP 

Similar to cold plasma.

Utilizes a reactor in which S02' NOx, and mercur

Will keep watch for dioxide (N02), sulfuric acid, and mercuric oxide r

33 Electrocatalytic Oxidation No availability ofthis plasma.

technology On recent project, the vender was doing final trial

Commercial version of Uses a regenerable sorbent to simultaneously adso

34 NOXSO No adsorption. Limited from utility and industrial boilers. In the 

experience to a saleable sulfur by-product (liquid SOz, elemen

concept tests). the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, supp

Absorption and SCR. alumina, to fonn copper sulfate. Ammonia is injec

absorption reactor and a selective catalytic 

35 No e,·. ExperitmceJimited to pilot reduces the nitric oxides in the flue gas. In the reg

scale. sulfate is reduced in a regenerator with a reducing 

producing a concentrated stream ofS02.

36 Cold Plasma No Research Level

Gas stream is passed through a filter medium ofs

37 Biofilters No Research level adsorbed and degraded by microbial metabolism 

dioxide and water.

Gas stream is passed through a filter baghouse in 

38 Pahlman Process No Research Level area metal oxide sorb

Pollutants are removed from the gases by adsor ti

I) This number is for reference only. It does not in any way rank the control technologies.

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogaptil/inodule6/index.htm

c) New and Emerging Environmental Technologies, http://neet.rti.orgl

d) ND BART Reports

Y:\22\52\080 Tilden BART\8ART report\Appendix\Appendix 0 Michigan Operations Control Technologies,. Dryer,xis

NOx Dryer
149

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the fonnation ofN1 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx fonnation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature

recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tem erature

Need capacity of all Shut offthe fuel flow from one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No bU111ers for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create fuel-rich and fuel-leal). zones

Palt ofthe total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes Yes primary (main burners) flames to create a reducing atmosphere (re-bum zone),

where hydrocarbon radicals react with NOx to produce elemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the electrical demand through efficiency projects,

Yes Yes Yes Yes Decrease amount offuel re uired to make an acce table roduet

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned. Specific energy efficiency project

Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

port\Appendix\Appendix 0 -Michigan Operations Control Technologies - Process Boilers.xls

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NOx Control

Process Boilers

Available and Applicable Review 

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Altemate Fuels Yes Yes Yes required by facilities experience lower using a fuel with less nitrogen. BART) NOx when burning solid

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and fuel-

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination afCFA and SCR. Wall-fired or tan

18 ROFA-ROTAMIX Yes Yes Yes Yes the scenario that combines utilizes high velocity overfire air. Additional NO

OFA and SCR ammonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissionsCurrent equipment cannot

20 Parametric Monitoring Yes Yes Yes No he tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into th

38 No Research Level to the combustion site, initiating chemical reacti

(EPS Technologies) the flame.

Catalytic For clean services. Too Under near stoichiometric conditions, in the pre

21 Reduction (NSCR) Yes Yes Yes Yes much debris in flue gas reduced by CO, resulting in nitrogen (N2) and ca

would poison catalyst

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix 0 - Michigan Operations Conlrol Technologies Process Boilers.xls

NOx Process Boilers
151

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx

Has been included as an

Yes No "innovative" technology in Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

recent BACT analyses NOx

from multiple facilities.

Need to inject at

Yes Yes Yes Yes appropriate temperature. Ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst to 

Applicable to clean convert NOx into N2 and water

services.

For clean services. Too

Yes No much debris in flue gas

would poison catalyst

Yes Yes Yes Yes Urea or ammonia-based chemicals are injected into the flue gas stream to convert 

NO to molecular nitrogen, N2, and water

No Still in research stages. Usc of char activated carbon to adsorb oxides ofnitro en

Yes Yes No Similar to TriNOx Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Yes Yes Yes Yes Redundant to regenerative Gas stream is sent through the regenerative, recuperative, catalytic or direct fired SCR oxidizer where pollutants are heated to a combustion point and destroyed.

port\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review 

30

31

32

33

34

3S

36

SNOX

SOx-NOx-Rox-Box

Electron (E-Beam) Process

Electrocatalytic Oxidation

NOXSO

Copper-Oxide

Cold Plasma

No

NoNo

NoNo

NoNo

Early commercial

stage

Technology has not been

demonstrated

No operating commercial

applications on coal

Similar to cold plasma.

