# United Taconite Analysis of Best Available Retrofit Technology (BART)

Table of Contents

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

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

2.B BART Determinations ................................................................................................................3

3. Streamlined BART Analysis ...................................................................................................... ..........9 3.A Indurating Furnaces ....................................................................................................................9

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

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

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

3.E Other Combustion Units ......................................................................................................... ..11

3.F Visibility Impact Modeling for Negligible Impacts..................................................................12

4. Baseline Conditions and Visibility Impa cts for BART Eligible Units ...............................................15 4.A MPCA Subject-to-BART Modeling .........................................................................................15

4.B Facility Baselin e Modeling ..................................................................................................... ..16

4.C Facility Baseline M odeling Results ..........................................................................................24

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

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

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

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

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 33

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

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

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

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

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

5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies................................................................................................ 54

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

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

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

6.B Post-Control Modeling Results.................................................................................................6 1

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

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# List of Tables

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

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

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

Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availa bility, Applicability, and Technical Feasibility.................................................................................................... 33

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness ......................................... 33

Table 5-3 Indurating Furnace SO 2 

# Control Cost Summary........................................................... 34

Table 5-4 SO 2 

# Control Technology Impacts Assessment ............................................................. 36

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

Table 5-6 Post-Control SO 2 

# Modeling Scenarios - Modeling Input Data ..................................... 39

Table 5-8 Post-Control SO 2 

# Modeling Scenarios - Visibility Modeling Results .......................... 41

Table 5-9 Post-Control SO 2 

# Modeling Scenarios - Visibility Improvements................................ 41

Table 5-10 Indurating Furnace NO
x 

# Control Technology – Availa bility, Applicability, and Technical Feasibility.................................................................................................... 54

Table 5-11 Indurating Furnace NO
x 

# Control Technology Effectiveness......................................... 54

Table 5-12 NO
x 

# Control Cost Summary......................................................................................... 55

Table 5-13 NO
x 

# Control Technology Impacts Assessment............................................................. 56

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

Table 5-15 Post-Control NO X 

# Modeling Scenarios – Emissions Data............................................ 58

Table 5-16 Post-Control NO X 

# Modeling Scenarios - Visibility Modeling Input Data .................... 59

Table 5-17 Post-Control NO X 

# Modeling Scenarios - Visib ility Modeling Results ......................... 60

Table 5-18 Post-Control NO X 

# Modeling Scenarios - Visibility Improvements .............................. 60

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

Table 6-2 Post-Control NO X 

# Modeling Scenarios - Modeling Input Data .................................... 64

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

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

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

List of Figures

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

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# List of Appendices

Appendix A Control Cost Analysis Spreadsheets
Appendix B Changes to MPCA BART Modeling Protocol
Appendix C Visibility Impacts Modeling Report
Appendix D Applicable and Av ailable Retrofit Technologies
Appendix E Clean Air Interstate Rule (CAI R), Cost-Effective Air Pollution Controls

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# 1. Executive Summary

United Taconite is located in northern Minnesota, with mining facilities near Eveleth, Minnesota.
United Taconite’s processing facilities are located near Forbes, Minnesota. This report describes the
background and methods for the selection of the Best Available Retrofit Technology (BART) as
proposed by United Taconite for its taconite processing plant located near Forbes, MN.

MPCA identified approximately 70 pie ces of equipment at United Taconite that were installed within
the time window (1962-1977) that makes them subjec t to BART. The equipment includes two gratekiln indurating furnace lines. Line 1 is permitted fo r natural gas and fuel oil, but Line 2 also uses
coal and petroleum coke. Other equipment identified includes crushers, pellet coolers, combustion
units, fugitive sources, and materi al handling and/or storage units fo r ore, product, and additives.
Preliminary visibility modeling conducted by the Minnesota Pollution C ontrol Agency (MPCA)

found that air emissions from Unit ed Taconite’s facility “cause or contribute to visibility
impairment” in a federally protected Class I area, therefore making the facility subject to BART.

Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to
propose BART for the subject units. The existi ng pollution control equipment includes a wet
scrubber designed to control partic ulate matter (PM) ; however some collater al control of sulfur

dioxide (SO 2 

# ) is also achieved. A dispersion mode ling sequence of CALM ET, 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 th e above criteria, United Taconite proposes the following as BART:

• SO 2 

# emissions will be controlled by the existing scrubbers.

• NO
x 

# emissions will be controlled by the impl ementation of a heat re cuperation project on

Line 1.

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# • PM emissions will be controlled as prescribed by the taconite maximum achievable control
technology (MACT) standard 1



# .

CALPUFF model is conservative, resu lting in an over prediction of impacts. This modeled high
impact from the BART eligible sources is 4.7 dV, wh ich is slightly above per ceptible levels of one to
two dV. Real impacts to the Class I areas from United Taconite are expected to be even less than
these modeled impacts.

The proposed BART controls will reduce the facility ’s visibility impact by 0.7 dV, an improvement
of 15%, on the worst visibility days. This represents a significant contribution to the default glide
path of reducing impacts by 1-2% per year.

1 

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

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# 2. Introduction

United Taconite is located in northern Minnesota, with mining facilities near Eveleth, Minnesota.
United Taconite’s processing facilities are located near Forbes, Minnesota. This report describes the
background and methods for the selection of the Best Available Retrofit Technology (BART) as
proposed by United Taconite for its taconite processing plant located near Forbes, MN.

To meet the Clean Air Act’s requirements, the U. S. Environmental Protection Agency (U.S. EPA)
published regulations to address visibility impair ment 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 Fe d. Reg. 39104 (July 6, 2005)] and is found in 40
CFR part 51, in 51.300 through 51.309.

Within its boundary, Minnesota has two Class I ar eas – the Boundary Waters Canoe Area Wilderness
and Voyageurs National Park. In addition, emissi ons from Minnesota may contribute to visibility
impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney
Wilderness Area. By December 2007, MPCA mu st submit to U.S. EPA a Regional Haze State
Implementation Plan (SIP) that identifies sources that cause or contribute to vi sibility 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 manda te a plan to achieve natural background visibility by 2064.
Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When
reviewing Figure 2-1, it is impor tant to note that Minnesota Steel Industries (MSI) and Mesabi
Nugget (Nugget), which are illustrated in the figure , are not currently in operation. The SIP must
also include milestones for establishing reasonable progress towards the visibility improvement goals
and plans for the first five-year period. Upon submis sion of the Regional Haze SIP, states must make
the requirements for BART sources enforceable through rules, admi nistrative orders or Title V
permit amendments.

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# Figure 2-1 Minnesota’s BART Geography The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary Waters Canoe Area (BWCA)] and BART-eligible units illustrated above. (Source MPCA BART-Strategy October 4, 2005)



# By U.S. EPA’s definition, reasonable progress mean s that there is no degradation of the 20 bestvisibility days, and the 20 worst-visibility days must have no more visibility impairment than the 20
worst days under natural conditions by 2064. 2 

# Assuming a uniform rate of progress, the default glide
path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state
must submit progress reports every five years to establish their advancement toward the Class I area
natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a
slower rate of improvement may be proposed on the basis of cost or time required for compliance and
non-air quality impacts.

Note that the improvements required under the Regional Haze regulations are different from the
BART requirements. Facilities subject to BART are not required to make all of the reasonable

2 

# 70 FR No. 178 pp. 39104 to 39172.

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# progress towards improving regional haze in Clas s I areas. Rather, BART is but one of many
measures which states may rely upon in making “reasonable prog ress” 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 categorie s under the PSD rules
(e.g., taconite ore processing plants, fossil-fue l-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 we re not in operation be fore 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, PM 10 

# , PM 2.5 

# , SO 2 

# , NO
x 

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

Once BART eligibility is determined, a source must then determine if it is “subject to BART.” A
source is subject to BART if emissions “cause or contribute” to visibility impairment at any Class I
area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model
is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that

do not cause or contribute to visibi lity impairment are exempt from BART requirements, even if they
are BART-eligible.



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

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# for each source. The BART analysis takes into account six criteria and is analyzed using five steps.
The six criteria that comprise the engineering analysis include: the availability of the control
technology, existing controls at a facility, the cost of compliance, the remaining useful life of a
source, the energy and non-air quality environmenta l impacts of the technology, and the visibility
impacts. 3 

# The five steps of a BART analysis are:

Step 1 - Identify all Available Retrofit Control Technologies The first step in the analysis is to identify all retrofit control technologies which are
generally available for each applicable em ission unit. Availabl e retrofit control
technologies are defined by U.S. EPA in Ap pendix Y to Part 51 (Guidelines for BART
Determinations under the Regional Haze Rule) as follows:

Available retrofit techno logies are those air pollution control technologies
with a practical potential for applic ation to the emissions unit and the
regulated pollutant under evaluation. Air pollution control technologies can
include a wide variety of availabl e 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 app lied to similar source categories or gas
streams. Technologies which have not ye t 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 constr uct a process or control device that
has not been demonstrated in practice. 4



# Step 2 - Eliminate Technically Infeasible Options In the second step, the source-specific technical feasibility of each control option
identified in step one is evaluated by answering three specific questions:

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

3 

# 40 CFR 51 Appendix Y

4 

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

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# The U.S. EPA states that a control technique is considered “available” to a specific
source “if it has reached the stage of licensing and commercial availability. 5 

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

conduct extended trials to learn how to apply a technology on a totally new and
dissimilar source type. 6 

# ”

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

In general, a commercially available cont rol technology, as defined in question 1,
“will be presumed applicable if it has been used on the same or a similar source

type. 7 

# ” If a control technology has not been demonstrated on a same or a similar
source type, the technical feasibility is determined by “examining the physical and
chemical characteristics of the pollutant-bearing stream and comparing them to the
gas stream characteristics of the source types to which the technology has been
applied previously. 8 

# ”

c. Are there source-specific is sues/conditions that would make the control technology
not technically feasible?

This question addresses specific circumstances that “preclude its application to a
particular emission unit.” This demonstration typically includes an “evaluation of
the characteristics of the pollutant-bearing gas stream and the capabilities of the
technology 9 

# .” This also involves the identification of “un-resolvable technical
difficulties.” However, when the technical difficulties are merely a matter of
increased cost, the technology should be considered technically feasible and the
technological difficulty evaluated as part of the economic analysis 10



# .

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

5 

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

6 

# IBID

7 

# IBID

8 

# IBID

9 

# IBID

10 

# IBID

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# EPA does not consider as “sufficient justification that a control option or emission
limit is technically infeasible”. In gene ral, 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 guarantees 11



# .

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 th e 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 analys is 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 as sessment of energy impacts and other non-air
quality environmental impacts.

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

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

estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air
Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model

version 7.5 were used. Vendor cost estima tes for this project were used when
applicable. The source of the control equipment cost data are noted in each of the
control cost analysis worksheets as found in Appendix A.

Step 5 - Evaluate Visibility Impacts The fifth step requires a modeling analysis conducted with U.S. EPA -approved models
such as CALPUFF. The modeling protocol 12 

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

11 

# IBID

12 

## MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modelin g Protocol to Determine Sources Subject to BART in the State of Minnesota

.

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# visibility impairment at each of the Class I areas, are used to establish the degree of
improvement that can be reasonably attributed to each technology.

The final step in the BART analysis is to select the “best” alternative using the results of steps 1
through 5. In addition, the U.S. EPA and MPCA guidance states that th e “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 requiri ng 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 consid eration 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 operatio ns 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 sp ecific economic effects, parameters, and
reasoning. (We recognize that this review process must pres erve the confidentiality of
sensitive business information). Any analysis may also consider whether competing
plants in the same industry have been requi red to install BART controls if this
information is available. 13



# To complete the BART process, the analysis must “establish enforceable emission limits that reflect
the BART requirement s and requires compliance with in a reasonable period of time 14 

# .” Those limits
must be developed for inclusion in the state implem entation plan (SIP) that is due to U.S. EPA in
December of 2007. In addition, the analysis mu st include requirements that the source “employ
techniques that ensure compliance on a continuous basis 15 

# .” which could include the incorporation of
other regulatory requirements for the source, incl uding 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 m easurement methodology for an emission unit

13 

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

14 

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

15 

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

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# infeasible, the BART limit can “instead prescrib e a design, equipment, work practice, operation
standard, or combination of these types of standards 16 

# .”

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

the Minnesota SIP.

16 

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

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# 3. Streamlined BART Analysis

Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include
a streamlined approach for BART analyses 17 

# . The streamlined approach wi ll allow both states and the

facilities to focus their resources on the main cont ributors to visibility impairment. This section of
the report follows the MPCA-approved streamlined BART analysis for taconite facilities and
presents the results of the streamlined approach in Table 3-1.



# 3.A Indurating Furnaces
The indurating furnaces are sources of three visibility impairing pollutants: NO
x 

# , SO 2 

# , and PM.

Relative to NO
x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the indurating
furnaces are subject to the taconite MACT standard 18 

# for the PM emissions. MPCA’s guidance for
conducting a BART review states that “MPCA will rely on MACT standards to represent BART
level of control for those visibility impairing pol lutants 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 contro l.” [Attachment 2, March 2006, page 2]. Since the MACT standard
was established very recently and becomes effective in 2006, th e technology analysis is up-to-date.
As a result, BART will be presumed to be equivalent to MACT for PM.

A full BART analysis w ill be conducted for NO
x 

# and SO 2 

# where applicable.



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

# or SO 2 

# . The
Ore Crushing and Handling sources and the Finished Pellet Handli ng 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 re latively low concentration of particle

emissions [FR, December 18, 2002, page 77570]. Therefor e, the emissions from the pellet coolers
are considered to have a negligible impact on vi sibility impairment, and no control requirements

under the MACT standard is consistent wi th the intention of the BART analysis.

17 

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

18 

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

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

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



# 3.C Sources of fugitive PM that ar e subject to MACT standards

The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonMACT sources are addressed in section 3.D). These sources operate at ambient temperature, only

emit PM, and do not emit NO
x 

# or SO 2 

# . Taconite MACT fugitive s ources include the following:

• Stockpiles (includes, but is not limited to, st ockpiles of uncrushed ore, crushed ore, or finished pellets),

• Material Transfer Points,

• Plant Roadways,

• Tailings basins,

• Pellet loading areas, and

• Yard areas.

Control of emissions from these fug itive PM sources is maintained through a fugitive control plan, as
required by the MACT standard and as required by the facility’s Title V air permit. The fugitive
controls consist of primary cont rols, and contingent measures to prevent or mitigate fugitive PM
emissions. The controls and measures are site spec ific and are appropriate to seasonal and weather

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

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



# 3.D Non-MACT Units and Fugitive Sources (PM only)
A few sources of PM emissions and sources of fugi tive PM are not subject to a MACT standard.
They include units such as:

• Additive storage and handling

• Concentrate storage and handling

Considering all PM emissi ons which are subject to the BART standard, the PM emissions from the
above units typically represent less than 2.5% of PM emissions from the facility, which are subject to

BART. Relative to NO
x 

# and SO 2 

# , PM is not a major visibility impairing pollutant.

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# The point source emission units are typically controlled by baghouses, which achieve high levels of
control for PM. Since these units already have th e best control equipment for PM emissions, and

since the PM emissions from these sources are sm all relative to the total PM emissions that are
subject to the BART standard, addi tional control of these sources can be presumed to have minimal
impact on visibility improvement in Class I areas. For the controlled sources, existing controls will

be considered BART consistent with direction from MPCA in the May 18, 2006 meeting. No further
analysis will be required to esta blish BART for these sources.

The fugitive sources are controlled by measures de scribed in the fugitive control plan as required by
the facility Title V operating permit. Fugitive control plans are accepted as MACT and BACT for
fugitive sources, including the recent taconite MACT standard and a BACT determination made in
2006 for the mining industry. For the fugitive sources, the existing fugitive dust control plans will be
considered BART. No further analysis will be required to establish BART for these sources.



# 3.E Other Combustion Units
United Taconite has other combustion units that are subject to BART. The combustion units are
sources of three visibility impairing pollutants: NO
x 

# , SO 2 

# , and PM.

The remaining combustion sources co nsist of four small boilers (each less than 20 MMBtu/hr) and 10
heaters to warm work areas during cold weather. It is important to note that the emissions from the
indurating furnaces represent the vast majority of emissions of all visibili ty impairing pollutants,
with the other combustion units typically contributing less than 1% of the total emissions of each
pollutant from sources that are subject to BART. The emissions from all the remaining sources are
small relative to the total emissions that are subject to the BART standard. Additional control of
these sources can be presumed to have minimal impa ct on visibility improvement in Class I areas.
As directed by MPCA in the May 18, 2006 meeting, United Taconite conducted an analysis for the
remaining combustion sources to demonstrate that the impact on visibility is negligible (less than or
equal to 0.05 deciviews 19 

# ). The procedure for the analysis is detailed in section 3.F of this document.

The results of that modeling demonstrated that the vi sibility impact of those sources is equal to 0.05
deciviews. Therefore, the sources are considered to not cause or contribute to visibility impairment
in Class I areas. Therefore, the existing operations will be considered BART. No further analysis
will be required to estab lish BART for these sources.

19 

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

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# 11

# 3.F Visibility Impact Modeling for Negligible Impacts
As described in section 3.E of this document, this facility contains several sources that are assumed
to have a negligible impact on visibility in Class I areas. In order to confirm this assumption, a
modeling analysis was conducted to determine the impact of the emissions from these sources on
visibility in Class I areas. The an alysis consisted of the following:

(1) Conduct air dispersion modeling for uncontro lled BART-eligible emission units and
fugitive sources for the facility, as described in section 3.E above. The modeling was
conducted based on the guidance in the BA RT Modeling Guidance as prepared by
MPCA. One modeling analysis was conducted. The modeling was conducted on a
focused grid (as previously agreed to with MPCA) which is based on the facility
impacts as presented by MPCA in “Results of Best Available Retrofit Technology
(BART) Modeling to Determine Sources Subj ect-to-BART in the State of Minnesota”

(March 2006).

(2) Count the days with a 98 th 

# percentile (21 over 3-yrs, 7 each year) change in visibility
greater than or equal to 0.05 deciviews (bas ed on 10% of the facility threshold of 0.5

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

assessed over the 3- year period 2002-2004.

(3) If the modeled emission sources result in a 98 th 

# percentile change in visibility less
than or equal to 0.05 deciviews, the point and fugitive sources w ill be considered to
not cause or contribute to visibility impair ment in Class I areas. Therefore, the
existing operations will be considered BART. No further analysis will be required to

establish BART for these sources.

(4) If the modeled emissions result in a 98 th 

# percentile change in vi sibility greater than
0.05 deciviews, a full BART analysis wi ll be conducted on th e emission sources.

