uss minntac bart report...minntac bart report september 8, 2006 y:\23\00 mn taconite bart...

$: USS Minntac BART Report...Minntac BART Report September 8, 2006 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc vi$
Minntac BART Report September 8, 2006

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc

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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) ................................................................. 11

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

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

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ............................................... 17 4.A MPCA Subject-to-BART Modeling ......................................................................................... 17

4.B Facility Baseline Emission Rates.............................................................................................. 18

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

5. BART Analysis for BART Eligible Emission Units .......................................................................... 22 5.A Indurating Furnace .................................................................................................................... 22

5.A.i Sulfur Dioxide Controls............................................................................................... 25

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 25

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 25

5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 32

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

5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 35

5.A.ii Nitrogen Oxide Controls.............................................................................................. 40

5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 40

5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 40

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

5.B External Combustion Sources................................................................................................... 62

5.B.i Nitrogen Oxide Controls.............................................................................................. 62

5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 62

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 63



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5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 70

5.B.i.d STEP 4 – Evaluate Impacts and Document the Results ............................... 71

5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 73

6. Visibility Impacts................................................................................................................................ 77 6.A Post-BART Modeling Scenarios............................................................................................... 77

6.B Post-BART Modeling Results .................................................................................................. 77

7. Select BART....................................................................................................................................... 81 7.A Indurating Furnaces .................................................................................................................. 81

7.B External Combustion Sources................................................................................................... 84

List of Tables

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ...14

Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data .............15

Table 3-3 De Minimis Visibility Modeling Results....................................................................16

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data ..20

Table 4-2 Baseline Visibility Modeling Results ..........................................................................21

Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................32

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness .........................................32

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

Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates ..........................................................................................................................37

Table 5-5 Indurating Furnace Post-BART SO2 Modeling Scenarios - Visibility Modeling Results39

Table 5-6 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................53

Table 5-7 Indurating Furnace NOx Control Technology Effectiveness ........................................54

Table 5-8 Indurating Furnace NOx Control Cost Summary .........................................................55

Table 5-9 Indurating Furnace NOx Control Technology Impacts Assessment ..............................57

Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates ..........................................................................................................................60

Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results61

Table 5-12 Boiler NOx Control Technology – Availability, Applicability, and Technical Feasibility70

Table 5-13 Boiler NOx Control Technology Effectiveness ............................................................71

Table 5-14 Boiler NOx Control Cost Summary .............................................................................72

Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates .........75

Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results ................76

Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................80



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List of Figures

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

List of Appendices

Appendix A Control Cost Analysis Spreadsheets

Appendix B Changes to MPCA BART Modeling Protocol

Appendix C Visibility Impacts Modeling Report

Appendix D NOX Emissions Analysis – Pre and Post Installation of Air Injection Ports on Line 7

at USS/Minntac

Appendix E Indurating Furnace – Applicable and Available Retrofit Technologies

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

Appendix G Process Heating Boiler – Applicable and Available Retrofit Technologies



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1. Executive Summary

U.S. Steel Corporation’s Minnesota Ore Operations (Minntac) is located in northern Minnesota, with

taconite mining and processing facilities near Mountain Iron, Minnesota. This report describes the

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

proposed by Minntac for its taconite processing plant.

Within the pellet making process, there are many pieces of equipment with pollution control devices

to reduce emissions. Based on the regulatory definitions and the details provided in this report,

Minntac’s BART-eligible units include emission units that were installed within the BART time

window (1962-1977). These BART-eligible units include the indurating furnaces, heating boilers,

minor combustions sources, and several material handling and storage units for ore, product, and

additives. Preliminary visibility modeling conducted by the MPCA found that the BART-eligible air

emissions from Minntac “cause or contribute to visibility impairment” in a federally protected Class I

area, therefore making the facility subject-to-BART. As a subject-to-BART facility, a BART

analysis was required to determine BART for the affected emission units.

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

a streamlined approach for BART analyses1. The streamlined approach allows both the states and the

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

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

for a streamlined analysis.

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

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

applicable to all indurating furnaces, ore crushing and handling operations, and finished pellet

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

for performance testing and continuous parametric monitoring for compliance demonstration.

After completion of the streamlined analysis, the focus of the BART analysis was the NOx emissions

from four heating boilers and the SO2 and NOx emissions from the five indurating furnaces. The four

boilers that underwent the BART analysis are relatively small, and have limited hours of operation

and utilization. The Indurating Furnaces operate with existing control equipment which include: wet

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



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scrubbers for each of the five stacks designed to control of particulate matter (PM) with collateral

control of sulfur dioxide (SO2); ported kilns on two of the furnaces designed for energy efficiency

with collateral control of nitrogen oxides (NOx); and low-NOx burners installed on the preheat

section of one of the furnaces.