Will keep watch for

availability ofthi5

Commercial version of

adsorption. Limitedexperience

concept tests).

Absorption and SCR.

Experience limited to pilot

scale.

Research Level

Catalytic reduction ofNOx in the presence of am

catalytic oxidation of S02 to S03' The exit gas fr

through a novel glass-tube condenser in which th

vapor and then condensed to a concentrated liqu

Dry sorbent injection upstream ofthe baghouse f

injection upstream of a zeolitic selective catalytic 

incorporated in the baghouse to reduce NOx emi

Electron beam irradiation in the presence of amm

conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ES

Utilizes a reactor in which S02' NOx, and mercu

dioxide (N0z), sulfuric acid, and mercuric oxide 

plasma.

On recent project, the vender was doing final tri

Uses a regenerable sorbent to simultaneously ad

fi'om utility and industrial boilers. In th

to a saleable sulfur by-product (liquid S02, elem

the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, sup

alumina, to fonn copper sulfate. Ammonia is injabsorption reactor and a selective catalytic reduc

reduces the nitric oxides in the flue gas. In the re

sulfate is reduced in a regenerator with a reducin

producing a concentrated stream of S02'

Y:\22\52\OBO Tilden BART\BART report:\Appendlx\Appendix 0 Michigan Operations Control Technologies Process Boilers.xis

NOx Process Boilers
153

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

NoNo

Research level

Research Level

Gas stream is passed through a filter medium ofsoil and microbes. Pollutants are

adsorbed and degraded by microbial metabolism forming the products carbon

dioxide and water.

Gas stream is passed through a filter baghouse in which specially-developed,

small-particle, high-surface area metal oxide sorbent have been deployed.

Pollutants are removed from the gases b adsor tion.

nly. It does not in any way rank the control technologies.

d Control. Wark, Kenneth; Wamer, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

Environmental Science, Module 6, http://www.epa.gov/eogaptillmodule6/index.htm

mental Technologies, http://neet.rti.org!

eport\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes Yes Yes Combustion air is separated into primary and secondary flow sections to achieve complete burnout and to encourage the fonnation ofN1 rather than NOx

Yes Yes Yes No Mixes flue gas with combustion air which reduces oxygen content and therefore 

reduces flame temperature

Yes Yes Yes Yes Burners are designed to reduce NOx fonnation through restriction ofoxygen, flame temperature, and/or residence time

Need to be upfired. Need 

Yes Yes Yes Yes convective loop to get gas Draws flue gas to dilute the fuel in order to reduce the flame temperature

recirculated

Yes Yes Yes Yes Reduces roduction Reduces ox en content in flue as and reduces flame tem erature

Need capacity of all Shut offthe fuel flow from one burner or more to create fuel rich and fuel lean 

Yes Yes Yes No bU111ers for worst case 

scenario zones

Yes Yes Yes No Combustion is staged by diverting fuel from the upper level burners to the lower ones or from the center to the side burners to create fuel-rich and fuel-leal). zones

Palt ofthe total fuel heat input is injected into the furnace in a region above the

Yes Yes Yes Yes primary (main burners) flames to create a reducing atmosphere (re-bum zone),

where hydrocarbon radicals react with NOx to produce elemental nitrogen

Yes Yes No This is a strategy to reduce load on a power plant by reducing the electrical demand through efficiency projects,

Yes Yes Yes Yes Decrease amount offuel re uired to make an acce table roduet

Yes Yes No Requires available excess Dry coal will increase the as-burned BTU value, and therefore less fuel is required heat. to be burned. Specific energy efficiency project

Yes Yes No Could reduce load Cooling ofthe primary flame zone by heat transfer to surrounding surfaces capabilities

port\Appendix\Appendix 0 -Michigan Operations Control Technologies - Process Boilers.xls

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NOx Control

Process Boilers

Available and Applicable Review 

Requires case by case

Yes (not analysis. Typically, Lower combustion temps with solid fuels vs gas. 