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# 12

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

Emission

Unit # Emission Unit Description VisibilityImpairing Pollutant 1 

# Existing Limit 1 

# gr/dscf Maximum Daily lbs/day 2



## 3.A Indurating Furnaces 40 Line 1 Pellet Induration PM 0.01 426.4 42 SV 048 Line 2 Pellet Induration PM 0.01 1932 42 SV 049 Line 2 Pellet Induration PM 0.01 1248 3.B PM-Only Taconite MACT Emission Units

1 Crude Ore Unloading Pan Feeders PM 0.008 43.2 2 SV008 Crude Ore Unloading PM 0.008 29.6 2 SV009 Crude Ore Unloading PM 0.008 33.6 4 Coarse Ore Surge Pan Feeders PM 0.008 18.1
5 Third Stage Crusher 1 PM 0.008 47.2 6 Third Stage Crusher 2 PM 0.008 0.0
7 Third Stage Crusher 3 PM 0.008 0.0 8 Third Stage Crusher 4 PM 0.008 0.0 9 Third Stage Crusher 5 PM 0.008 0.0 10 Third Stage Bins Conveyor PM 0.008 0.0
11 Fourth Stage Crusher 1 PM 0.008 180.0 12 Fourth Stage Crusher 2 PM 0.008 20.96 13 Fourth Stage Crusher 3 PM 0.008 264
14 Fourth Stage Crusher 4 PM 0.008 63.2 15 Fourth Stage Crusher 5 PM 0.008 0 16 Fourth Stage Crusher 6 PM 0.008 28.8
17 Fourth Stage Crusher 7 PM 0.008 0 18 Fourth Stage Crusher 8 PM 0.008 0 19 Fourth Stage Trip/Bin/Convey PM 0.008 0 20 Transfer House North PM 0.008 18.64 22 Transfer House South PM 0.008 18.48 23 No. 1 Rod Mill Feed PM 0.008 9.44
24 No. 2 Rod Mill Feed PM 0.008 25 No. 3 Rod Mill Feed PM 0.008 26.4 26 No. 4 Rod Mill Feed PM 0.008 0
27 No. 5 Rod Mill Feed PM 0.008 0 33 Line 2 Grate Feed PM 0.008 42.4 34 Line 2 Grate Discharge PM 0.008 128 35 Line 2 Kiln Cooler Discharge PM 0.008 22.96 35 Line 2 Kiln Cooler Discharge PM 0.008 68.8 35 Line 2 Cooler Discharge Vibrating feeders PM 0.008 7.84 36 Line 2 Pellet Cooler Exhaust PM 0.008 116.8 37 Line 1 Grate Feed PM 0.008 0 38 Line 1 Grate Discharge PM 0.008 0 39 SV 116 Line 1 Kiln Cooler Discharge PM 0.008 23.76 39 SV 045 Line 1 Kiln Cooler Discharge PM 0.008 24.64
41 Line 1 Pellet Cooler Exhaust PM 0.008 65.76 3.C Fugitive PM MACT Sources

FS 001 Unpaved Roads - coarse tailings to tailings basin PM Fug Control Plan

FS 002 Wind Erosion - Tailings Basin (Active Area) PM Fug Control Plan FS 005 Coarse Ore Surge Dump PM Fug Control Plan

FS 012 Unpaved Roads - light truck traffic around plant PM Fug Control Plan

FS 029 Fine Ore Surge (9F to 10 transfer) PM Fug Control Plan FS 030 Fine Ore Surge (10 to pile transfer) PM Fug Control Plan FS 031 Line 1 Pellet Transfer (21 to 21B) PM Fug Control Plan FS 033 Pellet Loadout Railcar loading PM Fug Control Plan FS 051 Line 1 Pellet transfer (21 to 22N/S) PM Fug Control Plan

3.D Non-MACT Emission Units and Fugitive Sources (PM-Only) 28 Limestone/Soda Ash Storage Bins PM 0.3 29 Additive Unloading PM 0.3 30 Line 2 Additive Storage Bins PM 0.3 31 Line 2 Additive Addition PM 0.3 FS 004 Wind Erosion - Concentrate Stockpile PM Fug Control Plan

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# 13

# Emission Unit # Emission Unit Description VisibilityImpairing Pollutant 1 

# Existing Limit 1 

# gr/dscf Maximum Daily lbs/day 2



## 3.E Other Combustion Units
51 Fairlane Truck Shop Boiler PM 0.6 3



## 52 Fairlane New Shop Boiler PM 0.6 3



## 53 Fuel Handling Boiler #1 PM 0.6 3



## 54 Fuel Handling Boiler #2 PM 0.6 3



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

## PM – Filterable PM only as measured by U.S. EPA Method 5 including the applicable averaging and grouping provisions, as presented in the MACT regulation, effective 10/30/2006.
2 

## Based on baseline flow rates.
3 

## 0.6 lbs/million Btu heat input

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# 14

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

As indicated in U.S. EPA’s final BART guidance 20 

# , 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 fac ility were estimated usi ng CALPUFF, an U.S. EPA
approved model recommended for comparing the visi bility improvements of different retrofit control
alternatives. However it is important to note that CALPUFF is a conservative model that over
estimates real impa cts. Therefore, although th e 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 NO
x 

# , SO 2, 

# PM 2.5 

# and PM 10 

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

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

first be modeled at baseline conditions. Per MP CA guidance, the baseline, or pre-BART conditions,
shall represent the average emission rate in uni ts of pounds per hour (lbs/hr) and reflect the

maximum 24-hour actual emissions 21



# .


# 4.A MPCA Subject-to-BART Modeling
In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA
completed modeling of the BART-eligible emission units at various facili ties in Minnesota in
accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF,

as detailed in the “Best Available Retrofit Te chnology (BART) Modeling Protocol to Determine
Sources Subject-to-BART in the State of Minnesot a,” finalized in March 2006. The modeling by
MPCA was conducted using em ission rate information submitted by the facility. The emissions were
reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions
during a 24-hour period under steady -state operating conditions dur ing periods of high capacity

20 

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

21 

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

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# 15

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

# 16 utilization. The results of the modeling were pres ented in the document titled “Results of Best

Available Retrofit Techno logy (BART) Modeling to Determine S ources Subject-to-BART in the

State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that
this facility is subject-to-BART.



# 4.B Facility Baseline Modeling
Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated.

On behalf of United Taconite and the other Minnes ota taconite facilities, Barr Engineering proposed
changes to the modeling protocol. The change s, as submitted to MPCA on May 16, 2006 are
presented in Appendix B.

In addition, the maximum 24-hour emis sion rates were re -ev aluated internally within United Taconite
to verify that the emission rates represent th e maximum steady-state op erating conditions during
periods of high capacity utilization. The maximu m 24-hour emission ra tes were adjusted to reflect
changes at the facility that occurred after the submittal of the information requested by MPCA and to
reflect combustion of permitted fuels.

An energy efficiency project was implemented on Line 1 to recoup waste heat in 2005 thereby
reducing natural gas fuel use on Line 1. The emissions of NO
x 

# from Line 1 were adjusted to
represent the new baseline conditions. Following implementation of this change, stack testing was
performed and the results indicate that NO
x 

# emissions were reduced by 46%.

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

summarized in Table 4-1. The full modeli ng analysis is presented in Appendix C.Table 4-1 Baseline Conditions Modeling Input Dataand the Basis for 24-hour Emissions DataEmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.EastingNorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)3.AIndurating Furnaces40Line 1PelletInduration4776Fueloil15,632Natgas426.446532024.985244399.881401,38210369,13712942Line 2PelletInduration8292Solidfuel22,872NatGas193248531995.035244364.981531,37112346,00012742Line 2PelletInduration6880SolidFuel25632NatGas124849531983.415244432.551531,37812380,0001153.BPM-Only Taconite MACT Emission Units1CrudeOreUnloading PanFeeders43.27531,8005,244,349401,3643.224,0006929.68531,8075,244,386141,3654.545,000632CrudeOreUnloading33.69531,7945,244,371141,3645.450,000774CoarseOreSurgePanFeeders18.110531,9065,244,763501,3653.218,000605ThirdStageCrusher147.211532,0245,244,6681911,3703.540,306776ThirdStageCrusher20.012532,0295,244,6631911,3703.540,30677C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc17EmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)7ThirdStageCrusher30.013532,0345,244,6591961,3703.540,306778ThirdStageCrusher40.014532,0395,244,6551961,3703.540,306779ThirdStageCrusher50.015532,0495,244,6462021,3703.540,3067710ThirdStageBinsConveyor0.016532,0535,244,6391961,3703.026,5217711FourthStageCrusher1180.017532,0015,244,6181461,3692.728,0006212FourthStageCrusher220.9618532,0135,244,6081461,3692.822,6477713FourthStageCrusher326419532,0215,244,6011461,3692.519,0006714FourthStageCrusher463.220532,0275,244,5961461,3702.519,2227715FourthStageCrusher5021532,0335,244,5911461,3702.520,0007716FourthStageCrusher628.822532,0375,244,5881501,3712.923,00076C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc18EmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)17FourthStageCrusher7023532,0445,244,5821501,3723.030,4027718FourthStageCrusher8024532,0505,244,5771501,3743.030,4027719FourthStageTrip/Bin/Convey025532,0575,244,5711501,3762.829,0027720TransferHouseNorth18.6426532,1495,244,545941,3812.825,6197722TransferHouseSouth18.4828532,1245,244,507971,3852.115,0007723No. 1Rod MillFeed9.4429532,2055,244,3591111,3862.013,2717724No. 2Rod MillFeed030532,1475,244,4072.025No. 3Rod MillFeed26.431532,2345,244,3341221,3873.128,0007726No. 4Rod MillFeed032532,2635,244,3101221,3863.126,9897727No. 5Rod MillFeed033532,2915,244,2871221,3853.126,9897733Line 2GrateFeed42.439532,0145,244,4081261,3804.130,0008134Line 2GrateDischarge12840531,9785,244,3681171,3714.230,00088C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc19EmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)35Line 2KilnCoolerDischarge22.9641531,9695,244,3331041,3694.845,0007435Line 2KilnCoolerDischarge68.870531,9335,244,3381241,3676.750,6678435Line 2CoolerDischargeVibratingfeeders7.8450531,9605,244,3241031,3682.06,40010036Line 2PelletCoolerExhaust116.842531,9585,244,3511361,37016.0298,00068537Line 1GrateFeed043532,0435,244,376921,3842.520,4278538Line 1GrateDischarge044532.0095,244,347961,3702.514,6127723.76116531,9925,244,31111513705.036,0008039Line 1KilnCoolerDischarge24.6445532,9715,244,3441001,3703.021,27310041Line 1PelletCoolerExhaust65.7647531,9935,244,3231151,37010.0349,2391,100C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc20EmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)3.CFugitive PM MACT Sources1UnpavedRoads -coarsetailingstotailingsbasin0.0NANANANA772WindErosion -TailingsBasin(ActiveArea)0.0NANANANA775CoarseOreSurgeDump0.0NANANANA7712UnpavedRoads -lighttrucktrafficaroundplant0.0NANANANA7729Fine OreSurge(9F to 10transfer)0.0NANANANA7730Fine OreSurge(10 topiletransfer)0.0NANANANA7731Line 1PelletTransfer(21 to21B)0.0NANANANA77C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc21EmissionUnit IDEmissionUnitDescriptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)Exit GasTemperature (F)33PelletLoadoutRailcarLoading0.0NANANANA7751Line 1PelletTransfer0.0NANANANA773.DNon-MACT Emission Units and Fugitive Sources(PM-Only)28Limestone/SodaAshStorageBins0.034532,0555,244,4141351,3862.03,7807729AdditiveUnloading0.035532,0725,244,398601,3872.28,8607730Line 2AdditiveStorageBins0.036532,0155,244,4471571,3821.74,2007731Line 2AdditiveAddition0.037532,0465,244,4251661,3853.014,000774WindErosion -ConcentrateStockpile0.0NANANANA773.EOther Combustion Units51FairlaneTruckShopBoiler58.10.0107532,0395,244,705491,3701.85,20030052FairlaneNewShopBoiler36.70.0108532,2805,244,708311,3781.53,20030053FuelHandlingBoiler #136.70.0109531,7985,244,107241,3651.73,200300C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc22Exit GasTemperature (F)C:\Documents andEmissionUnit IDEmissionDescrSettings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc23UnitiptionSO2Max.24-hrActualEmissions(lb/day)BasisforSO224-hrActualEmissionsNOxMax. 24-hr ActualEmissions (lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.524-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM1024-hrActualEmissionsStackNo.Easting NorthingHeightofopeningfromground(ft)BaseElevationofGround(ft)Stacklength,width orDiameter (ft)Flow Rateat Exit(acfm)54FuelHandlingBoiler #236.70.0110531,8025,244,101241,3651.73,2003009910MakeupHeaters(F.CrusherBldg)176.40.099

# 4.C Facility Baselin e Modeling Results
The Minnesota BART modeling protocol 22 

# describes the CALPUFF model inputs, including the
meteorological data set and background atmospheri c 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:

• 98 th 

# Percentile: As defined by federal guidance and as stated in the MPCA’s document which
identifies the Minnesota facilities that are subject to BART 23 

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

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

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

• Number of Days Exceeding 0.5 dV: The severity of the visibility impair ment 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 visibi lity impairment in Class I areas because the modeled

98 th 

# percentile of the baseline c onditions exceeds the threshold of 0.5 dV. The results of this
modeling are also utilized in the post-control modeli ng analysis in section 6 of this document. Two
baselines are shown. The first baseline represen ts burning natural gas on both Lines 1 and 2 and
emission levels prior to in stallation of the heat recoup project on Line 1. The new baseline represents

the emission levels afte r installation of the heat recoup project.

The full modeling analysis is presented in Appendix C.

22 

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

23 

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

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# 24

# Table 4-2 Baseline Visibility Modeling Results

2002 2003 2004 2002 – 2004 Combined

Class I Area with Greatest Impact Modeled 98 th


### Percentile

Value (deciview) No. of days exceeding 0.5 deciview Modeled 98 th


### Percentile

Value (deciview) No. of days exceeding 0.5 deciview Modeled 98 th


### Percentile

Value (deciview) No. of days exceeding 0.5 deciview Modeled 98 th


### Percentile

Value (deciview) No. of days exceeding 0.5 deciview 

# BWCA 3.5 121 4.0 116 4.7 103 4.0 340

BWCA 3.0 114 3.4 115 4.0 97 3.4 326

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# 25

# 5. BART Analysis for Indurating Furnaces

As presented in section 3 and Table 3-1, the only sources at United Taconite that require a full BART
analysis are the indurating furnaces. The BART analysis is required for SO 2 

# and NO
x 

# .


# 5.A Indurating Furnace
The primary function of taconite indurating furnaces is to conver t magnetic iron concentrate to a
more highly oxidized iron in the form of a pellet that is sold to metallic iron and steel production
facilities. “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The
induration process involves pellet pr e-heating, drying, hardening, oxi dation and cooling. The process
requires large amounts of air for pellet oxidation and cooling. Pr ocess temperature control in all
parts of the furnace is critical to minimize product breakage in the initial process stages, allow
required oxidation reactions to occu r, and adequately cool the produc t prior to subsequent handling
steps. Directed air flow, heat recovery and fuel combustion are critical to controlling temperature
and product quality in all parts of the furnace.

United Taconite has grate/kiln furnaces, in which the pellets are dried on a grate and then transferred
to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation section of the
induration furnace is designed to operate at 2,400 oF and higher. This temperature is required to meet
taconite pellet product specificatio ns. 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 induratio n process, induration furnaces have been designed to recover as
much heat as possible usi ng 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 desi gned to maximize heat recovery within process
constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s energy is
directed to the process instead of heating ambient air to combustion temperatures.

United Taconite has two grate/kiln furnaces, Line 1 and Line 2. Line 1 is permitted to burn natural
gas and fuel oil. Line 2 is permit ted to burn natural gas, fuel oil, coal, and petroleum coke. Both
lines are controlled by wet scrubbers. Line 1 al so uses caustic reagent. The wet scrubbers are
designed to remove PM and would be considered a high efficiency PM wet scrubber. Since collateral

SO 2 

# reductions occur within the existing wet scrubbers, they are considered low efficiency SO 2



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

# 26

# scrubbers and will be evaluated as su ch within this BART analysis. NO
x 

# is controlled through
furnace design.



# 5.A.i Sulfur Dioxide Controls

One source of SO 2 

# emissions in taconite produc tion is trace amounts of sulfur in the iron concentrate
and binding agents present in the green balls. Sulfur is also present in distillate fuel oil, that is a
permitted fuel for both lines, and in coal and petroleum coke, that are permitted fuels on Line 2.

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies See Appendix D for a comprehensive list of all pot ential retrofit control technologies that were
evaluated. Many emerging technol ogies have been identified that are not currently commercially
available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the
technology as it was understood at that time. As work on this evaluation progressed, new
information became apparent of the limited scope and scale of some of the technology applications.
Appendix D presents the current status of the avai lability and applicability of each technology.

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for SO 2 

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

section describes retrofit SO 2 

# control technologies that were identif ied as available and applicable in
the original submittal and discusses aspects of th ose technologies that dete rmine whether or not the
technology is technically feas ible 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 pa rticles are given an electrical charge by passing through a high
voltage DC corona region in whic h gaseous ions flow. The charged particles are attracted to and
collected on oppositely charged collec tor plates. Particles on the coll ector plates are released by
rapping and fall into hoppers for collection and removal.

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

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


# absorber.

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# 27

# The SO 2 

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

as SO 2 

# flue gas concentration, fuel used, and ore composition. United Taconite currently employs a
wet scrubber designed for removal of particulate matter, and it performs as a low efficiency SO 2 

# wet
scrubber. The addition of a WWESP would act as a polishing scrubber and would experience
reduced control efficiency due to lower SO 2 

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

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

# reduction for this BART analysis.

Wet Scrubbing (High and Low Efficiency)

Wet scrubbing, when applied to remove SO 2 

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

# in the waste gas. Crushed limestone, lime, or caustic are used as scrubbing
agents. Most wet scrubbers recirculate the scr ubbing solution, which minimizes the wastewater
discharge flow. However, higher concentrations of solids exist within the recirculated wastewater.

For a wet scrubber to be cons idered a high efficiency SO 2 

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

# . Typical high efficiency SO 2 

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

# wet scrubber
could be as low as 30% control efficiency. A low efficiency SO 2 

# scrubber could be a venturi rod
scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, wh ich are frequently used

for PM control at taconite facilities, will also remove some of the SO 2 

# from the flue gas as collateral

emission reduction.

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

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2


# CaSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

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

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# 28

# Ca(OH) 2 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O

Ca(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

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

# removal reactions are as

follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3


# 2Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or

limestone scrubbers. If lime or limest one is used as the reagent for SO 2 

# removal, additional
equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating
the resultant sludge. Calcium sulfit e sludge is watery; it is typically stabilized with fly ash for land
filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air
injection blower is needed to supply the oxygen for the second reaction to occur.

The normal SO 2 

# control efficiency range for SO 2 

# scrubbers on coal-fired utility boilers with excess
oxygen of 2-3% is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency
scrubbers. The highest control effi ciencies can be achieved when SO 2 

# concentrations are the highest.
Unlike coal-fired boilers, indurating furnaces oper ate with maximum excess air to enable proper
oxidation of the pellet. The excess air dilutes the SO 2 

# concentration as well as creates higher flow
rates to control. Additionally, the varying sulfur con centration within the pellet causes fluctuations of

the SO 2 

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

# control efficiency

of the wet scrubber.

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

exhausts and are believed to remove 15 to 30% of the SO 2 

# in the exhaust. Taking into consideration

the removal of SO 2 

# from the low-efficiency primary PM scrubber as well as a polishing SO 2 

# wet
scrubber, an overall efficiency of th e control train would then be 80%.

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

# removal could be accomplished. The co ncentration 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 SO 2 

# emissions. The SO 2 

# 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 extensiv e redesign of the existi ng scrubbers, such as modifying the spray,

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# 29

# increasing the contact time, recirculating the scrubber water, and retrofitting to allow use of a much
higher pH. Quantifying the likelihood and ma gnitude of potential improvements to SO 2 

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

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

# reduction for this BART analysis.

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

Lime/limestone injecti on is a post-combustion SO 2 

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

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

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

# control
efficiency range for dry SO 2 

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

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

Spray Dryer Absorption (SDA)

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

# is
absorbed by the slurry, forming CaSO 3 

# /CaSO 4 

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

# , the term flue-gas

desulfurization (FGD) may also be used.