15 Altemate Fuels Yes Yes Yes required by facilities experience lower using a fuel with less nitrogen. BART) NOx when burning solid

fuels.

16 Oxygen Enhanced No Research level A small fraction ofthe combustion air is replaced 

Combustion

Pulverized coal preheated and volatiles and fuel-

17 Preheat Combustion No Research level released in a controlled reducing atmosphere wh

reduced to Nz.

This is addressed through Combination afCFA and SCR. Wall-fired or tan

18 ROFA-ROTAMIX Yes Yes Yes Yes the scenario that combines utilizes high velocity overfire air. Additional NO

OFA and SCR ammonia injection (Rotamix)

Current equipment cannot

19 NOxCEMS Yes Yes Yes No be tuned to impact NOx Optimization of combustion

emissionsCurrent equipment cannot

20 Parametric Monitoring Yes Yes Yes No he tuned to impact NOx Optimization of combustion

emissions

Catalyst Injection

A combustion catalyst is directly injected into th

38 No Research Level to the combustion site, initiating chemical reacti

(EPS Technologies) the flame.

Catalytic For clean services. Too Under near stoichiometric conditions, in the pre

21 Reduction (NSCR) Yes Yes Yes Yes much debris in flue gas reduced by CO, resulting in nitrogen (N2) and ca

would poison catalyst

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix 0 - Michigan Operations Conlrol Technologies Process Boilers.xls

NOx Process Boilers
156

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

Yes Yes No Requires ozone generation Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx

Has been included as an

Yes No "innovative" technology in Utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

recent BACT analyses NOx

from multiple facilities.

Need to inject at

Yes Yes Yes Yes appropriate temperature. Ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst to 

Applicable to clean convert NOx into N2 and water

services.

For clean services. Too

Yes No much debris in flue gas

would poison catalyst

Yes Yes Yes Yes Urea or ammonia-based chemicals are injected into the flue gas stream to convert 

NO to molecular nitrogen, N2, and water

No Still in research stages. Usc of char activated carbon to adsorb oxides ofnitro en

Yes Yes No Similar to TriNOx Use of water, hydroxide and carbonate solutions, sulfuric acid, organic solutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.

Yes Yes Yes Yes Redundant to regenerative Gas stream is sent through the regenerative, recuperative, catalytic or direct fired SCR oxidizer where pollutants are heated to a combustion point and destroyed.

port\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review 

30

31

32

33

34

3S

36

SNOX

SOx-NOx-Rox-Box

Electron (E-Beam) Process

Electrocatalytic Oxidation

NOXSO

Copper-Oxide

Cold Plasma

No

NoNo

NoNo

NoNo

Early commercial

stage

Technology has not been

demonstrated

No operating commercial

applications on coal

Similar to cold plasma.

Will keep watch for

availability ofthi5

Commercial version of

adsorption. Limitedexperience

concept tests).

Absorption and SCR.

Experience limited to pilot

scale.

Research Level

Catalytic reduction ofNOx in the presence of am

catalytic oxidation of S02 to S03' The exit gas fr

through a novel glass-tube condenser in which th

vapor and then condensed to a concentrated liqu

Dry sorbent injection upstream ofthe baghouse f

injection upstream of a zeolitic selective catalytic 

incorporated in the baghouse to reduce NOx emi

Electron beam irradiation in the presence of amm

conversion ofsulfur and nitrogen oxides into com

collected by conventional methods such as an ES

Utilizes a reactor in which S02' NOx, and mercu

dioxide (N0z), sulfuric acid, and mercuric oxide 

plasma.

On recent project, the vender was doing final tri

Uses a regenerable sorbent to simultaneously ad

fi'om utility and industrial boilers. In th

to a saleable sulfur by-product (liquid S02, elem

the NOx is converted to nitrogen and oxygen.

S02 in the flue gas reacts with copper oxide, sup

alumina, to fonn copper sulfate. Ammonia is injabsorption reactor and a selective catalytic reduc

reduces the nitric oxides in the flue gas. In the re

sulfate is reduced in a regenerator with a reducin

producing a concentrated stream of S02'

Y:\22\52\OBO Tilden BART\BART report:\Appendlx\Appendix 0 Michigan Operations Control Technologies Process Boilers.xis

NOx Process Boilers
158

Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Process Boilers

Available and Applicable Review DRAFT

Revised: December 1, 2006

NoNo

Research level

Research Level

Gas stream is passed through a filter medium ofsoil and microbes. Pollutants are

adsorbed and degraded by microbial metabolism forming the products carbon

dioxide and water.

Gas stream is passed through a filter baghouse in which specially-developed,

small-particle, high-surface area metal oxide sorbent have been deployed.

Pollutants are removed from the gases b adsor tion.

nly. It does not in any way rank the control technologies.

d Control. Wark, Kenneth; Wamer, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

Environmental Science, Module 6, http://www.epa.gov/eogaptillmodule6/index.htm

mental Technologies, http://neet.rti.org!

eport\Appendix\Appendix 0 - Michigan Operations Control Technologies Process Boilers.xls

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Cleveland Cliffs Michigan Operations· Taconite BART Analysis

502 Control

Indurating Furnaces

Available and Applicable Review

2 y y y y <50% Absorption aud reaction using all a

Wet Scrubbing (High

__

-1f + -/- If-

__

---11---------------f------------

Wet Scrubbing (Low

Efficiency)

Wet Walled Electrostatic

Preci itator (WWESP) y y y y 80% Suspcnded particles are scparated 

collected in ho ers

4 Dry sorbent injection y y y y <55%

Pulverized lime or limestone is dir

fabric filter, Dry sorption of S02 o

solid particles arc collectedwitlt a 

5 Spray Dryer Absorption

6 Allemative Fuels

7 Load Reduction

8 Energy Efficiency Projects

9 Coal Processing

10 Bio Filters

y

y

N

y

y

N

y

yy

N

y

y

(for furnaces

capable of

multiple fLlels)

y

(for large

projects

heat-recou

y

y

(not required

by BART)

y

(for large

prqjects.llke

<90%

Site-specific Natural gas is base case

Powcr plant technology

Site-specific

Applies only to facilities tllat burn coal

level

Use a fuel with lower sulfur conte

Tbis is a strategy to rcduce load al

demand thrall htcfficienc ro·ccdecrease amount offuel required 

Dry coal will increase the as-bunte

to be bunted, 8 ecific ener effi

Gas stream passes through a pack

supports tlte growth of active bact

are biodegraded or biotransfonned 

dioxide, water, clilor

II CANSOLV Regenerable S02 N Research level

All aqueous solution ofproprietar

countercurreut absorption tower. T

stripping, giving a byproduct of pu

recycling to the a

12 Pahlman Process N Rcsearch level

Gas stream is passed through a fil

particlc, high·surface area metal o

removed from the gascs by adso 

13 SOx-NOx-Rox-Box N Teclmology has not been demonstrated

Dry sorbcnt injection npstream of

injection upstream of a zeolitic se

incorporated in tlte bagltouse to re

Y:\22\52\080 Tilden BART\BART repor1\Appendix\Appendix D· Michigan Operations Control Technologies _Furnaces.xls

502 Tables - Furnace
160

Cleveland Cliffs Michigan Operations· Taconite BART Analysis

502 Control

Indurating Furnaces

Available and Applicable Review

Revised: December 1, 2006

No operating commercial applications all

coal

Similar to cold plasma. Will keep watch fa

availability Ofl11is technology

Commercial version of adsorption. Limited

experience (proof-of-concept tests).