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

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# 30

# Energy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,
which results in lower operating costs. Typically, reduced fuel usage translates into reduced
pollution emissions. United Taconite recently in stalled heat recuperation on Line 1 and performed
stack testing to quantify the emis sion reductions. Testing comple ted in May of 2005 revealed that

NO
x 

# emissions were reduced by 46%. Differences in SO 2 

# emissions are attribut ed to differences in
ore composition. Therefore, this alternative will not be carried forward in this analysis for SO 2 

# , but

will be carried forward for NO
x 

# .

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 SO 2 

# emissions through alternative fuel usage, the source must use fuels
with lower sulfur content. Switching fuels tr ades one visibility impairment pollutant (SO 2 

# ) for

another (NO
x 

# ), as induration furnaces emit significantly less NO
x 

# when burning solid fuels.
Therefore, if this option is pursued, the impact on emissions of all visibility pollutants must be
quantified and the cumulative visibility impact modeled to determine the net benefit of a particular

alternative fuel.

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an
option, not to direct the fuel choice. 24



# Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility
impairment pollutant for another, and the fact that BART is not intended to mandate a fuel switch,

alternative fuels as an SO 2 

# air pollution control technology will not be further evaluated in this
report. However, similar to energy efficiency, facilities will continue to evaluate and implement
alternate fuel usage as the feasibility arises.

Coal Processing

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

uncontrolled SO 2 

# emissions. Coal processing technologies are being developed to remove moisture
and potential contaminants from the coal prior to use.

24 

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

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# 31

# These processes typically employ both mechanical and thermal means to increase the quality of coal
by removing moisture, sulfur, mercury, and heavy me tals. In one process, raw coal from the mine
enters a first stage separator where it is crushed and screened to remove large rock and rock

material. 25 

# The processed coal is then passed on to an intermediate storage facility prior to being sent
to the next stage in the process, the thermal process. In this stag e, 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 fractu red 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 vent ed into a water condenser to retu rn the processor to atmospheric
pressure and to flash cool the coal. Water, removed from the process at various points, and
condensed process steam ar e reused within the process or trea ted prior to being discharged.

To date, the use of processed fuels has only been de monstrated 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 Un ited Taconite for Line 2 as an incidental option

for SO 2 

# 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 reductio ns from this control opt ion are not possible.
Therefore, it will not be further evaluated in this report.

Step 2 Conclusion

Based upon the determination with in Step 2, the remaining SO 2 

# control technologies that are
available and applicable as secondary controls to the existing indurating furnace wet scrubbers are
identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.

25 

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

# process under development by KFx, Inc.

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# 32

# Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and Technical Feasibility



# SO 2 

# Pollution Control Technology Available? Applicable? Technically Feasible? 

# Wet Scrubbing (Secondary) Yes Yes Yes Modification to Existing Wet Scrubber Yes Yes No

Wet Walled Electrostatic

Precipitator (WWESP) Yes Yes Yes

Dry sorbent injection Yes Yes No Spray Dryer Absorption (SDA) Yes Yes No

Alternative Fuels Yes Yes Yes – Not Required Energy Efficiency Projects Yes Yes Not Required

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-2 describes the expected control efficiency from each of the remaining feasible control
options. The WWESP and high efficiency wet scrubbing control options listed in Table 5-2 would be
considered polishing controls since a wet scrubber cu rrently exists that achieves some control of SO 2


# .

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80

Secondary Wet Scrubber 60



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

As illustrated in Table 5- 2 above, the technically feasible contro l 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 maximu m 24-hour emissions, vendor estimates, and U.S.

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# 33

# EPA cost models. Capital costs we re based on a recent vendor quotation. The cost for that unit was
scaled to each stack’s flow rate using the 6/10 power law as shown in the following equation:

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



# Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S.
EPA models and factors. Operating costs were based on 93% utilization and annual operating hours
of 6600 hours for Line 1 and 8700 hours for Line 2. Oper ating costs of consumable materials, such as
electricity, water, and chemicals were established based on the U.S. EPA control cost manual 26 

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

Due to space considerations, 60% 27 

# of the total capital investment was included in the costs to

account for a retrofit installation. After a tour of the facility and disc ussions with facility staff, it was
determined the space surrounding th e 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 woul d 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-s pecific estimate for si te work, foundations, and

structural steel was added to arrive at the total re trofit 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 SO 2 

# Control Cost Summary

Control Technology Installed Capital Cost (MM$) Operating Cost (MM$/yr) Annualized Pollution Control Cost ($/ton) Incremental Control

Cost ($/ton) Wet Walled Electrostatic Precipitator

(WWESP) Line 1 Pellet

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

Line 2 Pellet

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

26 

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

. 27 

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

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# 34

# Control Technology Installed Capital Cost (MM$) Operating Cost (MM$/yr) Annualized Pollution Control Cost ($/ton) Incremental Control

Cost ($/ton) Wet Scrubber

(Additional) Line 1 Pellet

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

Line 2 Pellet

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



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

bodies, and other sim ilar regulatory programs like Clean Air In terstate Rule (CAI R), cost-effective
air pollution controls in the electric utility industr y for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshol d 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 tac onite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The tac onite industry is not
afforded the same market stability or guaranteed co st recovery mechanisms that are afforded to the
electric utility industry. Ther efore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, th en visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to el iminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 28



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

The incremental control cost listed in Table 5-3 is intended to represent the incremental value of each
technology as compared to the technology wi th the next highest level of control.

28 

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

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# 35

# The cost of control for Line 1 is far above the screening threshold for carrying either technology
forward in this analysis. The cost of control fo r Line 2 is below the screening threshold for both
technologies, however the incrementa l cost of a WWESP is higher than the screening threshold, so a
polishing wet scrubber will be ca rried forward in this analysis.

Energy and Environmental Impacts

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

Table 5-4 SO 2 

# Control Technology Impacts Assessment

Control Technology Energy Impacts Other Impacts

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

• Increased facility waterbalance and water quality issues

• Ponding for scrubber discharge will be limited because of site space constraints

• Additional solid waste/sludge generation

• Process downtime/lost production during installation

Wet Walled Electrostatic Precipitator (WWESP) • Additional electrical consumption due to operation of the ESP • Additional water consumption and wastewater generation

• Increased facility waterbalance and water quality issues

• Ponding for scrubber discharge will be limited because of site space constraints

• Additional solid waste/sludge generation (or increased sulfate loading to wastewater for caustic reagent)

• Process downtime/lost production during installation

• Plume visibility

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# 36

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

# 37 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 fro m the retrofit technology, in comb ination with other factors such
as economic, energy and other non-air quality impa cts, 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 eval uates the visibility impacts of BART SO 2 

# control and the
resulting degree of visibility improvement.

Predicted 24-Hour Maximum Emission Rates

Consistent with the use of the hi ghest daily emissions for baseline, or pre-BART, visi bility 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 SO 2 

# , the

emissions from the sources undergoing a full BART SO 2 

# analysis were adjusted to reflect the
projected 24-hour maximum SO 2 

# emission rate when applying the control technologies that met the
threshold requirements of steps 1 – 4. The emissions from all ot her 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 SO 2 

# control technologies. Table 5-6 provides a summary

of the SO 2 

# , NO
x 

# , and PM 10 

# emissions for each modeling scenario, and Table 5-7 provides a summary
of the modeling input data.Table 5-5 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxControlScenarioSV #Emission UnitSO2NOx% ReductionMax24-hour lbs/hr% ReductionMax24-hour lbs/hr6Base(Wet PM Scrubbers)N G on L1 & L2; Prior to HeatRecoup on Line 1SV 046EU 040 Line 10%80%1208SV 048EU 042 Line 20%200%953SV 049EU 042 Line 20%220%10688Base(Wet PM Scrubbers)Solid fuels on L2; Fuel Oil onL1;Heat recoup on L1SV 046EU 040 Line 10%19946%651SV 048EU 042 Line 20%3460%203SV 049EU 042 Line 20%2670%1732Base(Wet PM Scrubbers)N G on L1 & L2; with HeatRecoup L1SV 046EU 040 Line 10%846%651SV 048EU 042 Line 20%200%953SV 049EU 042 Line 20%220%10681Base(Wet PM Scrubbers)Solid fuels on L2; N G on L1;with Heat Recoup L1SV 046EU 040 Line 10%846%651SV 048EU 042 Line 20%3460%203SV 049EU 042 Line 20%2870%1733Wet Walled ESP onLine 2Solid fuels on L2; N G on L1;Heat Recoup L1SV 046EU 040 Line 10%80%651SV 048EU 042 Line 280%690%203SV 049EU 042 Line 280%570%1734Wet SO2 Scrubberon Line 2(secondaryscrubber)Solid fuels on L2; NG on L1;Heat Recoup on L1SV 046EU 040 Line 10%80651SV 048EU 042 Line 260%1380203SV 049EU 042 Line 260%1150173C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc38ments and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc39Table5-6 Post-ControlSO2Modeling Scenarios - Modeling Input DataC:\DocuControlScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpening fromGround(ft)BaseElevation ofGround(ft)Stack length,width, orDiameter(ft)Flow Rate atexit(acfm)Exit Temp(oF)All46EU 040 Line 1532024.985244399.8814013821036913712948EU 042 Line 2531995.035244364.9815313711234600012749EU 042 Line 2531983.415244432.55153137812380000115

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# 40 Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for SO 2 

# are presented in Table 5-8. The
results summarize the 98th percentile dV value and the number of days the facility contributes more
than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison of the postcontrol modeling scenarios to the baseline conditions is presented in Table 5-9. It is important to note

that Scenarios 6, 8, 2 and 1 are all baseline conditi ons using permitted fuels, as described in Table 5-
5. To evaluate the impact of add-on SO 2 

# controls in Scenarios 3 and 4 the results are compared to

Scenario 1, which uses the same fuels without SO 2 

# controls.

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

(Scen ario 6-both lines using natural gas, prior to the heat recoup project on Line 1). Installing heat
recoup on Line 1 reduced that impact by 0.7 dV to 4.0 dV due to NO
x 

# emission reductions (Scenario
2-both lines using natural gas, after the heat recoup project). The facility is currently operating under
Scenario 1, consisting of natural gas on Line 1 and solid fuels on Line 2. The modeled visibility
impact under Scenario 1 is 2.0 dV. A polishing wet scrubber would potentially reduce the visibility
contribution by 0.1 dV at a cost of over $28 million in installed capital cost and a total annual cost of
over $5.5 million per year. This would result in a cost per deciview reduction of over $50 million
per deciview. A WWESP on Line 2 would potentially reduce the visibility impact by 0.1 dV over
$41 million in installed capital cost and a total annual cost of $16.9 million per year. This would
result in a cost per deciview reduction of $117 million per deciview.

Visibility impacts with NO
x 

# controls are presented in Section 6.ments and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc41Table 5-8 Post-Control SO2Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004CombinedScenario #Class IArea withGreatestImpactModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciviewModeled 98thPercentileValue(deciview)No. of daysexceeding 0.5deciview6 BaseBWCA3.51214.01164.71034.03408 BaseBWCA1.6782.1742.2622.02142 BaseBWCA3.01143.51154.0973.53261 BaseBWCA1.5661.9672.0531.81863BWCA1.3571.6621.9471.61664BWCA1.4591.7651.9491.7173Table 5-9 Post-Control SO2Modeling Scenarios - Visibility ImprovementsC:\DocuModeling Results02002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dV3BWCA0.190.350.160.2204BWCA0.170.220.140.113Scenarios 3 and 4 are compared to Scenario 1, consisting of solid fuels on Line 2 and after the installation of heat recoup onLine 1.

# 5.A.ii Nitrogen Oxide Controls

To be able to control NO
x 

# it is important to understand how NO
x 

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

# production occurs: thermal, fuel and prompt NO
x 

# .

• Fuel bound NO
x 

# is formed from fuel combustion as nitrogen compounds in the fuel are

oxidized.

• Thermal NO
x 

# production arises from the thermal dissociation of nitrogen and oxygen

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

In taconite furnaces, thermal NO
x 

# production is a function of th e residence time, free oxygen,
and temperature, primarily in the flame area of the furnace.

• Prompt NO
x 

# is a form of thermal NO
x 

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

minor amounts of NO
x 

# are emitted as prompt NO
x 

# .

The majority of NO
x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the furnaces.

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies With the understanding of how NO
x 

# is formed, available and applic able control technologies were
evaluated. See Appendix D for the current status of the availability and applicability of retrofit
control technologies.

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options Step 1 identified the available and applicable technologies for NO
x 

# emission reduction. Within
Step 2, the technical feasibility of the control option was also discussed and determined. The
following describes retrofit NO
x 

# control technologies that were iden tified as available and applicable
in the original submittal and discusses aspects of those technologies that de termine whether or not
the technology is technically feas ible 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 NO
x 

# formation. In an external flue gas recirculation system, flue gas is
collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas
reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen

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# 42

# level in the combustion zone reduces flame temperatures; which in turn reduces NO
x 

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

The normal NO
x 

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

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

1. The exhaust gas in an induration furnace typica lly has an oxygen content that is close to
ambient, or 18% oxygen, vs. a boiler which has 2% - 3% oxygen. In a boiler, the flue gas
is relatively inert so it can be used as a diluent for flame temperature reduction. Taconite
waste gas has much higher oxygen level; thus use of taconite waste gas for EFGR would
be equivalent to adding combustion air instead of an inert gas.

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

# F in order to meet
product specifications. Existing burners are de signed to meet these process conditions.
Application of EFGR would reduce flame te mperatures. Lower flame temperatures
would reduce furnace temperatures to the poin t 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 compone nts to excessive temperatures and cause
equipment failures.

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

Low- NO x 

# Burners

Low- NO
x 

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

# formation
through the restriction of oxygen, flame temperatur e, and/or residence ti me. 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, NO
x 

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

# formation. In
the secondary combustion zone, incomplete combustion products formed in the primary zone act as

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# 43

# reducing agents. In a reducing atmosphere, nitrog en compounds are preferentially converted to
molecular nitrogen (N 2 

# ) over nitric oxide (NO). The estimated NO
x 

# control efficiency for LNB in
high temperature applications is 10%. Low NO
x 

# burners have been installed in the preheating section
of a straight grate furnace at anot her taconite plant. If LNB were to be applied in the indurating zone
of the furnace, the reduced flame temperatures associated with LNB would adversely affect taconite
pellet product quality. LNB has not been applied to the indurating zone of any grate-kiln taconite
furnace. Therefore, this option is not viable.

It is also important to note that there are othe r methods being developed for LNB which are not yet
commercially available. Some incorporate vari ous fuel dilution techniques to reduce flame
temperatures; such as mixing an inert gas like CO 2 

# 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 NO
x 

# emissions from gas turbines and a straight grate taconite
indurating furnace in the Netherlands. The wa ter 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 reci rculation burners, also called ultra low- NO
x 

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

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

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

As noted above, taconite furnaces are designed to operate with oxygen levels near 18%. At these
oxygen levels, flue gas recirc ulation is ineffective at NO
x 

# reduction, and it would adversely affect

combustion because excessi ve amounts of oxygen would be inject ed into the flame pattern. In

addition, IFGR relies on convectiv e 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 an d applicable control option, it is not technically feasible due to
the high oxygen content of the flue gas and wi ll not be further evaluated in this report.

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# 44

# Energy Efficiency Projects

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption,
which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution
emissions. United Taconite recently installed heat recuperation on Line 1 and performed stack
testing to quantify the emission reductions. Testing completed in May of 2005 revealed that NO
x 

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

Ported Kilns

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the
kiln for process improvement. The purpose of the ports is to allow air injection into the pellet bed as
it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is
equipped with a closure device that opens when it is at the bottom position to inject air in the pellet
bed, and closed when it rotates out of position.

The purpose of air injection is to provide addi tional oxygen for pellet oxidation. The oxidation
reaction produces enough heat to offset the heat lo ss associated with air in jection. Air injection
reduces the overall energy use of the kiln and produ ces 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 NO
x 

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

reduce NO
x 

# emissions because controlli ng the oxygen in the firing zone is not possible due to the

flow of air from the cooler 29 

# . Any reduction in NO
x 

# would be minor and incidental to the process
improvement and specific to the individual furnace. Therefore, although this may be an available and
applicable technology, it does not reduce NO
x 

# emissions and will not be further evaluated in this

report.

Alternate Fuels

As described within the energy efficiency description, increased price of fuel has moved companies
to evaluate alternate fuel sources. These fuel sources come in all physical forms – solid, liquid and
gas. Reduction of NO
x 

# emissions through alternativ e fuel usage has been achi eved at taconite grate
kilns through the use of solid fuel. In these cases the reduction resulted due to changes from
pulverized solid fuel dispersal in the kiln that resulted in lower flame temperature compared to other

29 

# Telephone conversation with Metso, July 18, 2006.

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# 45

# fuels. Switching from natural gas or oil to solid fuel has a potential drawback in that I can exchange
one visibility impairment pollutant (NO
x 

# ) for another (SO 2 

# ). Therefore, if this option is pursued, the
impact on emissions of all visibility pollutants must be quantified and the cumulative visibility
impact modeled to determine the net benefit of a particular alternative fuel.

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as an
option, not to direct the fuel choice. 30



# Process Optimization with NO x 

# CEMS or Other Parametric Monitoring

MPCA guidance lists “NO
x 

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

# emissions 31 

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

Based on conversations with MPCA staff, this work practice would include pr ocess adjustments, or
optimization, to minimize NO
x 

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

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

emissions from boilers.

One taconite plant has installed NO
x 

# CEMS to monitor emissions, but not to optimize NO
x 

# emissions
through process fine tuning. That plan t has experienced some reduction in NO
x 

# emissions, but these
encompass multiple variables and are not attr ibuted to process fine tuning with the NO
x 

# CEMS.

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

There are several concerns with utilizing process optimization as an available, applicable and
technically feasible control op tion for the taconite industry:

• Taconite furnaces are designed and operated to convert magnetite to hematite in the presence
of excess oxygen and require heat input to initiate the reaction wh ich is exot hermic and

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

30 

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

31 

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

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# 46

# • 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 NO
x 

# 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 NO
x 

# formation may not be dependent upon controllable operating pa rameters. In the absence of
controllable parameters, proc ess optimization would not be effective at controlling NO
x 

# emissions.

Based upon this information, there is no indica tion that further emissi on reductions would be
achieved through process optimization, using NO
x 

# CEMS or other parametric monitoring, as a
control technology. Therefore, process optimization as a control option will not be evaluated further
in this report.

Post Combustion Controls

NO
x 

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

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

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

alternatives is described below.

Non-Selective Catalytic Reduction (NSCR)

A non-selective catalytic reduction (NSCR) syst em is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensi tive to poisoning; so; NSCR is usually applied
primarily in natural gas combustion applications.

NSCR is often referred to as “t hree-way conversion” catalyst be cause it simultaneously reduces NO
x 

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

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

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# 47

# stoichiometric conditions. Under this condition, in the presence of a catalyst, NO
x 

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

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO
x 

# removal

are:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

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

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction

SCR is a post-combustion NO
x 

# control technology in which ammonia (NH 3 

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

# is removed through the fo llowing chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O (1)

2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2)

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

# decomposition. SCR requires a temperat ure range of about 570°F – 850°F for a
normal catalyst. At temperature ex ceeding 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 le ss than 3 to 5 ppm. The emission of ammonia
increases during load changes due to the instability of the temperature in the catalyst bed as well as at
low loads because of the low gas temperature.

Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR)
control process as described below with a preheat process step to reheat the flue gas stream up to
SCR catalyst operating temperatures. The prehea ting process combines use of a thermal heat sink

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# 48

# (packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR
and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the
preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow
alternates between vessels. Each of the vessels alternates between preheating/treating and heat

recovery.

The benefits of RSCR are:

• Its high energy efficiency allows it to be used after SO 2 

# and particulate controls.

• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a
thermal efficiency of 60% to 70%.

• Application of RSCR after SO 2 

# and PM controls significantly reduces the potential for
problems associated with plugging and ca talyst poisoning and deactivation.

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

furnace:

• The composition of the indurating furnace flue gas is significantly different from the
composition of the flue gas from the boilers that utilize RSCR;

• The taconite dust is highly er osive and can cause significantly equipment damage. RSCR has
a number of valves which must be opened and closed frequently to switch catalyst/heat
recovery beds. These valves could be subject to excessive wear in a taconite application due

to the erosive nature of the taconite dust;

• RSCR has not been applied downstream of a wet scrubber. Treating a st ream saturated with
water may present design problems in equipmen t sizing for proper heat transfer and in
corrosion protection;

• RSCR catalyst had been shown to oxidize merc ury. Oxidized mercury can be absorbed by
the local environment and have adverse impact. The impact of RSCR on mercury emissions

needs to be studied to determine whether or not mercury oxidation is a problem and to
identify mitigation methods if needed.

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# To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not
been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace
exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant
would require research, test runs, and extended trials to identify potential issues related to catalyst
selection, and impacts on plant systems, including the furnaces and emission control systems. It is
not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of
a demonstration project. The timeline required to pe rform such a demonstration project would likely
be two years to develop and agree on the test pl an, 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 result s 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 re garding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to unde rgo extended trials in order to
learn how to apply a control technology to a comple tely new and significantly different source type.
Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this
BART analysis.

SCR with reheat through a conventional duct burn er (rather than using a regenerative heater) has
been successfully implemented more widely and in higher airflow applicati ons and will be carried
forward in this analysis as available and applicab le technology that is reasonably expected to be
technically feasible.

Low Temperature Oxidation (LTO)

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

NO
x 

# . In the system, the NO
x 

# in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2,
and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas
(4). Then the nitric acid vapor is absorbed as di lute nitric acid and is neutralized by the sodium
hydroxide or lime in the scrubbi ng solution forming sodium nitrat e (5) or calcium nitrate. The
nitrates are removed from the scrubbing system and discharged to an appr opriate water treatment
system. Commercially available LTO systems include Tri-NO
x 

# ® and LoTOx®.

NO + O 3 

# → NO 2 

# + O 2 

# (1)

NO 2 

# + O 3 

# → NO 3 

# + O 2 

# (2)

NO 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

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# N 2 

# O 5 

# + H 2 

# O → 2HNO 3 

# (4)

HNO 3 

# + NaOH → NaNO 3 

# + H 2 

# O (5)

Low Temperature Oxidation (Tri-NO x ® 

# )

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

# in a
primary scrubbing stage. Then NO 2 

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

reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# (1)

2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O (2)

Tri-NO
x ® 

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

# . Subsequent
stages reduce NO 2 

# to nitrogen gas, while the oxygen beco mes part of a soluble salt. Tri-NO
x ® 

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

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

# ). NO
x 

# concentrations in the exhaust at Unit ed Taconite are typically less than 200
ppm. Therefore, Tri-NO
x ® 

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

Low Temperature Oxidation (LoTOx ® 

# )

BOC Gases’ Lo-TOx ® 

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

# technology uses ozone

to oxidize NO to NO 2 

# and NO 2 

# to N 2 

# O 5 

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

# O 5 

# is converted to HNO 3 

# in a

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

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

needed for NO
x 

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

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

The first component of the technical feasibility revi ew includes determining if the technology would
apply to the process being reviewed. This would include a review and comparison of the chemical
and physical propertie s required. Although it appears that the chemistry involved in the LTO

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# technology may apply to an indurating furnace, the furnace exhaust contains other ore components
that may participate in side reactions. This technol ogy has not been demonstrated on a taconite pellet
indurating furnace. This raises uncertainties about how or whether the technology will transfer to a
different type of process.

The second component of the technical feasibility re view 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 qui te small, compared to the indurating fu rnace flue gas flow rates of up to
726,000 acfm. Therefore, the appli cation of LTO would be more than an order of magnitude larger
than the biggest current installation. This larg e scale-up is contrary to good engineering practices
and could be problematic in maintain ing 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, th e limited application mean s 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 (Fe 3 

# O 4 

# ) which would react with the

ozone to form hematite (Fe 2 

# O 3 

# ); since the ozone injection point would be before the scrubber,
there can be more than 400 pounds per hour of taconite dust in the flue gas which could
consume a significant amount of the ozone bei ng generated which may change the reaction
kinetics; consequently, this w ould 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 SO 2 

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

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# 52

# • 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 al so be a source of nitr ate discharge to the
tailings basin which would cha nge the facility water chemistr y which could cause operational
problems and would likely cause additional pr oblems with National Pollutant Discharge
Elimination System (NPDES) discharge limits and requirements.

Application of this technology has not been applied to taconite induration furnaces, to airflows of the
magnitude of taconite furnace exhausts, nor to exha ust streams with similar, high moisture content.
Using LTO at a taconite plant would require resear ch, test runs, and extended trials to identify
potential issues related to design for high airflows and impacts on plant systems, including the
furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of
performance would be forthcoming in advance of a demonstration pr oject. The timeline required to
perform such a demonstration proj ect would likely be two years to develop and agree on the test
plan, obtain permits for the trial, commission the e quipment for the test runs, perform the test runs
for a reasonable study period, and evaluate and re port 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 re garding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to unde rgo extended trials in order to
learn how to apply a control technology to a comple tely new and significantly different source type.
Consequently, the technical feasibility of LTO on an indurating furnace is te chnically infeasible for
this application and will not be evaluated further.

Step 2 Conclusion

Based upon the determination with in Step 2, the remaining NO
x 

# control technologies that are
available and applicable to the indurating furnace process are identified in Tabl e 5-10. The technical
feasibility as determined in Step 2 is also included in Table 5-10.

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# Table 5-10 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility



# NO
x 

# Pollution Control Technology Available? Applicable? Technically Feasible?
External Flue Gas Recirculation (EFGR) Yes No No

Low- 

# NO
x 

# Burners Yes Yes No

Induced Flue Gas Recirculation Burners Yes Yes No

Energy Efficiency Projects Yes Yes Yes

Ported Kilns (Applies to Grate Kilns Only) Yes Yes No

Alternative Fuels Yes Yes Yes, Not Required Process Optimization using 

# NO
x 

# CEMS Yes No No

Non-Selective Catalytic Reduction (NSCR) Yes No No

Selective Catalytic Reduction (SCR) with conventional reheat Yes Yes Yes

Regenerative SCR Yes No No Selective Non-Catalytic Reduction (SNCR) Yes No No

Low Temperature Oxidation (LTO) Yes No No



# 5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies Table 5-11 describes the expected control efficiency from each of the remaining technically feasible
control options as identified in Step 2.

Table 5-11 Indurating Furnace NO x 

# Control Technology Effectiveness



# NO
x 

# Pollution Control Technology Approximate Control Efficiency

SCR with Conventional Reheat 80%



# 5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results Table 5-12 summarizes the expected costs associated with installation of low NO
x 

# burners and SCR
with conventional reheat. Capital costs were ca lculated based on the maximum 24-hour emissions,

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# 54

# U.S. EPA cost models, and vendor es timates. Vendor esti mates for capital cost s based on a specific
flow rate were scaled to each stack’s flow rate using the 6/10 power law to account for the economy
of scale. Operating costs were based on 93% utilization and annual operating hours of 6600 hours
for Line 1 and 8700 hours for Line 2. Operating costs were proportionally adjusted to reflect site
specific flow rates and pollutant concentrations.

After a tour of the facility and discussions with facility staff, it was determined the space surrounding
the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to
transport materials to and from th e building. A site-specific estimat e for site-work, foundations, and
structural steel was added based upon the facility site to arrive at the total retr ofit installed cost of the
control technology. The site specific estimate was based on Barr’s experience with recent actual
retrofit costs. See Appendix C for a site plan of the facility. Additionally, the structural design of the
existing building would not support additional equipmen t on the roof. The detailed cost analysis is
provided in Appendix A.

Table 5-12 NO x 

# Control Cost Summary

Control Technology Installed Capital Cost (MM$) Operating Cost (MM$/yr) Annualized Pollution Control Cost ($/ton) Incremental Control

Cost ($/ton) Selective Catalytic Reduction (SCR) with Reheat
Line 1 Pellet Induration $44,591,384 $23,923,236 $13,659 NA
Line 2 Pellet Induration solid fuels $70,762,832 $35,189,143 $22,017 NA

Line 2 Pellet Induration natural
gas $72,222,298 $37,770,123 $4,736 NA



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

bodies, and other sim ilar regulatory programs like Clean Air In terstate Rule (CAI R), cost-effective
air pollution controls in the electric utility industr y for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshol d 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 tac onite BART analysis, the $1,000 to $1,300 cost

effectiveness threshold is used as the cutoff in proposing BART. The tac onite industry is not
afforded the same market stability or guaranteed co st recovery mechanisms that are afforded to the
electric utility industry. Ther efore, the $1,000 to $1,300 per ton removed is considered a greater

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# 55

# business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.

The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, th en visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to el iminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 32



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

The incremental control cost column in Table 5-6 is intended to present the incremental value of each
technology as compared to the technology with the ne xt most effective alterna tive. Since none of the

NO
x 

# reduction technologies are co st effective, the incrementa l cost is not applicable.

The cost of NO
x 

# control using SCR for Line 1 and Line 2 using solid fuels are over $12,000 per ton
removed, which is above the screening threshold for further consideration. When Line 2 uses natural
gas, the cost per ton removed is $4736, which is be low the $12,000 screening level, but is more than

a factor of three times the cost effectiveness th reshold of $1000-$1300. this alternative is carried
forward to analyze the energy and environmental impacts as well as visibility impacts.

Energy and Environmental Impact

The energy and non-air quality impacts for the rema ining alternatives are pr esented in Table 5-13.

Table 5-13 NO x 

# 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 NO x 

# to form ammonium nitrate and SO 2 

# to form ammonium sulfate particles. Ammonium sulfate is hygroscopic and bonds with water in the air to grow large particles. The

32 

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

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# large particles formed by ammonium sulfate disproportionately contribute to visibility impairment .

• Ammonia emissions will increase condensable PM emissions that will have possible PSD permitting implications.

• Ammonia deposition onto nearby lakes and waters of the state and contribute nutrients and undesirable biological growth.

• Additional safety and regulatory concerns associated with ammonia storage on site.

• Possible oxidation of elemental mercury.



# 5.A.ii.e STEP 5 – Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting fro m the retrofit technology, in comb ination with other factors such
as economic, energy and other non-air quality impa cts, 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 eval uates the visibility impacts of BART NO X 

# control and the
resulting degree of visibility improvement.

Predicted 24-Hour Maximum Emission Rates

Consistent with the use of the hi ghest daily emissions for baseline, or pre-BART, visi bility 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 NO
x 

# modeling analysis,
the emissions from the sources undergoing a full BART NO
x 

# analysis were adjusted to reflect the
projected 24-hour maximum NO
x 

# emission rate when applying the control technologies that met the
threshold requirements of steps 1 – 4. The emissions from all ot her Subject-to-BART sources were
not changed. Table 5-14 provides a summary of the modeled 24-hour maximum emission rates and
their computational basis for the evaluated NO
x 

# control technologies. Table 5-15 provides a
summary of the SO 2 

# , NO
x 

# , and PM 10 

# emissions for each modeling s cenario, and Table 5-16 provides
a summary of the modeling input data.

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# Table 5-14 Post-Control NO x 

# Modeling Scenarios

Control Scenario SV # Emission Unit Descripition NO x 

## Control Technology NO x 

## % Reduction 24-hr Max (lb/hr)

6 Base: NG on L1 & L2; Prior to Heat Recoup on Line 1

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

2 Base: NG on L1 & L2; with Heat Recoup on Line 1

SV 046 Line 1 SV 046 46% 651
SV 048 Line 2 SV 048 0% 953
SV 049 Line 2 SV 049 0% 1068

7 NG on L1 & L2; with Heat Recoup on Line 1; SCR on Line 2 SV 046 Line 1 SV 046 46% 651
SV 048 Line 2 SV 048 80% 191
SV 049 Line 2 SV 049 80% 214



# Table 5-15 Post-Control NO X 

# Modeling Scenarios – Emissions Data

Scenario Control Technology SO 2 

## NO x 

## Control Scenario SV # Emission Unit SO 2 

## NO x 

## % Reduction Max 24-hour lbs/hr % Reduction Max 24-hour lbs/hr

6 Prior to Heat Recoup on Line 1 Old Base: Prior to Heat Recoup on Line 1 SV 046 Line 1 SV 046 0% 8 0% 1208 SV 048 Line 2 SV 048 0% 20 0% 953 SV 049 Line 2 SV 049 0% 22 0% 1068

2 Base (Wet PM Scrubbers) New Base with Heat Recoup on Line 1 SV 046 Line 1 SV 046 0.0% 8 46% 651 SV 048 Line 2 SV 048 0.0% 20 0% 953 SV 049 Line 2 SV 049 0.0% 22 0% 1068

7 Base (Wet PM Scrubbers) NG on L1&L2; with Heat Recoup on Line 1; SCR on Line 2 SV 046 Line 1 SV 046 0.0% 8 46% 651 SV 048 Line 2 SV 048 0.0% 20 80% 191 SV 049 Line 2 SV 049 0.0% 22 80% 214

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# Table 5-16 Post-Control NO X 

# Modeling Scenarios - Visibility Modeling Input Data

Control Scenario SV # Emission Unit Descripition Stack Easting (utm) Stack Northing

(utm) Height of Opening

from Ground

(ft) Base Elevation

from Ground

(ft) Stack length, width or Diameter (ft) Flow Rate at Exit (acfm) Exit Temp

( o 

## F)

All

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

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

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



# Post-Control Visibility Impacts Modeling Results

Results of the post-control visibility impacts modeling for NO X 

# are presented in Table 5-17. The
results summarize 98th percentile dV value and the number of days the facility contributes more than
a 0.5 dV of visibility impairment at each of th e Class I areas. The comparison of the post-control
modeling scenarios to the baseline conditions is presented in Table 5-18.

As illustrated in tables 5-17 and 5-18 , the facility baseline visibility contribution is 4.7 dV. Installing
heat recoup on Line 1 reduced that impact by 0.7 dV to 4.0 dV. Installing SCR on Line 2 when
natural gas is burned could potentially reduce the visibility contribution by 2.1 dV compared to

Scenario 2, which includes the heat recoup project already installed on Line 1. Line 2 currently uses
solid fuels (Scenario 1, see Table 5-5 through 5-9). The visibility improvement reflected in Scenario
7 is realized when Line 2 uses natural gas, which is a permitted scenario, but does not reflect current
operations.

Visibility impacts with SO 2 

# controls are presented in section 6.

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# Table 5-17 Post-Control NO X 

# Modeling Scenarios - Visibility Modeling Results

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting Class I Area Modeled 98%ile

∆ dV # days

over 0.5 ∆ dV Modeled 98%ile

∆ dV # days

over 0.5 ∆ dV Modeled 98%ile

∆ dV # days

over 0.5 ∆ dV Modeled 98%ile

∆ dV # days

over 0.5 ∆ dV



# 6 BWCA 3.5 121 4.0 116 4.7 103 4.0 340

2 BWCA 3.0 114 3.5 115 4.0 97 3.5 326

7 BWCA 1.4 57 1.6 62 1.9 47 1.6 166

Table 5-18 Post-Control NO X 

# Modeling Scenarios - Visibility Improvements

Modeling Results

2002 2003 2004 2002-2004

Scenario Limiting Class I Area Improved Modeled

98 th


## Percentile

Value ( ∆ -dV) Decreased No. of Days exceeding

0.5 dV Improved Modeled

98 th


## Percentile

Value ( ∆ -dV) Decreased No. of Days exceeding

0.5 dV Improved Modeled

98 th


## Percentile

Value ( ∆ -dV) Decreased No. of Days exceeding

0.5 dV Improved Modeled

98 th


## Percentile

Value ( ∆ -dV) Decreased No. of Days exceeding

0.5 dV 

# 2 BWCA 0.5 7 0.5 1 0.7 6 0.5 14

7 BWCA 1.6 57 1.8 53 2.1 50 1.8 160

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# 60

# 6. Visibility Impacts

As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting fro m the retrofit technology, in comb ination with other factors such
as economic, energy and other non-air quality, when determining BART for an individual source.
The baseline, or pre-BART, visibil ity 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

SO 2 

# and NO
x 

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



# 6.A Post-Control Mo deling Scenarios
Steps 1-4 of the BART analysis identifi ed 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 NO
x 

# , SO 2 

# and PM 10 

# can play a large part
in predicting impairment. It is th erefore 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 NO
x 

# controls. In addition,
two site-specific scenarios were developed so that the evaluation includes other operating scenarios
and conditions that would improve visibility im pairment. 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 pr esented 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 ar eas. The comparison of the post-control modeling

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

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

scenarios on a $/dV basis.