Absorption and SCR. Experience limited to

pilot scale.

arly commercial development stage

Electron beam irradiation in the presence of ammonia to initiate chemical

conversion ofsulfur and nitrogen oxides into components wl\ic1\ can be easily

collected by conventional methods such as an ESP or baghouse.

Utilizes a reactor in whic1\ S02' NOll, and mercury are oxidized to nitrogen

dioxide (N02), sulfuric acid, and mercuric oxide respectively using lloll-thenllal

plasma.

On recent project, the vender was doing fInal trials all full-scale applications.

Uses a regenerable sorbent to simultaneously adsorb S02 and NOx from flue gas

from coal-fired utility and industrial boilers. In the process, die S02 is converted t

a saleable sulfilr by-product (liquid S02, elemental sulfur, or sulfuric acid) and the

NO,

S02 in the flue gas reacts witll copper oxide, supported on small spheres of

alumina, to fonn copper snlfate. Ammonia is injected into the flue gas before the

absorption reactor and a selective catalytic reduction-type reaction occurs that

reduces the nitr

Catalytic reduction ofNOx in the presence of ammonia (NHl ), followed by

catalytic oxidation ofS02 to SOl' The exit gas from the S03 converter passes

through a novel glass-tube condenser in which the S03 is hydrated to H2S04 vapor

and then condensed to a

h level

es not in any way rank the control tcclmologies.

Wark, Kennetll; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Tuc.

mental Science, Module 6, http://www.epa.gov/eogaptillmodllle6/index.1Jtm

echnologies, llttp:llncet..rti.orgl

Appendix o· Michigan Operations Control Technologies - Furnaces.xls

20f2

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Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

Combustion Controls

1 Overfire Air (OFA) Yes Yes Yes Yes Combustion air is separated into primary an

complete burnout and to encourage the form

2 External Flue Gas Recirculation (EFGR) Yes Yes Yes No Mixes flue gas with combustion air which 

reduces flame temperature

3 Low-NOx Burners Yes Yes Yes Yes Burners are designed to reduce NOx forma

flame temperature, and/or residence time

4 Induced Flue Gas Recirculation Burners Yes Yes Yes Yes Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in order to 

5 Low Excess Air Yes Yes Yes Yes Reduces production Reduces oxygen content in flue gas and red6 Burners out of Service (BOOS) Yes Yes Yes No Need capacity of all burners for worst case scenario Shut off the fuel flow from one burner or m

zones

7 Fuel Biasing Yes Yes Yes No Combustion is staged by diverting fuel from 

ones or from the center to the side burners 

8 Reburning Yes Yes Yes No

Part of the total fuel heat input is injected iprimary (main burners) flames to create a rwhere hydrocarbon radicals react with NOx 

9 Load Reduction Yes Yes No --- This is a strategy to reduce load on a power 

demand through efficiency projects.

10 Energy Efficiency Projects Yes Yes Yes Yes Decrease amount of fuel required to make 

11 Coal Drying Yes Yes No --- Requires available excess heat. Dry coal will increase the as-burned BTU v

required to be burned. Specific energy effi

14 Combustion Zone Cooling Yes Yes No --- Could reduce load capabilities Cooling of the primary flame zone by heat 

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

161
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

15 Alternate Fuels Yes Yes Yes

Yes (not 

required by 

BART)

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

Lower combustion temps with solid fuels vusing a fuel with less nitrogen.

16 Oxygen Enhanced Combustion No --- --- --- Research level A small fraction of the combustion air is re17 Preheat Combustion No --- --- --- Research level

Pulverized coal preheated and volatiles and released in a controlled reducing atmospherreduced to N2.

18 ROFA-ROTAMIX Yes Yes Yes Yes

This is addressed through the scenario that combines OFA and SCR

Combination of OFA and SCR. Wall-fired utilizes high velocity overfire air. Additionaammonia injection (Rotamix)

19 NOx CEMS Yes Yes Yes No

Current equipment cannot be tuned to impact NOx emissions

Optimization of combustion

20 Parametric Monitoring Yes Yes Yes No

Current equipment cannot be tuned to impact NOx emissions

Optimization of combustion

38 Catalyst Injection (EPS Technologies) No --- --- --- Research Level A combustion catalyst is directly injected in

to the combustion site, initiating chemical rthe flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Yes Yes Yes Yes Not as efficient as other control technologies Under near stoichiometric conditions, in th

reduced by CO, resulting in nitrogen (N2) a

22 Low Temperature Oxidation (LTO) - Tri-NOx® Yes Yes No --- Requires ozone generation Utilizes an oxidizing agent such as ozone to 

NOx

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

162
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

23 Low Temperature Oxidation (LTO) - LoTOx Yes No --- --- Has been included as an "innovative" technology in recent BACT analyses 

from multiple facilities.

Utilizes an oxidizing agent such as ozone to NOx

24 Selective Catalytic Reduction (SCR) Yes Yes Yes Yes

Need to inject at appropriate temperature. Applicable to clean services.

Ammonia (NH3) is injected into the flue ga

to convert NOx into N2 and water

25 Regenerative SCR Yes No --- --- For clean services. Too much debris in flue gas 

would poison catalyst

26 Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes Yes Urea or ammonia-based chemicals are inje

NO to molecular nitrogen, N2, and water

27 Adsorption No --- --- --- Still in research stages. Use of char (activated carbon) to adsorb ox28 Absorption Yes Yes Yes Yes Similar to TriNOx Use of water, hydroxide and carbonate solu

molten alkali carbonates, or hydroxides to a

29 Oxidizer Yes Yes Yes Yes Redundant to regenerative SCR Gas stream is sent through the regenerative

oxidizer where pollutants are heated to a co

30 SNOX No --- --- --- Early commercial development stage

Catalytic reduction of NOx in the presence 

catalytic oxidation of SO2 to SO3. The exit 

through a novel glass-tube condenser in wh

vapor and then condensed to a concentrated 

31 SOx-NOx-Rox-Box No --- --- --- Technology has not been demonstrated Dry sorbent injection upstream of the bagh

injection upstream of a zeolitic selective caincorporated in the baghouse to reduce NO

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xlsNOx Dryer

163
Cleveland Cliffs Michigan Operations BART Analysis

NOx Control

Dryer

Available and Applicable Review

Step 1 Step 2

This table is part of the CCMO Process 

be distributed without the full text of t

not taken out 

Reference No.

1

NOx Pollution Control 

Technology 2 

Is this a 

generally 

available 

control 

technology?

Is the control 

technology 

available to 

power boilers?

Is the control 

technology 

applicable to 

this specific 

source?

Is it technically 

feasible for this 

source?

Comments Basic Pri

2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix D Michigan Operations Control Technologies - Dryer.xls

NOx Dryer

164
Appendix E Summary of Relevant Economic Feasility ($/ton) Control Costs 

Appendix E Clean Air Interstate Rule (CAIR), Cost-Effecti

Comments

Reference Regulatory Body/Rule SO2 NOx SO2 NOx

BART 100 to 1000 100 to 1000 70 FR 39135BART 281 to 1296 70 FR 39135 Table BART 919 70 FR 39133BART Guidelines dispara

dollars per ton" in cexceed MACT and 

70_FR_25210_CAIR.pdf CAIR 1300 Estimated Margina

BART(proposed rule) 200-1000

BART proposed lis

SO2 control, which lb/MMBtu. Droppeflexibility to require bypasses aren't BABART.

BART(proposed rule)

0.2 lb/MMBtu for N

Recognizes that so

get this level. For t

cost vs. visibility va

CAIR(using IPM) 1000 1500CAIR ( 2009 in 1999$) 900 2400CAIR ( 2015 in 1999$) 1800 3000CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100

This was modeled 

Retrofitting Updatinmarginal values.

Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000

LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000

954-1134 was rule

for SO2. This did cSections XVII to XI

WRAP 3000EPA - Referenced by Wrap

References EPA-6

<$500/ton, Moderaover $3000/ton

WRAP_Trading_program_methodology.pdf

Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)

MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdf

Y:\22\52\080 Tilden BART\BART report\Appendix\Appendix E - Table of Costs_per_ton.xls

165
DRAFT – BART Analysis Procedures 8/29/2006 

P:\22-52\CCMO BART\BART General Documents\BART Analysis Procedures.doc 

1

1. 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 

visibility-impairing 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 particulate matter (PM), PM10, 

PM2.5, sulfur dioxide (SO2), nitrous oxide (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. EPAapproved visibility model is necessary to make a definitive visibility impairment 

determination (>0.5 deciviews). Sources that do not cause or contribute to visibility 

impairment are exempt from BART requirements, even if they are BART-eligible. 

2. 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 

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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.1 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.2

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: 

 

1

 40 CFR 51 Appendix Y 

2

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

undergoing the BART analysis? 

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

specific source “if it has reached the stage of licensing and commercial 

availability.3” However, the U.S. EPA further states that they “do not 

expect a source owner to conduct extended trials to learn how to apply a 

technology on a totally new and dissimilar source type.4” 

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

which is undergoing the BART analysis? 

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

question 1, “will be presumed applicable if it has been used on the same or 

a similar source type.5” 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 pollutantbearing stream and comparing them to the gas stream characteristics of the 

source types to which the technology has been applied previously.6” 

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

technology not technically feasible? 

This question addresses specific circumstances that “preclude its 

application to a particular emission unit.” This demonstration typically 

includes an “evaluation of the characteristics of the pollutant-bearing gas 

stream and the capabilities of the technology7.” This also involves the 

identification of “un-resolvable technical difficulties.” However, when the 

technical difficulties are merely a matter of increased cost, the technology 

 

3

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

4

 IBID 

5

 IBID 

6

 IBID 

7

 IBID 

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should be considered technically feasible and the technological difficulty 

evaluated as part of the economic analysis8. 

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 guarantees9. 

Step 3 - Evaluate Control Effectiveness 

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

at the expected emission rate (post-control) as compared to the emission rate 

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

Step 4 - Evaluate Impacts and Document Results 

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

remaining control technology option. The economic analysis compares dollar 

per ton of pollutant removed for each technology. In addition, it includes 

incremental dollar per ton cost analysis to illustrate the economic effectiveness 

of one technology in relation to the others. Finally, step four includes an 

assessment of energy impacts and other non-air quality environmental impacts. 

Step 5 - Evaluate Visibility Impacts 

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

models such as CALPUFF. The modeling protocol10, including receptor grid, 

meteorological data, and other factors used for this part of the analysis were 

provided by the MDEQ. The model outputs, including the 98th percentile 

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

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

the degree of improvement that can be reasonably attributed to each technology. 

 

8

 IBID 

9

 IBID 

10 LADCO. March 21, 2006. Single Source Modeling to Support Regional Haze BART Modeling Protocol. 

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

steps 1 through 5. In addition, the U.S. EPA 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.11

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 

time12.” 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 

basis13;” which could include the incorporation of other regulatory requirements for the 

source, including Compliance Assurance Monitoring (40 CFR 64), Periodic Monitoring (40 

CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If technological or 

economic limitations make measurement methodology for an emission unit infeasible, the 

 

11 Federal Register 70, No. 128 (July 6, 2005): 39171.

12 Federal Register 70, No. 128 (July 6, 2005): 39172.

13 IBID. 

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BART limit can “instead prescribe a design, equipment, work practice, operation standard, or 

combination of these types of standards14.” 

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

approval of the Michigan SIP. 