As mentioned in section 5.B.ii.e, the energy effici ency projects implemented at United Taconite will
reduce its contribution to visibility impacts at Class I areas from 4.7 dV to 4.0 dV, which is a
reduction of 15%. These reductions have already been implemented. They represent a significant

contribution toward MPCA’s defa ult glide-path goal of reducing impacts by 1.67% per year.Table 6-1 Post-Control Modeling ScenariosScenario Control TechnologySO2NOxParticulate MatterControlScenarioSV #Emission UnitSO2NOx%ReductionMax24-hourlbs/hr%ReductionMax24-hourlbs/hrPM10Max 24-hrlbs/hrPM2.5Max 24-hrlbs/hrPMcoarseMax 24-hrlbs/hr6Base(Wet PM Scrubbers)Base:NG on L1 & L2;Priorto Heat Recoup on L1SV 046Line 1 SV 0460%80%120818SV 048Line 2 SV 0480%200%95381SV 049Line 2 SV 0490%220%1068528Base(Wet PM Scrubbers)Base: Solid fuel on L2; fueloil on L1; heat recoup on L1SV 046Line 1 SV 0460.0%19946%65118SV 048Line 2 SV 0480.0%3460%20381SV 049Line 2 SV 0490.0%2870%173522Base(Wet PM Scrubbers)Base:NG on L1&L2; heatrecoup on L1SV 046Line 1 SV 0460.0%846%65118SV 048Line 2 SV 0480.0%200%95381SV 049Line 2 SV 0490.0%220%1068521Base(Wet PM Scrubbers)Base: Solid fuel on L2; NGon L1; heat recoup on L1SV 046Line 1 SV 0460.0%846%65118SV 048Line 2 SV 0480.0%3460%20381SV 049Line 2 SV 0490.0%2870%173523Wet Walled ESP onLine 2Base Solid Fuel on L2; NGon L1; heat recoup on L1SV 046Line 1 SV 0460%80%65118C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc63Scenario Control TechnologySO2NOxParticulate MatterControlScenarioSV #Emission UnitSO2NOx%ReductionMax24-hourlbs/hr%ReductionMax24-hourlbs/hrPM10Max 24-hrlbs/hrPM2.5Max 24-hrlbs/hrPMcoarseMax 24-hrlbs/hrSV 048Line 2 SV 04880%690%20381SV 049Line 2 SV 04980%570%173524Wet SO2 Scrubber onLine 2(secondary scrubber)Base Solid Fuel on L2; NGon L1; heat recoup on L1SV 046Line 1 SV 0460%8065118SV 048Line 2 SV 04860%138020381SV 049Line 2 SV 04960%1150173527Base(Wet PM Scrubbers)Base: NG on L1&L2; heatrecoup on L1; SCR on L2SV 046Line 1 SV 0460.0%846%65118SV 048Line 2 SV 0480.0%2080%19181SV 049Line 2 SV 0490.0%2280%21452Table 6-2 Post-Control NOXModeling Scenarios - Modeling Input DataControlScenarioSV #Emission UnitStack Easting(utm)Stack Northing(utm)Height ofOpeningfromGround(ft)BaseElevation ofGround(ft)Stacklength,width, orDiameter(ft)Flow Rate atexit(acfm)Exit Temp(oF)All46Line 1 SV 046532024.985244399.8814013821036913712948Line 2 SV 048531995.035244364.9815313711234600012749Line 2 SV 049531983.415244432.55153137812380000115C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc64Table 6-3 Post-Control Modeling Scenarios - Visibility Modeling Results2002200320042002 – 2004CombinedScenario #Class IArea withGreatestImpactModeled98thPercentile Value(deciview)No. ofdaysexceeding 0.5deciviewModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciviewModeled98thPercentileValue(deciview)No. of daysexceeding0.5deciview6BaseBWCA3.51214.01164.71034.03408BaseBWCA1.6782.1742.2622.02142 BaseBWCA3.01143.51154.0973.53261BaseBWCA1.5661.9672.0531.81863 WWESPBWCA1.3571.6621.9471.61664 Secondary WetScrubberBWCA1.4591.7651.9491.71737 SCR with NatGas on Line 2BWCA1.6571.8532.1501.8160C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc65Table 6-4 Post-Control Modeling Scenarios - Visibility Modeling ResultsModeling Results02002200320042002-2004ScenarioLimitingClass IAreaImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dVImprovedModeled98thPercentileValue(∆-dV)DecreasedNo. of Daysexceeding0.5 dV2BWCA0.570.510.760.5143BWCA0.190.350.160.2204BWCA0.170.220.140.1137BWCA1.6571.8532.1501.8160C:\Documents and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc66ScenarioSO2NOxAnnualizedCost ($/yr)ImprovedModeled 98thPercentileValue(∆-dV)$/dV2Base(Wet PM Scrubbers)Solid fuels on L2; NGon L1; Heat Recoup onL1--0.7--3Wet Walled ESP onLine 2Solid fuels on L2; NGon L1; Heat Recoup onL1$16,872,5710.1$117,990,0104Wet SO2Scrubber onLine 2(secondary scrubber)Solid fuels on L2; NGon L1; Heat Recoup onL1$5,590,4980.1$52,247,6457Base(Wet PM Scrubbers)Nat Gas with SCR onL2; NG with heatrecoup on L1$37,770,1232.1$17,985,773Table 6-5 Post-Control Modeling Results – Dollars per Deciview Improvementments and Settings\bth\My Documents\@Projects\BART\Utac\REV Utac BART Report_DRAFT (2006-08-30).doc67C:\Docu

# 7. Select BART

BART for United Taconite is determined to be as described below.

For SO 2 

# , polishing add-on controls are not cost effectiv e. Therefore, BART is determined to be
existing controls. The corresponding SO 2 

# emissions limit is 2 lb per million Btu heat input for Line 1
when liquid fuel is burned. For Line 2, the BART limit is 4 lb per million Btu heat input when solid
fuel is burned or 2 lb per million Btu heat input when liquid fuel is burned.

For NO
x 

# , the reduction due to the heat recuperation pr oject on Line 1is selected as BART. Other addon controls for NO
x 

# are not cost effective. The NO
x 

# reductions for the heat recuperation project have
been established through stack testing on Li ne 1. This represents a reduction in NO
x 

# emissions by
557 lb per hr. Heat recoup is integral to the process, therefore no li mitation is required.

For PM, requirements compelled by the Octobe r 30, 2006 MACT standard constitute BART. The
corresponding emissions limits ar e equivalent to the limits identified in Table 3-1.

The overall improvement in visibility contribution is a reduction by 15%. This represents a
significant contribution to the defaul t glide path of reducing impacts by 1-2% per year. The schedule
for implementation of controls is by October 30, 2006, well in advance of the 5-year time-frame
required for BART implementation.