 

14 IBID. 

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DRAFT BART Eligible Emission Units Subject to a Streamlined BART Analysis 

1.0 Indurating Furnaces (PM Only) 

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

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

indurating furnaces are subject to the taconite Maximum Achievable Control Technologies 

(MACT) standard [40 CFR Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing] for the 

PM emissions. In 40 CFR Part 51 Appendix Y paragraph IV.C., it states: 

For VOC and PM sources subject to MACT standards, States may streamline the analysis 

by including a discussion of the MACT controls and whether any major new technologies 

have been developed subsequent to the MACT standards. We believe that there are many 

VOC and PM sources that are well controlled because they are regulated by the MACT 

standards, which EPA developed under CAA section 112. For a few MACT standards, 

this may also be true for SO2. Any source subject to MACT standards must meet a level 

that is as stringent as the best-controlled 12 percent of sources in the industry. Examples 

of these hazardous air pollutant sources which effectively control VOC and PM emissions 

include (among others) secondary lead facilities, organic chemical plants subject to the 

hazardous organic NESHAP (HON), pharmaceutical production facilities, and 

equipment leaks and wastewater operations at petroleum refineries. We believe that, in 

many cases, it will be unlikely that States will identify emission controls more stringent 

than the MACT standards without identifying control options that would cost many 

thousands of dollars per ton. Unless there are new technologies subsequent to the 

MACT standards which would lead to cost effective increases in the level of control, 

you may rely on the MACT standards for purposes of BART.(emphasis added)

It is clear from EPA’s guidance that they are encouraging states to develop a streamlined BART 

analysis approach for sources regulated under a MACT. Since the Taconite MACT standard was 

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

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

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

2.0 Taconite MACT Emission Units (PM-Only) 

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]. 

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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 U.S. EPA guidance. 

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

3.0 Process Boiler MACT Emission Units (PM-Only) 

Similarly to sources subject to the Taconite MACT, a taconite processing facility has many 

process boilers subject to the Boiler MACT. Since the MACT standard was established recently 

and will become effective in 2007, 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 

U.S. EPA guidance. 

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

4.0 Process Boiler Emission Units (NOx and SO2) 

It is important to note that the emissions from the indurating furnaces represent the vast majority 

of emissions of all visibility impairing pollutants, with the process boiler emission units typically 

contributing less than 1% of the total emissions of each pollutant from sources that are subject to 

BART. The emissions from all the remaining sources are small relative to the total emissions 

that are subject to the BART standard. Additional control of these sources can be presumed to 

have minimal impact on visibility improvement in Class I areas. Each facility will conduct an 

analysis for the remaining sources to demonstrate that the impact on visibility is negligible. The 

procedure for the analysis is detailed in section 5 of this document. Assuming that the modeling 

demonstrates that the sources have a negligible impact on visibility in Class I areas, no further 

analysis will be required to establish BART for these sources. 

5.0 Visibility Impact Modeling for Negligible Impacts 

As described in sections 3 and 4 of this document, each facility contains several process boilers 

that are assumed to have a negligible impact on visibility in Class I areas. In order to confirm 

this assumption, each facility will conduct a modeling analysis to determine the impact of the 

emissions from these sources on visibility in Class I areas. The analysis will consist of the 

following: 

A. Conduct air dispersion modeling for uncontrolled BART-eligible emission unit, as 

described in sections 3 and 4 above. The modeling will be conducted based on the 

guidance document Single Source Modeling to Support Regional Haze BART 

Modeling Protocol dated March 21, 2006 as prepared by Lake Michigan Air 

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Directors Consortium (LADCO). One modeling analysis will be conducted for each 

facility. 

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

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

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

assessed over the 3-year period 2002-2004. 

C. If the modeled emission sources result in a 98th percentile change in visibility less 

than or equal to 0.05 deciviews, the point sources will be considered to not cause or 

contribute to visibility impairment in Class I areas. Therefore, the existing operations 

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

these sources. 

D. If the modeled emissions result in a 98th percentile change in visibility greater than or 

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

sources. 

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