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# 68Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 1>: Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonSelective Catalytic Reduction (SCR) + ReheatLine 1 Pellet Induration80% 399.7 1751.5$44,591,384$23,923,236$13,659NALine 2 Pellet Induration80% 35.0 1598.3 $70,762,832$35,189,143$22,017NALine 2 Pellet Induration NG80% 188.7 7975.8 $72,222,298$37,770,123$4,736NAEnergy Efficiency Project - Heat Recoup on Line 1Line 1 Pellet Induration46% --- --- ---SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled CapitalCost $Total Annual Cost$/yrPollution ControlCost $/tonIncrementalControl Cost$/tonWet Walled Electrostatic Precipitator (WWESP)Line 1 Pellet Induration80% 2.8 11.1 $29,805,809$7,441,650$671,145NALine 2 Pellet Induration80% 549.9 2199.7 $41,621,612$17,974,280$8,171$22,600Wet Scrubber (Additional)Line 1 Pellet Induration60% 5.5 8.3 $20,773,230$3,196,687$384,402NALine 2 Pellet Induration60% 1099.9 1649.8 $28,067,807$5,545,472$3,361NAY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsCost Summary9/7/2006 Page 1 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 2>: - Summary of Utility, Chemical and Supply CostsOperating Unit:Line 1 Pellet IndurationStudy Year2006Emission Unit NumberEU 040Stack/Vent NumberSV 046Operating Unit:Line 2 Pellet IndurationEmission Unit Number EU 042Stack/Vent Number SV 048 & 049Line 1 furnacemmbtu 190Line 2 furnace mmbtu400ReferenceItem Unit Cost Units Cost Year Data Source NotesOperating Labor45.31 $/hr 2006Site Specific - United Taconite.Maintenance Labor47.22 $/hr 2006Site Specific - United Taconite.Construction Labor Rate.Electricity0.04 $/kwh 2006Site Specific - United Taconite.Purchased Cost.Natural Gas12.81 $/mscf 2006Site Specific - United Taconite. $12.02/MMBtu @ 1066 Btu/scf.Water2.07 $/mgal 2006Site Specific - United Taconite.Purchased Cost.Cooling Water0.28 $/mgal 0.23 1999EPA Air Pollution Control Cost Manual, 6thed. Section 3.1 Ch 1.Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and3% inflation.Compressed Air0.32 $/mscf 0.25 1998EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 1 .Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflation.Wastewater Disposal Neutralization3.13 $/mgal 2006Site Specific - United Taconite. Purchased Cost.Chemicals & SuppliesLime88.98 $/ton 88.98 2006Estimate from Cutler Magney CompanyOxygen40.00 $/ton 2006BOC estimate.Ammonia (29% aqua.)0.12 $/lb 0.101 2000EPA Air Pollution Control Cost Manual 6th Ed2002, Section 5 Chapter 2, page 2-50.Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic484.56 $/ton 280 2003 United Taconite 2006 costOtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Operating InformationAnnual Op. Hrs EU0406599 HoursBART spreadsheet.Maximum hours of operation 2004-2005 with a 10% safety factor.Annual Op. Hrs EU0428688 HoursBART spreadsheet.Maximum hours of operation 2004-2005 with a 10% safety factor.Utilization Rate93%Equipment Life20 yrsStandardized Flow RateSV 046 308,345 scfm @ 32o FCalculated.SV 048 & 049 615,086 scfm @ 32o FCalculated.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsUtility Chem$ Data9/7/2006 Page 2 of 40Line 2 furnace mmbtu400ReferenceItem Unit Cost Units Cost Year Data Source NotesTemperatureSV 046 129 Deg FBART spreadsheet.SV 048 & 049 121 Deg FBART spreadsheet. Weighted average.Moisture ContentSV 046 13.8% 2005Y:\23\69\948 United Taconite Post EERPTesting\Data\Waste Gas Stack. Average from test results in : Line 1 WG pm 5-2-05.SV 048 & 049 13.8% 2005Y:\23\69\872 United Tac\Data. Weighted average from test results in: SV049 2BPM and SV048 2APM.Actual Flow RateSV 046 369,137 acfmBART spreadsheet.SV 048 & 049 726,000 acfmBART spreadsheet.Standardized Flow RateSV 046 330,907 scfm @ 68o FCalculated.SV 048 & 049 660,092 scfm @ 68o FCalculated.Dry Std Flow RateSV 046 285,110 dscfm @ 68o FCalculated.SV 048 & 049 568,896 dscfm @ 68o FCalculated.Max Emis Actual Emissions lb/hr ton/yearPollutant Lb/Hr Ton/year ('04&'05 Max) ppmv ppmvlb/mmbtuNitrous Oxides (NOx)SV 046 651.3 2,151.2 319 240.2 3.428070175 2005 plus 10%SV 048 & 049 375.2 1,633.3 92 91.4 8.279997057 2004 plus 10%SV 048 & 049 with NG only 2021.0 8,164.5 495 457.0Sulfur Dioxides (SO2)SV 046 4.2 13.9 1 1.1 2004 plus 10%SV 048 & 049 632.2 2,749.7 111 110.5 2004 plus 10%estimatecalculated valueknown or assumed datarequired dataY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsUtility Chem$ Data9/7/2006 Page 3 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2Control - Wet Walled Electrostatic PrecipitatorOperating Unit:Line 1 Pellet IndurationEmission Unit Number EU 040 Stack/Vent Number SV 046Standardized Flow Rate 308,345 scfm @ 32o FExpected Utilization Rate 93% Temperature 129 Deg FExpected Annual Hours of Operation 6,599 Hours Moisture Content 13.8%Annual Interest Rate7.0%Actual Flow Rate369,137 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o FDry Std Flow Rate 285,110 dscfm @ 68o FCONTROL EQUIPMENT COSTSCapital CostsDirect Capital CostsPurchased Equipment (A)5,420,940Purchased Equipment Total (B) 22% of control device cost (A)6,586,442Installation - Standard Costs67% of purchased equip cost (B)4,412,916Installation - Site Specific Costs6,200,000Installation Total4,412,916Total Direct Capital Cost, DC10,999,359Total Indirect Capital Costs, IC57%of purchased equip cost (B) 3,754,272Total Capital Investment (TCI) = DC + IC29,805,809Operating CostsTotal Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,935,246Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,506,404Total Annual Cost (Annualized Capital Cost + Operating Cost)7,441,650ActualEmission Control Cost CalculationEmissionsMax Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr%T/yr T/yr $/Ton RemNitrous Oxides (NOx) 651.32,151.20% 2151.2 -NASulfur Dioxide (SO2)4.213.980% 2.8 11.1671,145Notes & Assumptions1Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.2Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.3CUECost Workbook Version 1.0, USEPA Document Page 2.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 WWESP9/7/2006 Page 4 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2 Control - Wet Walled Electrostatic PrecipitatorCAPITAL COSTSDirect Capital CostsPurchased Equipment (A)1Purchased Equipment Costs (A)2- ESP + auxiliary equipment5,420,940Instrumentation 10% of control device cost (A) 542,094MN Sales Taxes 6.5% of control device cost (A) 352,361Freight 5% of control device cost (A) 271,047Purchased Equipment Total (B)22%6,586,442InstallationFoundations & supports4% of purchased equip cost (B)263,458Handling & erection 50% of purchased equip cost (B) 3,293,221Electrical 8% of purchased equip cost (B) 526,915Piping 1% of purchased equip cost (B) 65,864Insulation 2% of purchased equip cost (B) 131,729Painting 2% of purchased equip cost (B)131,729Installation Subtotal Standard Expenses67%4,412,916Total Direct Capital Cost, DC10,999,359Indirect Capital CostsEngineering, supervision 20% of purchased equip cost (B) 1,317,288Construction & field expenses 20%of purchased equip cost (B) 1,317,288Contractor fees 10%of purchased equip cost (B) 658,644Start-up 1%of purchased equip cost (B) 65,864Performance test 1%of purchased equip cost (B) 65,864Model Studies 2%of purchased equip cost (B)131,729Contingencies 3%of purchased equip cost (B) 197,593Total Indirect Capital Costs, IC57%of purchased equip cost (B)3,754,272Total Capital Investment (TCI) = DC + IC14,753,631Retrofit multiplier360% of TCI8,852,178Sitework and foundationsSite Specific1,400,000Structural steel Site Specific 4,800,000Site Specific - Other Site Specific NATotal Site Specific Costs6,200,000Total Capital Investment (TCI) Retrofit Installed29,805,809OPERATING COSTSDirect Annual Operating Costs, DCOperating LaborOperator45.31 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours74,749Supervisor15% 15% of Operator Costs11,212MaintenanceMaintenance Labor47.22 $/Hr, 15.0 hr/wk, Annual Operating Hours31,165Maintenance Materials1.00 % of Maintenance Labor54,209Utilities, Supplies, Replacements & Waste ManagementElectricity0.04 $/kwh, 872 kW-hr, annual operating hours, 93% utilization214,127Water2.07 $/mgal, 1,846 gpm, annual operating hours, 93% utilization 1,406,804WW Treat Neutralization3.13 $/mgal, 1,846 gpm, annual operating hours, 93% utilization 2,127,197Caustic484.56 $/ton, 11 lb/hr, 6598.9 hr/yr, 93% utilization15,782Total Annual Direct Operating Costs3,935,246Indirect Operating CostsOverhead 60% of total labor and material costs 102,802Administration (2% total capital costs) 2% of total capital costs (TCI) 295,073Property tax (1% total capital costs) 1% of total capital costs (TCI) 147,536Insurance (1% total capital costs) 1% of total capital costs (TCI) 147,536Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,813,458Total Annual Indirect Operating CostsSum indirect oper costs + capital recovery cost3,506,404Total Annual Cost (Annualized Capital Cost + Operating Cost)7,441,650See summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 WWESP9/7/2006 Page 5 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 3>: SO2 Control - Wet Walled Electrostatic PrecipitatorCapital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unitAmount Required0Total Rep Parts Cost 0Installation Labor 0Total Installed Cost0Annualized Cost0Electrical UseFlow acfm D P in H2OkWFan Power 369,137 10 668.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46Fluid Head (ft) Pump Eff.Pump Power60 60%34.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47Plate AreaESP Power87,305169.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48Total872.3Reagent Use & Other Operating CostsgpmWater 5.00 gal/min-kacfm 1845.69 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6lb/hrReagent Use2.50 lb NaOH/lb SO210.61 lb/hr causticOperating Cost CalculationsAnnual hours of operation:6,599Utilization Rate:93.0%Unit Unit of Use Unit ofAnnualAnnual CommentsItem Cost $ Measure Rate Measure Use*CostOperating LaborOp Labor 45.31 $/Hr 2.0 hr/8 hr shift 1,650 74,749 $/Hr, 2.0 hr/8 hr shift, Annual Operating HoursSupervisor 15% of Op. NA 11,21215% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 15.0 hr/wk 660 31,165 $/Hr, 15.0 hr/wk, Annual Operating HoursMaint Mtls 1 % of Purchase Cost NA 54,209 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1Utilities, Supplies, Replacements & Waste ManagementElectricity0.040 $/kwh872.3 kW-hr 5,353,163 214,127 $/kwh, 872 kW-hr, annual operating hours, 93% utilizationWater2.07 $/mgal1,845.7 gpm679,616 1,406,804 $/mgal, 1,846 gpm, annual operating hours, 93% utilizationWW Treat Neutralization3.13 $/mgal1,845.7 gpm679,616 2,127,197 $/mgal, 1,846 gpm, annual operating hours, 93% utilizationCaustic 484.56 $/ton 10.6 lb/hr 33 15,782 $/ton, 11 lb/hr, 6598.9 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factorSee summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 WWESP9/7/2006 Page 6 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2Control - Wet Walled Electrostatic PrecipitatorOperating Unit:Line 2 Pellet IndurationEmission Unit Number EU 042 Stack/Vent Number SV 048 & 049Standardized Flow Rate 615,086 scfm @ 32o FExpected Utilization Rate 93% Temperature 121 Deg FExpected Annual Hours of Operation 8,688 Hours Moisture Content 13.8%Annual Interest Rate7.0%Actual Flow Rate726,000 acfmExpected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o FDry Std Flow Rate 568,896 dscfm @ 68o FCONTROL EQUIPMENT COSTSCapital CostsDirect Capital CostsPurchased Equipment (A)8,134,372Purchased Equipment Total (B) 22% of control device cost (A)9,883,262Installation - Standard Costs67% of purchased equip cost (B)6,621,786Installation - Site Specific Costs6,200,000Installation Total6,621,786Total Direct Capital Cost, DC16,505,048Total Indirect Capital Costs, IC57%of purchased equip cost (B) 5,633,459Total Capital Investment (TCI) = DC + IC41,621,612Operating CostsTotal Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 13,024,545Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,949,735Total Annual Cost (Annualized Capital Cost + Operating Cost)17,974,280ActualEmission Control Cost CalculationEmissionsMax Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr%T/yr T/yr $/Ton RemNitrous Oxides (NOx) 375.21,633.30% 1633.3 -NASulfur Dioxide (SO2)632.22,749.780% 549.9 2,199.78,171Notes & Assumptions1Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.2Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm.3CUECost Workbook Version 1.0, USEPA Document Page 2.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 WWESP9/7/2006 Page 7 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2 Control - Wet Walled Electrostatic PrecipitatorCAPITAL COSTSDirect Capital CostsPurchased Equipment (A)1Purchased Equipment Costs (A)2- ESP + auxiliary equipment8,134,372Instrumentation 10% of control device cost (A) 813,437MN Sales Taxes 6.5% of control device cost (A) 528,734Freight 5% of control device cost (A) 406,719Purchased Equipment Total (B)22%9,883,262InstallationFoundations & supports4% of purchased equip cost (B)395,330Handling & erection 50% of purchased equip cost (B) 4,941,631Electrical 8% of purchased equip cost (B) 790,661Piping 1% of purchased equip cost (B) 98,833Insulation 2% of purchased equip cost (B) 197,665Painting 2% of purchased equip cost (B)197,665Installation Subtotal Standard Expenses67%6,621,786Total Direct Capital Cost, DC16,505,048Indirect Capital CostsEngineering, supervision 20% of purchased equip cost (B) 1,976,652Construction & field expenses 20%of purchased equip cost (B) 1,976,652Contractor fees 10%of purchased equip cost (B) 988,326Start-up 1%of purchased equip cost (B) 98,833Performance test 1%of purchased equip cost (B) 98,833Model Studies 2%of purchased equip cost (B)197,665Contingencies 3%of purchased equip cost (B) 296,498Total Indirect Capital Costs, IC57%of purchased equip cost (B)5,633,459Total Capital Investment (TCI) = DC + IC22,138,507Retrofit multiplier360% of TCI13,283,104Sitework and foundationsSite Specific1,400,000Structural steel Site Specific 4,800,000Site Specific - Other Site Specific NATotal Site Specific Costs6,200,000Total Capital Investment (TCI) Retrofit Installed41,621,612OPERATING COSTSDirect Annual Operating Costs, DCOperating LaborOperator45.31 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours98,411Supervisor15% 15% of Operator Costs14,762MaintenanceMaintenance Labor47.22 $/Hr, 15.0 hr/wk, Annual Operating Hours31,165Maintenance Materials1.00 % of Maintenance Labor81,344Utilities, Supplies, Replacements & Waste ManagementElectricity0.04 $/kwh, 1,716 kW-hr, annual operating hours, 93% utilization 554,444Water2.07 $/mgal, 3,630 gpm, annual operating hours, 93% utilization 3,642,680WW Treat Neutralization3.13 $/mgal, 3,630 gpm, annual operating hours, 93% utilization 5,508,013Caustic484.56 $/ton, 1,580 lb/hr, 8687.8 hr/yr, 93% utilization3,093,727Total Annual Direct Operating Costs13,024,545Indirect Operating CostsOverhead 60% of total labor and material costs 135,409Administration (2% total capital costs) 2% of total capital costs (TCI) 442,770Property tax (1% total capital costs) 1% of total capital costs (TCI) 221,385Insurance (1% total capital costs)1% of total capital costs (TCI)221,385Capital Recovery0.0944 for a 20- year equipment life and a 7% interest rate3,928,786Total Annual Indirect Operating CostsSum indirect oper costs + capital recovery cost4,949,735Total Annual Cost (Annualized Capital Cost + Operating Cost)17,974,280See summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 WWESP9/7/2006 Page 8 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 4>: SO2 Control - Wet Walled Electrostatic PrecipitatorCapital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unitAmount Required0Total Rep Parts Cost 0Installation Labor 0Total Installed Cost0Annualized Cost0Electrical UseFlow acfm D P in H2OkWFan Power 726,000 10 1,314.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46Fluid Head (ft) Pump Eff.Pump Power60 60%68.4 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47Plate AreaESP Power171,708333.1 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48Total1,715.6Reagent Use & Other Operating CostsgpmWater 5.00 gal/min-kacfm 3630.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6lb/hrReagent Use2.50 lb NaOH/lb SO21580.42 lb/hr causticOperating Cost CalculationsAnnual hours of operation:8,688Utilization Rate:93.0%Unit Unit of Use Unit ofAnnualAnnual CommentsItem Cost $ Measure Rate Measure Use*CostOperating LaborOp Labor 45.31 $/Hr 2.0 hr/8 hr shift 2,172 98,411 $/Hr, 2.0 hr/8 hr shift, Annual Operating HoursSupervisor 15% of Op. NA 14,76215% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 15.0 hr/wk 660 31,165 $/Hr, 15.0 hr/wk, Annual Operating HoursMaint Mtls 1 % of Purchase Cost NA 81,344 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1Utilities, Supplies, Replacements & Waste ManagementElectricity0.040 $/kwh1715.6 kW-hr 13,861,102 554,444 $/kwh, 1,716 kW-hr, annual operating hours, 93% utilizationWater2.07 $/mgal3,630.0 gpm1,759,749 3,642,680 $/mgal, 3,630 gpm, annual operating hours, 93% utilizationWW Treat Neutralization3.13 $/mgal3,630.0 gpm1,759,749 5,508,013 $/mgal, 3,630 gpm, annual operating hours, 93% utilizationCaustic484.56 $/ton1,580.4 lb/hr6,385 3,093,727 $/ton, 1,580 lb/hr, 8687.8 hr/yr, 93% utilization*annual use rate is in same units of measurement as the unit cost factorSee summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 WWESP9/7/2006 Page 9 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOxControl - Wet ScrubberOperating Unit:Line 1 Pellet IndurationEmission Unit Number EU 040 Stack/Vent Number SV 046Standardized Flow Rate 308,345 scfm @ 32o FExpected Utilization Rate 93% Temperature 129 Deg FExpected Annual Hours of Operation 6,599 Hours Moisture Content 13.8%Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfmExpected Equipment Life 20 yrs Standardized Flow Rate330,907 scfm @ 68o FDry Std Flow Rate 285,110 dscfm @ 68o FCONTROL EQUIPMENT COSTSCapital CostsDirect Capital Costs (1)Purchased Equipment (A)3,748,259Purchased Equipment Total (B) 22% of control device cost (A)4,554,134Installation - Standard Costs 85% of purchased equip cost (B)3,871,014Installation - Site Specific Costs6,200,000Installation Total3,871,014Total Direct Capital Cost, DC8,425,148Total Indirect Capital Costs, IC 15%of purchased equip cost (B)683,120Total Capital Investment (TCI) = DC + IC20,773,230Operating CostsTotal Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 835,246Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,361,441Total Annual Cost (Annualized Capital Cost + Operating Cost)3,196,687ActualEmission Control Cost CalculationEmissionsMax Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/HrT/Yr%T/yrT/yr$/Ton RemNitrous Oxides (NOx) 651.32,151.20% 2151.2 -NASulfur Dioxide (SO2)4.213.960% 5.5 8.3384,402Notes & Assumptions1Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.2Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.3Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.4Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.5CUECost Workbook Version 1.0, USEPA Document Page 2.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 Wet Scrubber9/7/2006 Page 10 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet ScrubberCAPITAL COSTSDirect Capital CostsPurchased Equipment (A) (1)Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,748,259Instrumentation 10% of control device cost (A) 374,826MN Sales Taxes 7% of control device cost (A) 243,637Freight 5% of control device cost (A) 187,413Purchased Equipment Total (B)22%4,554,134InstallationFoundations & supports12% of purchased equip cost (B)546,496Handling & erection40% of purchased equip cost (B)1,821,654Electrical1% of purchased equip cost (B)45,541Piping30% of purchased equip cost (B)1,366,240Insulation1% of purchased equip cost (B)45,541Painting1% of purchased equip cost (B)45,541Installation Subtotal Standard Expenses85%3,871,014Total Direct Capital Cost, DC8,425,148Indirect Capital CostsEngineering, supervision5%of purchased equip cost (B)227,707Construction & field expenses0%of purchased equip cost (B)0Contractor fees5%of purchased equip cost (B)227,707Start-up 1%of purchased equip cost (B)45,541Performance test1%of purchased equip cost (B)45,541Model StudiesNAof purchased equip cost (B)NAContingencies 3%of purchased equip cost (B)136,624Total Indirect Capital Costs, IC15%of purchased equip cost (B)683,120Total Capital Investment (TCI) = DC + IC9,108,269Retrofit multiplier560% of TCI5,464,961Sitework and foundationsSite Specific1,400,000Structural steelSite Specific4,800,000Site Specific - OtherSite Specific0Total Site Specific Costs6,200,000Total Capital Investment (TCI) Retrofit Installed20,773,230Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 Wet Scrubber9/7/2006 Page 11 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet ScrubberOPERATING COSTSDirect Annual Operating Costs, DCOperating LaborOperator37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours18,687Supervisor15% 15% of Operator Costs2,803MaintenanceMaintenance Labor40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours19,475Maintenance Materials100% of maintenance labor costs19,475Utilities, Supplies, Replacements & Waste ManagementElectricity0.04 $/kwh, 759 kW-hr, annual operating hours, 93% utilization186,351Water2.07 $/kgal, 346 gpm, annual operating hours, 93% utilization264,005WW Treat Neutralization3.13 $/kgal, 281 gpm, annual operating hours, 93% utilization323,334Lime88.98 $/ton, 4 lb/hr, annual operating hours, 93% utilization1,116Total Annual Direct Operating Costs835,246Indirect Operating CostsOverhead60% of total labor and material costs36,264Administration (2% total capital costs)2% of total capital costs (TCI)182,165Property tax (1% total capital costs)1% of total capital costs (TCI)91,083Insurance (1% total capital costs)1% of total capital costs (TCI)91,083Capital Recovery0.0944 for a 20- year equipment life and a 7% interest rate1,960,846Total Annual Indirect Operating CostsSum indirect oper costs + capital recovery cost2,361,441Total Annual Cost (Annualized Capital Cost + Operating Cost)3,196,687See Summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 Wet Scrubber9/7/2006 Page 12 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet ScrubberCapital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Catalyst:Equipment Life 20 yearsCRF 0.0000Rep part cost per unit 0$/ft3Amount Required0ft3Packing Cost0 Cost adjusted for freight & sales taxInstallation Labor 0Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)Total Installed Cost0 Zero out if no replacement parts neededAnnualized Cost0Replacement Parts & Equipment:Equipment Life 3CRF 0.3811Rep part cost per unit 0.00 $ eachAmount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.Total Installed Cost0 Zero out if no replacement parts neededAnnualized Cost0Electrical UseFlow acfm∆P in H2OEfficiency HpkWBlower, Scrubber 369,137 8.55 0.7 - 527.5 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48FlowLiquid SPGR∆P ft H2OEfficiency HpkWCirc Pump 14,027 gpm 1 60 0.7 - 226.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49H2O WW Disch346 gpm1 60 0.7-5.6 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49OtherTotal759.1Reagent Use & Other Operating CostsCaustic Use4.25 lb/hr SO22.50lb NaOH/lb SO210.61 lb/hr CausticLime Use 4.25 lb/hr SO2 0.96lb Lime/lb SO24.09 lb/hr lime, lime addition at 1.1 times the stoichiometric ratioLiquid/Gas ratio 38.0 * L/G = Gal/1,000 acfCirculating Water Rate214,027 gpmWater Makeup Rate/WW Disch3=2.0% of circulating water rate + evap. loss = 346 gpmEvaporation Loss4=65.82 gpmY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 Wet Scrubber9/7/2006 Page 13 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 5>: SOx Control - Wet ScrubberOperating Cost CalculationsAnnual hours of operation:6,599Utilization Rate:93%Unit Unit of Use Unit of Annual Annual CommentsItemCost $ Measure Rate Measure Use*CostOperating LaborOp Labor 45.31 $/Hr 0.5 hr/8 hr shift 412 18,687 $/Hr, 0.5 hr/8 hr shift, Annual Operating HoursSupervisor 15% of Op. NA 2,80315% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 0.5 hr/8 hr shift 412 19,475 $/Hr, 0.5 hr/8 hr shift, Annual Operating HoursMaint Mtls 100 % of Maintenance Labor NA 19,475 100% of Maintenance LaborUtilities, Supplies, Replacements & Waste ManagementElectricity 0.040 $/kwh 759.1 kW-hr 4,658,783 186,351 $/kwh, 759 kW-hr, annual operating hours, 93% utilizationWater 2.07 $/kgal 346.4 gpm 127,538 264,005 $/kgal, 346 gpm, annual operating hours, 93% utilizationWW Treat Neutralization3.13 $/kgal280.5 gpm103,302323,334 $/kgal, 281 gpm, annual operating hours, 93% utilizationLime89.0 $/ton4.1 lb/hr131,116 $/ton, 4 lb/hr, annual operating hours, 93% utilization*annual use rate is in same units of measurement as the unit cost factorSee Summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU040 Wet Scrubber9/7/2006 Page 14 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOxControl - Wet ScrubberOperating Unit:Line 2 Pellet IndurationEmission Unit Number EU 042 Stack/Vent Number SV 048 & 049Standardized Flow Rate 615,086 scfm @ 32o FExpected Utilization Rate93%Temperature121 Deg FExpected Annual Hours of Operation8,688 HoursMoisture Content13.8%Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfmExpected Equipment Life20 yrsStandardized Flow Rate660,092 scfm @ 68o FDry Std Flow Rate 568,896 dscfm @ 68o FCONTROL EQUIPMENT COSTSCapital CostsDirect Capital Costs (1)Purchased Equipment (A)5,624,436Purchased Equipment Total (B)22% of control device cost (A)6,833,690Installation - Standard Costs85% of purchased equip cost (B)5,808,636Installation - Site Specific Costs6,200,000Installation Total5,808,636Total Direct Capital Cost, DC12,642,326Total Indirect Capital Costs, IC 15%of purchased equip cost (B)1,025,053Total Capital Investment (TCI) = DC + IC28,067,807Operating CostsTotal Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,301,630Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,243,841Total Annual Cost (Annualized Capital Cost + Operating Cost)5,545,472ActualEmission Control Cost CalculationEmissionsMax Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yrT/yr$/Ton RemNitrous Oxides (NOx) 375.21,633.30% 1633.3 -NASulfur Dioxide (SO2)632.22,749.760% 1099.9 1,649.83,361Notes & Assumptions1Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.2Liquid/Gas ratio = 38 L/G = Gal/1,000 acf.3Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate.4Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.5CUECost Workbook Version 1.0, USEPA Document Page 2.Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 Wet Scrubber9/7/2006 Page 15 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet ScrubberCAPITAL COSTSDirect Capital CostsPurchased Equipment (A) (1)Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,624,436Instrumentation 10% of control device cost (A) 562,444MN Sales Taxes 7% of control device cost (A) 365,588Freight 5% of control device cost (A) 281,222Purchased Equipment Total (B)22%6,833,690InstallationFoundations & supports 12% of purchased equip cost (B) 820,043Handling & erection 40% of purchased equip cost (B) 2,733,476Electrical 1% of purchased equip cost (B)68,337Piping 30% of purchased equip cost (B) 2,050,107Insulation 1% of purchased equip cost (B)68,337Painting 1% of purchased equip cost (B)68,337Installation Subtotal Standard Expenses85%5,808,636Total Direct Capital Cost, DC12,642,326Indirect Capital CostsEngineering, supervision 5%of purchased equip cost (B) 341,684Construction & field expenses 0%of purchased equip cost (B) 0Contractor fees 5%of purchased equip cost (B) 341,684Start-up 1%of purchased equip cost (B)68,337Performance test1%of purchased equip cost (B)68,337Model Studies NAof purchased equip cost (B) NAContingencies 3%of purchased equip cost (B) 205,011Total Indirect Capital Costs, IC15%of purchased equip cost (B)1,025,053Total Capital Investment (TCI) = DC + IC13,667,380Retrofit multiplier560% of TCI8,200,428Sitework and foundations Site Specific 1,400,000Structural steel Site Specific 4,800,000Site Specific - OtherSite Specific0Total Site Specific Costs6,200,000Total Capital Investment (TCI) Retrofit Installed28,067,807Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 Wet Scrubber9/7/2006 Page 16 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet ScrubberOPERATING COSTSDirect Annual Operating Costs, DCOperating LaborOperator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 24,603Supervisor 15% 15% of Operator Costs 3,690MaintenanceMaintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 25,640Maintenance Materials 100% of maintenance labor costs 25,640Utilities, Supplies, Replacements & Waste ManagementElectricity 0.04 $/kwh, 1,493 kW-hr, annual operating hours, 93% utilizatio 482,525Water 2.07 $/kgal, 681 gpm, annual operating hours, 93% utilization 683,595WW Treat Neutralization 3.13 $/kgal, 552 gpm, annual operating hours, 93% utilization 837,218Lime 88.98 $/ton, 608 lb/hr, annual operating hours, 93% utilization 218,719Total Annual Direct Operating Costs2,301,630Indirect Operating CostsOverhead 60% of total labor and material costs 47,744Administration (2% total capital costs) 2% of total capital costs (TCI) 273,348Property tax (1% total capital costs) 1% of total capital costs (TCI) 136,674Insurance (1% total capital costs) 1% of total capital costs (TCI) 136,674Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,649,402Total Annual Indirect Operating CostsSum indirect oper costs + capital recovery cost3,243,841Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,545,472See Summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 Wet Scrubber9/7/2006 Page 17 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet ScrubberCapital Recovery FactorsPrimary InstallationInterest Rate 7.00%Equipment Life 20 yearsCRF 0.0944Replacement Catalyst:Equipment Life20 yearsCRF 0.0000Rep part cost per unit 0$/ft3Amount Required0ft3Packing Cost0 Cost adjusted for freight & sales taxInstallation Labor0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)Total Installed Cost0 Zero out if no replacement parts neededAnnualized Cost0Replacement Parts & Equipment:Equipment Life3CRF 0.3811Rep part cost per unit 0.00 $ eachAmount Required 0 NumberTotal Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.Total Installed Cost0 Zero out if no replacement parts neededAnnualized Cost0Electrical UseFlow acfm∆P in H2OEfficiencyHpkWBlower, Scrubber 726,0008.55 0.7-1,037.5 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48FlowLiquid SPGR∆P ft H2OEfficiency HpkWCirc Pump 27,588 gpm 1 60 0.7 - 444.5 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49H2O WW Disch681 gpm1 60 0.7-11.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49OtherTotal1493.0Reagent Use & Other Operating CostsCaustic Use 632.17 lb/hr SO2 2.50lb NaOH/lb SO21580.42 lb/hr CausticLime Use 632.17 lb/hr SO2 0.96lb Lime/lb SO2608.46 lb/hr lime, lime addition at 1.1 times the stoichiometric ratioLiquid/Gas ratio 38.0 * L/G = Gal/1,000 acfCirculating Water Rate227,588 gpmWater Makeup Rate/WW Disch3=2.0% of circulating water rate + evap. loss = 681 gpmEvaporation Loss4=129.46 gpmY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 Wet Scrubber9/7/2006 Page 18 of 40Cleveland Cliffs Incorporated: United TaconiteBART Report - <Appendix A> Emission Control Cost Analysis<Table 6>: SOx Control - Wet ScrubberOperating Cost CalculationsAnnual hours of operation:8,688Utilization Rate:93%Unit Unit of Use Unit ofAnnualAnnual CommentsItem Cost $ Measure Rate Measure Use*CostOperating LaborOp Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, Annual Operating HoursSupervisor 15% of Op. NA 3,69015% of Operator CostsMaintenanceMaint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, Annual Operating HoursMaint Mtls 100 % of Maintenance Labor NA 25,640 100% of Maintenance LaborUtilities, Supplies, Replacements & Waste ManagementElectricity 0.040 $/kwh 1493.0 kW-hr 12,063,123 482,525 $/kwh, 1,493 kW-hr, annual operating hours, 93% utilizationWater 2.07 $/kgal 681.2 gpm 330,239 683,595 $/kgal, 681 gpm, annual operating hours, 93% utilizationWW Treat Neutralization3.13 $/kgal551.8 gpm267,482837,218 $/kgal, 552 gpm, annual operating hours, 93% utilizationLime89.0 $/ton608.5 lb/hr2,458218,719 $/ton, 608 lb/hr, annual operating hours, 93% utilization*annual use rate is in same units of measurement as the unit cost factorSee Summary page for notes and assumptionsY:\23\00 MN Taconite BART (2006)\Facility BART Reports\UTAC\United Taconite Control Costs.xlsEU042 Wet Scrubber9/7/2006 Page 19 of 40

## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 7: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046 Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 308,345 scfm @ 32o F Expected Utiliztion Rate 93% Temperature 129 Deg F Expected Annual Hours of Operation 6,599 Hours Moisture Content 13.8% Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment (A) 15,894,553 Purchased Equipment Total (B) SCR Only 16,927,699

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,935,740 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 44,591,384

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 18,389,200 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 5,534,036 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 23,923,236



### Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 2,151.2 130.3 0.69 399.7 1,751.5 13,659

Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.

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

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 7: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 15,894,553 Instrumentation 10% of control device cost (A) N A
MN Sales Taxes 6.5% of control device cost (A) 1,033,146 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 16,927,699

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 16% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 16% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,935,740

Total Plant Cost D A + B + C 22,507,337

Allowance for Funds During Construction (E)

Pre Production Costs (G) 2% of (D+E)) 450,147

Inventory Capital Reagent Vol * $/gal 289,894

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 23,247,378 Retrofit multiplier 3 60% of TCI 13,948,427 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost N A Total Retrofit Capital 37,195,804 

### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 2.0 hr/8 hr shift, 6598.9 hr/yr 74,749 Supervisor 15% 15% of Operator Costs 11,212
Maintenance

Maintenance Total 1.50 % of Total Capital Investment 348,711 Maintenance Materials N A % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 5,919 kW-hr, 6598.9 hr/yr, 93% utilization 1,453,059
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 747,654
NA NA - Ammonia 0.12 $/lb, 8,542 lb/hr, 6598.9 hr/yr, 93% utilization 6,322,342
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 8,957,727

Indirect Operating Costs Overhead 60% fixed O&M 62,942 Administration (2% total capital costs) 2% of total capital costs (TCI) 464,948 Property tax (1% total capital costs) 1% of total capital costs (TCI) 232,474 Insurance (1% total capital costs) 1% of total capital costs (TCI) 232,474 Capital Recovery 9.44% for a 20- year equipment life and a 7% interest rate 3,511,021 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,503,858

Total Annual Cost (Annualized Capital Cost + Operating Cost) 13,461,585

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 7: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 1,859 Plant Cap kW A 190,728 Est power platn eff 35% Unc Nox lb/mmBtu B 3.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066 Equivalent power plant k 190,728 Capital Cost $/kW D $83.34 $15,894,552.62 Total SCR Equipment Uncontrolled Nox t/y 2,151.2 Fixed O&M E $104,904.05 Annual Operating Hrs 8000 Variable O&M F $423,896.63 Uncontrolled Nox lb/mm 3.428 A nn Cap Factor G 0.82 Heat Input mmBtu / H 6,000 SCR Capital Cost

Duty 1,859 MMBtu/hr Catalyst Area 897 ft 2 1,352 f (h SCR) Q flue gas 861,164 acfm Rx Area 1,032 27 f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 32.1 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 3.43 lb/MMBtu n layer 51 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 53.6 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 52 layers 34,003,097 f (vol catalyst) Temperature 129 Deg F h SCR 252 ft f (h SCR) Catalyst Volume 141,680 ft 3 New/Retrofit R N or R

Electrical Use Duty 1,859 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 5,919.3
NOx in 3.43 lb/MMBtu n catalyst layers 52 layers
Press drop catalyst 1 in H 2 O per layer

Press drop duct 3 in H 2 O

Total 5919.3

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft 3 Density
2477 lb/hr Neat 1141.2 gal/hr 29% solution Volume 14 day inventory 383,433 gal $289,894 Inventory Cost
8542 lb/hr

Design Basis Baseline Em Baseline Emi Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.69 Nitrous Oxide 2,151.2 3.428 651.33

Actual 90,035 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu
A djusted Duty 1,859 MMBtu/h r

Operating Cost Calculations Annual hours of operation: 6,599 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 45.31 $/Hr 2.0 hr/8 hr shift 1,650 74,749 $/Hr, 2.0 hr/8 hr shift, 6598.9 hr/yr Supervisor 15% of Op. NA 11,212 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 348,711 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.040 $/kwh 5919.3 kW-hr 36,326,476 1,453,059 $/kwh, 5,919 kW-hr, 6598.9 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 190.7 mw 112 $747,654 Catalyst Replacement

7 A mmoni a 0.12 $/lb 8542 lb/hr 52,424,372 6,322,342 $/lb, 8,542 lb/hr, 6598.9 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis
<Table 8> : - Summary of Utility, Chemical and Supply Cost s

Operating Unit: Line 1 Pellet Induration

Emission Unit Number EU 040 Stack/Vent Number SV 046 Chemical Engineering Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 308,345 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 129 Deg F 1998/1999 390 Expected Annual Hours of Operation 6,599 Hours Moisture Content 13.8% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 369,137 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 330,907 scfm @ 68o F Dry Std Flow Rate 285,110 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 611,190 Purchased Equipment Total (B) 22% of control device cost (A) 742,596

Installation - Standard Costs 30% of purchased equip cost (B) 222,779 Installation - Site Specific Costs 6,200,000
Installation Total 6,422,779 Total Direct Capital Cost, DC 7,165,375 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 230,205 Total Capital Investment (TCI) = DC + IC 7,395,580

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 9,431,473 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,030,178 Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,461,651

Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis <Table 8>: - Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 611,190

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 61,119 MN Sales Taxes 6.5% of control device cost (A) 39,727 Freight 5% of control device cost (A) 30,560 Purchased Equipment Total (B) 22% 742,596

Installation

Foundations & supports 8% of purchased equip cost (B) 59,408 Handling & erection 14% of purchased equip cost (B) 103,963 Electrical 4% of purchased equip cost (B) 29,704
Piping 2% of purchased equip cost (B) 14,852 Insulation 1% of purchased equip cost (B) 7,426 Painting 1% of purchased equip cost (B) 7,426 Installation Subtotal Standard Expenses 30% 222,779

Site Preparation, as required Site Specific 1,400,000 Buildings, as required Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Installation Total 6,422,779 Total Direct Capital Cost, DC 7,165,375

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 74,260 Construction & field expenses 5% of purchased equip cost (B) 37,130 Contractor fees 10% of purchased equip cost (B) 74,260 Start-up 2% of purchased equip cost (B) 14,852 Performance test 1% of purchased equip cost (B) 7,426 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 22,278 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 230,205

Total Capital Investment (TCI) = DC + IC 7,395,580

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,395,580



### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr 18,687 Supervisor 15% 15% of Operator Costs 2,803 Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr 19,475 Maintenance Materials 100% of maintenance labor costs 19,475 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.04 $/kwh, 1,368 kW-hr, 6598.9 hr/yr, 93% utilization 335,730 Natural Gas 12.81 $/mscf, 1,915 scfm, 6598.9 hr/yr, 93% utilization 9,035,303

Total Annual Direct Operating Costs 9,431,473

Indirect Operating Costs Overhead 60% of total labor and material costs 36,264 Administration (2% total capital costs) 2% of total capital costs (TCI) 147,912 Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,956 Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,956 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 698,090 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,030,178

Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,461,651

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 4: -Summary of Utility, Chemical ans Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed
Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Thermal 369,137 19 0.6 1,367.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 369,137 23 0.6 1,655.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 1367.7

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 6,599 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 412 18,687 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr Supervisor 15% of Op. NA 2,803 15% of Operator Costs Maintenance Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 412 19,475 $/Hr, 0.5 hr/8 hr shift, 6598.9 hr/yr Maint Mtls 100 % of Maintenance Labor NA 19,475 100% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.040 $/kwh 1367.7 kW-hr 8,393,252 335,730 $/kwh, 1,368 kW-hr, 6598.9 hr/yr, 93% utilization Natural Gas 12.81 $/mscf 1,915 scfm 705,149 9,035,303 $/mscf, 1,915 scfm, 6598.9 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis <Table 8>: - Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19
T wi 129 Deg F - Temperature of waste gas into heat recovery
T fi 750 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 564 Deg F - Temperature of waste gas out of heat recovery

T fo 315 Deg F - Temperature of flue gas into of heat recovery

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

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

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

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

Q wg 330,907 scfm - Flow of waste gas

Q af 1,915 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 332,822 scfm Flue Gas Cost in 1989 $'s $512,611 Current Cost Using CHE Plant Cost Inde x $611,190
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 9: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs EPRI Correlation 1998 Purchased Equipment (A) 2005 22,410,519 Purchased Equipment Total (B) SCR Only 23,867,203

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 3,976,665 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 70,762,832

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 28,175,324 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,013,819 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 35,189,143



### Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1,633.3 8.7 0.02 35.0 1,598.3 22,017

Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.

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

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 9: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,410,519 Instrumentation 10% of control device cost (A) N A
MN Sales Taxes 6.5% of control device cost (A) 1,456,684 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 23,867,203

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 3,976,665

Total Plant Cost D A + B + C 30,487,767

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 774,395

Inventory Capital Reagent Vol * $/gal 17,062

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 39,511,225 Retrofit multiplier 3 60% of TCI 23,706,735 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost N A Total Retrofit Capital 63,217,960 

### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator NA - Supervisor NA - Maintenance

Maintenance Total 1.50 % of Total Capital Investment 592,668 Maintenance Materials N A % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 5,133 kW-hr, 8687.8 hr/yr, 93% utilization 1,658,998
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 548,800
NA NA - Ammonia 0.12 $/lb, 503 lb/hr, 8687.8 hr/yr, 93% utilization 489,909
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 3,290,375

Indirect Operating Costs
Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,967,328 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,967,328

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,257,704

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 9: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 3,462 Plant Cap kW A 355,097 Est power platn eff 35% Unc Nox lb/mm B B 0.11 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066 Equivalent power plant k 355,097 Capital Cost $/k W D $63.11 $22,410,519.46 Total SCR Equipment Uncontrolled Nox t/y 1,633.3 Fixed O&M E $147,909.43 Annual Operating Hrs 8000 Variable O&M F $598,961.39 Uncontrolled Nox lb/mm 0.108 A nn Cap Factor G 0.82 Heat Input mmB H 6,000 SCR Capital Cost

SCR Capital Cost per EPRI Method Duty 3,462 MMBtu/hr Catalyst Area 1,670 ft 2 664 f (h SCR) Q flue gas 1,603,311 acfm Rx Area 1,921 -8 f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 43.8 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.11 lb/MMBtu n layer 24 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 25.5 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 25 layers 29,505,985 f (vol catalyst) Temperature 120.719008 Deg F h SCR 139 ft f (h SCR) Catalyst Volume 122,942 ft 3 New/Retrofit R N or R

Electrical Use Duty 3,462 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 5,133.3
NOx in 0.11 lb/MMBtu n catalyst layers 25 layers
Press drop catalyst 1 in H 2 O per layer

Press drop duct 3 in H 2 O

Total 5133.3

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft 3 Density
146 lb/hr Neat 67.2 gal/hr 29% solution Volume 14 day inventory 22,568 gal $17,062 Inventory Cost
503 lb/hr

Design Basis Baseline Em Baseline Emi s Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.02 Nitrous Oxide 1633.31 0.108 375.17

Actual 85,334 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
A djusted Duty 3,462 MMBtu/h r

Operating Cost Calculations Annual hours of operation: 8,688 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 45.31 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8687.8 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs
Maintenance 0.00 Maintenance Total 1.5 % of Total Capital Investment 592,668 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Re p 0.00 Electricity 0.040 $/kwh 5133.3 kW-hr 41,474,951 1,658,998 $/kwh, 5,133 kW-hr, 8687.8 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 140.0 mw 112 548,800 Catalyst Replacement

7 A mmoni a 0.12 $/lb 503 lb/hr 4,062,288 489,909 $/lb, 503 lb/hr, 8687.8 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 10: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 726,369 Purchased Equipment Total (B) 15% of control device cost (A) 835,324

Installation - Standard Costs 30% of purchased equip cost (B) 250,597 Installation - Site Specific Costs 6,200,000
Installation Total 6,450,597 Total Direct Capital Cost, DC 7,285,921 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951 Total Capital Investment (TCI) = DC + IC 7,544,872

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 24,884,948 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491 Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 10: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 726,369

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 72,637 ND Sales Taxes 0.0% of control device cost (A) 0 Freight 5% of control device cost (A) 36,318 Purchased Equipment Total (B) 15% 835,324

Installation

Foundations & supports 8% of purchased equip cost (B) 66,826 Handling & erection 14% of purchased equip cost (B) 116,945 Electrical 4% of purchased equip cost (B) 33,413
Piping 2% of purchased equip cost (B) 16,706 Insulation 1% of purchased equip cost (B) 8,353 Painting 1% of purchased equip cost (B) 8,353 Installation Subtotal Standard Expenses 30% 250,597

Site Preparation, as required Site Specific 1,400,000 Buildings, as required Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Installation Total 6,450,597 Total Direct Capital Cost, DC 7,285,921

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 83,532 Construction & field expenses 5% of purchased equip cost (B) 41,766 Contractor fees 10% of purchased equip cost (B) 83,532 Start-up 2% of purchased equip cost (B) 16,706 Performance test 1% of purchased equip cost (B) 8,353 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,060 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,544,872



### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 24,603 Supervisor 15% 15% of Operator Costs 3,690 Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 25,640
Maintenance Materials 100% of maintenance labor costs 256 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.04 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization 869,316 Natural Gas 12.81 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization 23,961,443

Total Annual Direct Operating Costs 24,884,948

Indirect Operating Costs Overhead 60% of total labor and material costs 32,514 Administration (2% total capital costs) 2% of total capital costs (TCI) 150,897 Property tax (1% total capital costs) 1% of total capital costs (TCI) 75,449 Insurance (1% total capital costs) 1% of total capital costs (TCI) 75,449 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 712,183 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 10: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed
Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Thermal 726,000 19 0.6 2,689.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 726,000 23 0.6 3,256.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2689.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,688 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr Supervisor 15% of Op. NA 3,690 15% of Operator Costs Maintenance 0% Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr
Maint Mtls 100% % of Maintenance Labor NA 256 1% of Maintenance Labor Utilities, Supplies, Re p 0% Electricity 0.04 $/kwh 2689.8 kW-hr 21,732,896 869,316 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization Natural Gas 12.81 $/mscf 3,858 scfm 1,870,042 23,961,443 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 10: -Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19
T wi 121 Deg F - Temperature of waste gas into heat recovery
T fi 750 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 561 Deg F - Temperature of waste gas out of heat recovery

T fo 310 Deg F - Temperature of flue gas into of heat recovery

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

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

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

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

Q wg 660,092 scfm - Flow of waste gas

Q af 3,858 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 663,950 scfm Flue Gas Cost in 1989 $'s $609,213 Current Cost Using CHE Plant Cost Inde x $726,369
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 11: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 2 Pellet Induration

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs EPRI Correlation 1998 Purchased Equipment (A) 2005 23,080,776 Purchased Equipment Total (B) SCR Only 24,581,027

Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 4,083,739 Installation - Site Specific Costs 0 Installation Total 0 Total Direct Capital Cost, DC 0 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0 Total Capital Investment (TCI) = DC + IC SCR + Reheat 72,222,298

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 30,618,541 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,151,583 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 37,770,123



### Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 8,164.5 46.7 0.12 188.7 7,975.8 4,736

Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.

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

11 Control Efficiency = 80% reduction which is the normal SCR control efficiency
12 $35/MW-hr, 140 MW
13 Catalyst replacement every three years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 11: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,080,776 Instrumentation 10% of control device cost (A) N A
MN Sales Taxes 6.5% of control device cost (A) 1,500,250 Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 24,581,027

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 4,083,739

Total Plant Cost D A + B + C 31,308,664

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 790,813

Inventory Capital Reagent Vol * $/gal 91,914

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 40,423,391 Retrofit multiplier 3 60% of TCI 24,254,035 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost N A Total Retrofit Capital 64,677,426 

### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator NA - Supervisor NA - Maintenance

Maintenance Total 1.50 % of Total Capital Investment 606,351 Maintenance Materials N A % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 6,001 kW-hr, 8687.8 hr/yr, 93% utilization 1,939,332
NA NA - NA NA - NA NA - N A N A - NA NA - NA NA - NA NA - NA NA - NA NA - Cat. Replacement [14] 35.00 Catalyst Replacement 548,800
NA NA - Ammonia 0.12 $/lb, 2,708 lb/hr, 8687.8 hr/yr, 93% utilization 2,639,110
NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 5,733,593

Indirect Operating Costs
Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,105,091 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,105,091

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,838,684

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 11: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Equivalent Duty 3,462 Plant Cap kW A 355,097 Est power platn eff 35% Unc Nox lb/mm B B 0.58 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066 Equivalent power plant k 355,097 Capital Cost $/k W D $65.00 $23,080,776.17 Total SCR Equipment Uncontrolled Nox t/y 8,164.5 Fixed O&M E $152,333.12 Annual Operating Hrs 8000 Variable O&M F $626,908.01 Uncontrolled Nox lb/mm 0.584 A nn Cap Factor G 0.82 Heat Input mmB H 6,000 SCR Capital Cost

SCR Capital Cost per EPRI Method Duty 3,462 MMBtu/hr Catalyst Area 1,670 ft 2 767 f (h SCR) Q flue gas 1,603,311 acfm Rx Area 1,921 -8 f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 43.8 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.58 lb/MMBtu n layer 28 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 29.8 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 29 layers 34,578,438 f (vol catalyst) Temperature 120.719008 Deg F h SCR 156 ft f (h SCR) Catalyst Volume 144,077 ft 3 New/Retrofit R N or R

Electrical Use Duty 3,462 MMBtu/hr kW NOx Cont Eff 80% (as faction) Power 6,000.7
NOx in 0.58 lb/MMBtu n catalyst layers 29 layers
Press drop catalyst 1 in H 2 O per layer

Press drop duct 3 in H 2 O

Total 6000.7

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft 3 Density
785 lb/hr Neat 361.8 gal/hr 29% solution Volume 14 day inventory 121,571 gal $91,914 Inventory Cost
2708 lb/hr

Design Basis Baseline Em Baseline Emi s Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu) T/yr lb/MMBtu lb/hr 80% 0.12 Nitrous Oxide 1633.31 0.584 375.17

Actual 85,334 dscf/MMBtu
Method 19 Factor 9,860 dscf/MMBtu
A djusted Duty 3,462 MMBtu/h r

Operating Cost Calculations Annual hours of operation: 8,688 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 45.31 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8687.8 hr/yr Supervisor 15% of Op. NA

- 15% of Operator Costs
Maintenance 0.00 Maintenance Total 1.5 % of Total Capital Investment 606,351 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Re p 0.00 Electricity 0.040 $/kwh 6000.7 kW-hr 48,483,290 1,939,332 $/kwh, 6,001 kW-hr, 8687.8 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 140.0 mw 112 548,800 Catalyst Replacement

7 A mmoni a 0.12 $/lb 2708 lb/hr 21,883,299 2,639,110 $/lb, 2,708 lb/hr, 8687.8 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 12: -Summary of Utility, Chemical and Supply Costs

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 042 Stack/Vent Number SV 048 & 049 Chemical Engineering Desgin Capacity 400 MMBtu/hr Standardized Flow Rate 615,086 scfm @ 32o F Chemical Plant Cost Index Expected Utiliztion Rate 93% Temperature 121 Deg F 1998/1999 390 Expected Annual Hours of Operation 8,688 Hours Moisture Content 13.8% 2005 465 Annual Interest Rate 7.0% Actual Flow Rate 726,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 660,092 scfm @ 68o F Dry Std Flow Rate 568,896 dscfm @ 68o F

CONTROL EQUIPMENT COSTS
Capital Costs Direct Capital Costs Purchased Equipment (A) 726,369 Purchased Equipment Total (B) 15% of control device cost (A) 835,324

Installation - Standard Costs 30% of purchased equip cost (B) 250,597 Installation - Site Specific Costs 6,200,000
Installation Total 6,450,597 Total Direct Capital Cost, DC 7,285,921 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951 Total Capital Investment (TCI) = DC + IC 7,544,872

Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 24,884,948 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491 Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 12: -Summary of Utility, Chemical and Supply Costs

CAPITAL COSTS Direct Capital Costs

Purchased Equipment (A) (1) 726,369

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 72,637 ND Sales Taxes 0.0% of control device cost (A) 0 Freight 5% of control device cost (A) 36,318 Purchased Equipment Total (B) 15% 835,324

Installation

Foundations & supports 8% of purchased equip cost (B) 66,826 Handling & erection 14% of purchased equip cost (B) 116,945 Electrical 4% of purchased equip cost (B) 33,413
Piping 2% of purchased equip cost (B) 16,706 Insulation 1% of purchased equip cost (B) 8,353 Painting 1% of purchased equip cost (B) 8,353 Installation Subtotal Standard Expenses 30% 250,597

Site Preparation, as required Site Specific 1,400,000 Buildings, as required Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Installation Total 6,450,597 Total Direct Capital Cost, DC 7,285,921

Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 83,532 Construction & field expenses 5% of purchased equip cost (B) 41,766 Contractor fees 10% of purchased equip cost (B) 83,532 Start-up 2% of purchased equip cost (B) 16,706 Performance test 1% of purchased equip cost (B) 8,353 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,060 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 258,951

Total Capital Investment (TCI) = DC + IC 7,544,872

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,544,872



### OPERATING COSTS Direct Annual Operating Costs, DC

Operating Labor

Operator 45.31 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 24,603 Supervisor 15% 15% of Operator Costs 3,690 Maintenance

Maintenance Labor 47.22 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr 25,640
Maintenance Materials 100% of maintenance labor costs 256 Utilities, Supplies, Replacements & Waste Managemen t

Electricity 0.04 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization 869,316 Natural Gas 12.81 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization 23,961,443

Total Annual Direct Operating Costs 24,884,948

Indirect Operating Costs Overhead 60% of total labor and material costs 32,514 Administration (2% total capital costs) 2% of total capital costs (TCI) 150,897 Property tax (1% total capital costs) 1% of total capital costs (TCI) 75,449 Insurance (1% total capital costs) 1% of total capital costs (TCI) 75,449 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 712,183 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,046,491

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,931,439

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 12: -Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors Primary Installation

Interest Rate 7.00% Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft 3
Amount Required 39 ft 3
Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labo r 0 10 min per bag (13 hr total) Labor at $29.65/h r OAQPS list replacement times from 5 - 20 min per bag

. Total Installed Cos t 0 Zero out if no replacement parts needed
Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW Blower, Thermal 726,000 19 0.6 2,689.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1 Blower, Catalytic 726,000 23 0.6 3,256.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2689.8

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,688 Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use * Cost Operating Labor Op Labor 45.31 $/Hr 0.5 hr/8 hr shift 543 24,603 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr Supervisor 15% of Op. NA 3,690 15% of Operator Costs Maintenance 0% Maint Labor 47.22 $/Hr 0.5 hr/8 hr shift 543 25,640 $/Hr, 0.5 hr/8 hr shift, 8687.8 hr/yr
Maint Mtls 100% % of Maintenance Labor NA 256 1% of Maintenance Labor Utilities, Supplies, Re p 0% Electricity 0.04 $/kwh 2689.8 kW-hr 21,732,896 869,316 $/kwh, 2,690 kW-hr, 8687.8 hr/yr, 93% utilization Natural Gas 12.81 $/mscf 3,858 scfm 1,870,042 23,961,443 $/mscf, 3,858 scfm, 8687.8 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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## Cleveland Cliffs Incorporated: United Taconite BART Report - <Appendix A> Emission Control Cost Analysis Table 12: -Summary of Utility, Chemical and Supply Costs

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

Auxiliary Fuel Use Equation 3.19
T wi 121 Deg F - Temperature of waste gas into heat recovery
T fi 750 Deg F - Temperature of Flue gas into of heat recovery

T ref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

T wo 561 Deg F - Temperature of waste gas out of heat recovery

T fo 310 Deg F - Temperature of flue gas into of heat recovery

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

-h wg 0 Btu/lb Heat of combustion waste gas
C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)

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

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

Q wg 660,092 scfm - Flow of waste gas

Q af 3,858 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0% Cost Calculations 663,950 scfm Flue Gas Cost in 1989 $'s $609,213 Current Cost Using CHE Plant Cost Inde x $726,369
Heat Rec % A B 0 10,294 0.2355 Exponents per equation 3.24 0.3 13,149 0.2609 Exponents per equation 3.25 0.5 17,056 0.2502 Exponents per equation 3.26 0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole Gas Composition lb/hr f wt % Cp Gas Cp Flue 28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528 18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368 Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B-96-001)

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# Memorandum

To: 

# Margaret McCourtney

From: 

# Andrew Skoglund
Subject: 

# Revisions per your comments

Date: 

# May 16, 2006
Project: 

# Taconite Industry BART Clients

c: 

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

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

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

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

Thank you,

Andrew J. Skoglund
Barr Engineering Co.

(952) 832 - 2685
askoglund@barr.com

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



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

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



## 0 100 Kilometers



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

# Legend

Modeling Domain


# Class I Area

BWCA

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

# Appendix C

1. CALPUFF Modeling System

The CALPUFF Modeling System is the required model for determining visual impacts at long distances

from sources. This model was used in accordan ce with the guidelines found in the Best Available
Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of

Minnesota, Final 1 

# , with the modifications found in Appendix B.

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

described below:

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

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

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

Lambert conformal coordinates (LCC) were used in the m odeling. To accommodate this coordinate
system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets

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

1 

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

# CALMET

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



# CALPUFF

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

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

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

transfor mation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates
of transformation. The MESOPUFF-generated transf ormation rates are a function of the background

ozone and ammonia concentrations, the former set by observations, the latter using monthly average
values provided by MPCA.

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

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



# CALPOST

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

# 2. Visibility Impacts Analysis

As indicated in EPA’s final BART guidance 2 

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

The CALPUFF program models how a pollutant contribut es to visibility impairment with consideration
for the background atm ospheric ammonia, ozone and me teorological data. Additionally, the interactions
between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting
impairment. It is therefore important to take a multi- pollutant approach when ass essing visibility impacts.



# Assessing Visibility Impairment

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

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

As defined by federal guidance 4 

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

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

on which a source exceeds 0.5 dV.

2 

# 40 CFR 51, Appendix Y.

3 

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

4 

# 40 CFR 51, Appendix Y.

5 

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

# De minimis Modeling

As a part of the streamlined BART approach, a method for removing insignificant sources from further
BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold
would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis.

For this facility, five sources were modeled, SV 099, S V107, SV108, SV109, and SV110. The maximum

98 th 

# percentile modeled impact for these s ources was 0.05 dV, meeting the required de minimis threshold
of 0.05 dV. This exempts these sources fro m further BART analysis. A summary of the de minimis
modeling is in the table below.

Modeled 98th Percentile Impact

2002 2003 2004 2002-2004 Maximum
BWCA 0.04 0.05 0.04 0.04 0.05 Voyageurs 0.03 0.03 0.03 0.03 0.03



# Predicting 24-Hour Maximum Emission Rates

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

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



# Modeled Results

Visibility impairment was modeled using the meteor ological data for the years 2002, 2003 and 2004 for
the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above
0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are

included in Table 6-3.N

Barr Footer: Date: 7/5/2006 2:23:18 PM File: I:\projects\23\00\Minntac.mxd User: ams1000MetersUTAC Aerial PhotoTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic PrincipleCombustion Controls1 Overfire Air (OFA)YN------NOx formation front is not stationary inan indurating furnaceCombustion air is separated into primary and secondary flow sections toachieve complete burnout and to encourage the formation of N2ratherthan NOx2External Flue GasRecirculation (EFGR)Y Y N---Mixes flue gas with combustion air which reduces oxygen content andtherefore reduces flame temperature3 Low-NOx BurnersYYY(preheatburners)Y(preheatburners)Higher control efficiency at the burner,but the listed control efficiency is forthe entire furnace.Burners are designed to reduce NOx formation through restriction ofoxygen, flame temperature, and/or residence time4Induced Flue GasRecirculation BurnersYYN---Need to be upfired. Need convectiveloop to get gas recirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature5 Low Excess AirYN------Need high O2for process requirementsand product qualityReduces oxygen content in flue gas and reduces flame temperature6Burners out of Service(BOOS)Y N --- ---Need capacity of all burners for worstcase scenarioShut off the fuel flow from one burner or more to create fuel rich and fuellean zones7 Fuel BiasingYN------ Power plant technologyCombustion is staged by diverting fuel from the upper level burners to thelower ones or from the center to the side burners to create fuel-rich andfuel-lean zones8 ReburningYN------Kiln configuration not correct for thistechnology.Part of the total fuel heat input is injected into the furnace in a regionabove the primary (main burners) flames to create a reducing atmosphere(re-burn zone), where hydrocarbon radicals react with NOx to produceelemental nitrogen9 Load ReductionN---------Power plant technology -productdemand side solutionThis is a strategy to reduce load on a power plant by reducing theelectrical demand throught efficiency projects.10 Energy Efficiency Projects YYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)decrease amount of fuel required to make an acceptable product11 Coal DryingYN------ Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel isrequired to be burned. Specific energy efficiency project12Coal Addition to Pellets withLow Excess Air in theInduration FurnaceN --- ------ Check on status of researchReduce flame temperature and energy requirementsTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle13 Ported KilnsYYY(grate-kilnsonly)N(Metso saysno NOximprovement)Applicable to grate kilns.Provides additional oxygen for pellet oxidation which reduces the overallenergy use of the kiln14 Combustion Zone Cooling YN------ Boiler technologyCooling of the primary flame zone by heat transfer to surroundingsurfaces15 Alternate FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Requires case by case analysis.Typically, facilities experience lowerNOx when burning solid fuels.Lower combustion temps with solid fuels vs gas. May also reduce fuelNOx by using a fuel with less nitrogen.16Oxygen EnhancedCombustionN--------- Research levelA small fraction of the combustion air is replaced with oxygen.17 Preheat Combustion N--------- Research levelPulverized coal preheated and volatiles and fuel-bound nitrogencompounds are released in a controlled reducing atmosphere where thenitrogen compounds are reduced to N2.18 ROFA-ROTAMIXYN------Can't achieve correct temperaturewindow (1400-1800F). Too hot in kilntoo cold in reheatCombination of OFA and SCR. Wall-fired or tangentially-fired furnace thatutilizes high velocity overfire air. Additional NOx reductions are achievedwith ammonia injection (Rotamix)19 NOx CEMSYN------Optimization of combustion20 Parametric Monitoring YN------Optimization of combustion38Catalyst Injection(EPS Technologies)N --- ------ Research LevelA combustion catalyst is directly injected into the air intake stream anddelivered to the combustion site, initiating chemical reactions that changethe dynamics of the flame.Post Combustion Controls21Non-Selective CatalyticReduction (NSCR)YN------For clean services. Too much stuff influe gas would poison catalystUnder near stoichiometric conditions, in the presence of a catalyst, NOx isreduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).22Low Temperature Oxidation(LTO) - Tri-NOx®Y N --- --- Used for higher flue gas concentrationsUtilizes an oxidizing agent such as ozone to oxidize various pollutantsincluding NOxTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle23Low Temperature Oxidation(LTO) - LoTOxY N --- ---Has been included as an "applicableand available" technology in recentBACT analyses from multiple facilities.Utilizes an oxidizing agent such as ozone to oxidize various pollutantsincluding NOx24Selective CatalyticReduction (SCR)Y Y YYNeed to inject at appropriatetemperature (reheat will be required).Applicable on clean side only.Although this hasn't beendemonstrated on an induratingfurnace, the stream characteristicsappear to make this technologyfeasible.Ammonia (NH3) is injected into the flue gas stream in the presence of acatalyst to convert NOx into N2and water25 Regenerative SCR Y N------ Clean side only26Selective Non-CatalyticReduction (SNCR)YN------Can't achieve correct temperaturewindow (1400-1800F). Too hot in kilntoo cold in reheatUrea or ammonia-based chemicals are injected into the flue gas stream toconvert NO to molecular nitrogen, N2, and water27 AdsorptionN--------- Still in research stages.Use of char (activated carbon) to adsorb oxides of nitrogen28 AbsorptionYN------ Similar to TriNOxUse of water, hydroxide and carbonate solutions, sulfuric acid, organicsolutions, molten alkali carbonates, or hydroxides to absorb oxides ofnitrogen.29OxidizerYN------ Redundant to regenerative SCRGas stream is sent through the regenerative, recuperative, catalytic ordirect fired oxidizer where pollutants are heated to a combustion point anddestroyed.30 SNOX N --- ------ Early commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converterpasses through a novel glass-tube condenser in which the SO3ishydrated to H2SO4vapor and then condensed to a concentrated liquidsulfuric acid (H2SO4).31 SOx-NOx-Rox-BoxN---------Technology has not beendemonstratedDry sorbent injection upstream of the baghouse for removal of SOx andammonia injection upstream of a zeolitic selective catalytic reduction(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.Taconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle32 Electron (E-Beam) Process N---------No operating commercial applicationson coalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can beeasily collected by conventional methods such as an ESP or baghouse.33 Electrocatalytic Oxidation N---------Similar to cold plasma. Will keepwatch for availability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogendioxide (NO2), sulfuric acid, and mercuric oxide respectively using nonthermal plasma.On recent project, the vender was doing final trials on full-scaleapplications.34 NOXSON---------Commercial version of adsorption.Limited experience (proof-of-concepttests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx fromflue gas from coal-fired utility and industrial boilers. In the process, theSO2is converted to a saleable sulfur by-product (liquid SO2, elementalsulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.35 Copper-OxideN---------Absorption and SCR. Experiencelimited to pilot scale.SO2in the flue gas reacts with copper oxide, supported on small spheresof alumina, to form copper sulfate. Ammonia is injected into the flue gasbefore the absorption reactor and a selective catalytic reduction-typereaction occurs that reduces the nitric oxides in the flue gas. In theregeneration step, the copper sulfate is reduced in a regenerator with areducing agent, such as natural gas, producing a concentrated stream ofSO2.36 Cold PlasmaN--------- Research Level37 BiofiltersYN------ Not applicable to furnaces.Gas stream is passed through a filter medium of soil and microbes.Pollutants are adsorbed and degraded by microbial metabolism formingthe products carbon dioxide and water.38 Pahlman ProcessN--------- Research LevelGas stream is passed through a filter baghouse in which speciallydeveloped, small-particle, high-surface area metal oxide sorbent havebeen deployed. Pollutants are removed from the gases by adsorption.1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htmTaconite BART AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1NOxPollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsTaconite BART AnalysisSO2 ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1SO2Pollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle1Wet Scrubbing (HighEfficiency)YYYYAbsorption and reaction using an alkaline reagent to produce a solid compound2Wet Scrubbing (LowEfficiency)YYYYAbsorption and reaction using an alkaline reagent to produce a solid compound3Wet Walled ElectrostaticPrecipitator (WWESP)YYYYSuspended particles are separated from the flue gas stream, attracted to plates, andcollected in hoppers4 Dry sorbent injectionYYYNPulverized lime or limestone is directly injected into the duct upstream of the fabricfilter. Dry sorption of SO2onto the lime or limestone particle occurs and thesolidparticles are collected with a fabric filter5 Spray Dryer Absorption (SDA)YYYNLime slurry is sprayed into an absorption tower where SO2is absorbed by theslurry, forming CaSO3/CaSO46 Alternative FuelsYYY(for furnacescapable ofmultiple fuels)Y(not requiredby BART)Natural gas is base caseUse a fuel with lower sulfur content.7 Load ReductionN---------Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electrical demandthrought efficiency projects.8 Energy Efficiency ProjectsYYY(for largeprojects likeheat-recoup)Y(for largeprojects likeheat-recoup)decrease amount of fuel required to make an acceptable product9Coal DryingYN------Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is requiredto be burned. Specific energy efficiency project10Bio FiltersN---------Research levelGas stream passes through a packed bed of specially engineered biomedia whichsupports the growth of active bacterial species. The pollutants in the gas stream arebiodegraded or biotransformed into innocuous products, such as carbon dioxide,water, chloride ion in water, sulfate or nitrate ions in water.11CANSOLV Regenerable SO2N---------Research levelAn aqueous solution of proprietary diamine captures SO2from the feed gas in acountercurrent absorption tower. The rich solvent is regenerated by steam stripping,giving a byproduct of pure, water saturated SO2gas and lean solvent for recyclingto the absorber.12 Pahlman ProcessN---------Research levelGas stream is passed through a filter baghouse in which specially-developed, smallparticle, high-surface area metal oxide sorbent have been deployed. Pollutants areremoved from the gases by adsorption.Taconite BART AnalysisSO2 ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

Reference No. 1SO2Pollution ControlTechnology Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source?CommentsBasic Principle13 SOx-NOx-Rox-BoxN --- ------Technology has not been demonstratedDry sorbent injection upstream of the baghouse for removal of SOx and ammoniainjection upstream of a zeolitic selective catalytic reduction (SCR) catalystincorporated in the baghouse to reduce NOx emissions.14 Electron (E-Beam) ProcessN---------No operating commercial applications oncoalElectron beam irradiation in the presence of ammonia to initiate chemicalconversion of sulfur and nitrogen oxides into components which can be easilycollected by conventional methods such as an ESP or baghouse.15 Electrocatalytic OxidationN---------Similar to cold plasma. Will keep watch foravailability of this technologyUtilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen dioxide(NO2), sulfuric acid, and mercuric oxide respectively using non-thermal plasma.On recent project, the vender was doing final trials on full-scale applications.16NOXSON---------Commercial version of adsorption. Limitedexperience (proof-of-concept tests).Uses a regenerable sorbent to simultaneously adsorb SO2and NOx from flue gasfrom coal-fired utility and industrial boilers. In the process, the SO2is converted toasaleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and theNOxis converted to nitrogen and oxygen.17 Copper-OxideN---------Absorption and SCR. Experience limited topilot scale.SO2in the flue gas reacts with copper oxide, supportedon small spheres ofalumina, to form copper sulfate. Ammonia is injected into the flue gas before theabsorption reactor and a selective catalytic reduction-type reaction occurs thatreduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfateis reduced in a regenerator with a reducing agent, such as natural gas, producing aconcentrated stream of SO2.18SNOXN---------Early commercial development stageCatalytic reduction of NOx in the presence of ammonia (NH3), followed bycatalytic oxidation of SO2to SO3. The exit gas from the SO3converter passesthrough a novel glass-tube condenser in which the SO3is hydrated to H2SO4vaporand then condensed to a concentrated liquid sulfuric acid (H2SO4).19 Cold PlasmaN---------Research level1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART ReportsAppendix EClean Air Interstate Rule (CAIR)Cost-Effective air pollution Controls9/1/2006CommentsReferenceRegulatory Body/RuleSO2NOxSO2NOxBART100 to 1000100 to 100070 FR 39135BART281 to 129670 FR 39135 Table 3BART91970 FR 39133BARTGuidelines disparagingly reference "thousands ofdollars per ton" in commenting on the need toexceed MACT and its general unreasonableness.70_FR_25210_CAIR.pdfCAIR1300Estimated Marginal cost 2009BART(proposed rule) 200-1000BART proposed lists this as values for 90-95%SO2 control, which is still assumed, or .1 to .15lb/MMBtu. Dropped from final to give statesflexibility to require more. Says for scrubbers,bypasses aren't BART, only 100% scrubbing isBART.BART(proposed rule)0.2 lb/MMBtu for NOx is assumed reasonble.Recognizes that some sources may need SCR toget this level. For those, state discretion of the thecost vs. visibility value is necessary.CAIR(using IPM)10001500CAIR ( 2009 in 1999$) 9002400CAIR ( 2015 in 1999$) 18003000CAIR (depending on Nat'lemissions)1200 - 3000 1400- 2100This was modeled with TRUM (TechnologlyRetrofitting Updating Model) to develop themarginal values.Kammer_EPA_Decision.docKammer Decisionover 1000 over 1000LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU200-500 200-1500Bowers_vs_SWAPCA.txtBowers vs SWAPCA30030010001000954-1134 was ruled too much, in favor of 256-310for SO2. This did consider incremental value.Sections XVII to XIXWRAP3000EPA - Referenced by WrapReferences EPA-600S\7-90-018. Low is<$500/ton, Moderate is $500-3000/ton, High isover $3000/tonWRAP_Trading_program_methodology.pdfAvg. Expected Values ($/ton) Limiting/Marginal values ($/ton)MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdfY:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xls