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

determine BART for these sources. A dispersion modeling sequence of CALMET, CALPUFF, and

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

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

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

technologies, cost of control, energy and environmental impacts, existing pollution control

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

Based on the consideration of all of the above criteria, Minntac proposes no additional controls,

emission limits, or monitoring requirements for the NOx emissions from four heating boilers. This is

based on the conclusion that low-NOx burners were the only control technology that meet the cost

screening threshold, but the technology did not provide significant improvement in the visibility

modeling. In addition, the control cost for this technology is higher than the anticipated level for a

BART analysis. It is also important to note that due to the relatively small size of the boilers and the

low hours of operation, the actual visibility impact of the boilers is small.

Based on consideration of all of the above criteria, Minntac proposes the following as BART for SO2

and NOX for the Indurating Furnaces:

• BART for SO2:

o SO2 emissions will be controlled by the existing wet scrubbers, which will be

operated as required in accordance with provisions of the Taconite MACT.

o SO2 emission limit for the Indurating Furnace on Line 3 will be determined based

on upcoming performance testing to determine the actual emission rate from the

furnace with the addition of the new scrubber. A proposed SO2 limit for the

furnace in the draft PSD permit for Minntac does not reflect the recently installed

wet scrubber.



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o SO2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the

limits which are based on using the existing wet scrubbers and reflect air

dispersion modeling results for regional haze as proposed in the draft PSD

permit:

⋅ Line 4 = 182 lbs/hr




o Compliance will be initially be demonstrated by a performance test at each

furnace.

o Continuous compliance will be demonstrated by continuous monitoring of

scrubber water flow rate and scrubber pressure drop, which are the same

parameters that will be monitored under the Taconite MACT. The operating

limits will be determined based on the MACT compliance test and will be based

on a 24-hour block average. Therefore, the compliance demonstration will be

consistent with the Taconite MACT.

• BART for NOx:

o NOx emissions will be controlled as follows:

⋅ Line 3: Existing combustion controls and fuel blending. Line 3 does not

currently use burners in its pre-heat section, and therefore low-NOx burners

cannot be applied at this furnace.

⋅ Line 4: Installation of low-NOx burners on the pre-heat section, existing

combustion controls, and fuel blending.





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⋅ Line 6: Operation of low-NOx burners on the pre-heat section (installed as

replacement and reconfigured burners in April 2006), existing combustion

controls, and fuel blending.



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

installation of the low-NOx burners to allow the facility sufficient time for

process and emissions monitoring using NOx CEMS to determine the actual

emission rates under a variety of operating conditions. Although the facility

anticipates a significant reduction in NOx emissions with the installation of the

low-NOx burners, the actual emissions reduction cannot be determined until the

burners are operated under a variety of operation conditions.

o Initial and continuous compliance will be demonstrated after the appropriate

emission limits have been determined. Compliance will be demonstrated using

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

The schedule for implementation of these controls, specifically installation of low-NOx burners and

subsequent testing to demonstrate the appropriate BART emission limit, is within the 5-year time-

frame required for BART implementation. In addition, Minntac will continue to evaluate energy

efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission

rates.

Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for

the installation of low-NOx burners, the proposed BART controls will result in visibility

improvement on the 98th percentile day of approximately 0.488 deciviews (dV) when burning gas in

the kiln and 0.465 dV when burning solid fuels in the kiln. This is a visibility improvement of

approximately 7% compared to the baseline (pre-BART) operating conditions.



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2. Introduction

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

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

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

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

40 CFR part 51, in §51.300 through §51.309.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Nugget (Nugget), which are illustrated in the figure, are not currently constructed or in operation.

The SIP must also include milestones for establishing reasonable progress towards the visibility

improvement goals and plans for the first five-year period. Upon submission of the Regional Haze

SIP, states must make the requirements for BART sources federally enforceable through rules,

administrative orders or Title V permit amendments.



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Figure 2-1 Minnesota’s BART Geography The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary

Waters Canoe Area (BWCA)] and BART-eligible units illustrated above. (Source MPCA BART-Strategy October 4, 2005)

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

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

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

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

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

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

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



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

must meet the following three conditions:

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

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

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

plants, sulfur recovery plants, etc.);

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

3. Have total potential emissions greater than 250 tons per year for at least one visibility-

impairing pollutant from the emission units meeting the two criteria above.

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

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

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

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

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

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

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

date from any other CAA requirements.

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

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

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

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

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

are BART-eligible.

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

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

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

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



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

and non-air quality environmental impacts of the technology, and the visibility impacts.2

The five steps of a BART analysis are:

Step 1 - Identify all Control Technologies

The first step in the analysis is to identify all available retrofit control technologies for

each applicable emission unit. U.S. EPA is very specific about the criteria to be met

for a technology to be considered available. In preambles to the interim and final rules

U.S. EPA defines “available” as follows:

Available retrofit technologies are those air pollution control technologies

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

regulated pollutant under evaluation. Air pollution control technologies can

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

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

are available for BART purposes and must be included as control

alternatives. The control alternatives can include not only existing controls

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

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

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

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

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

has not been demonstrated in practice.3

Step 2 - Eliminate Technically Infeasible Options In the second step, the technical feasibility of each control option identified in step one

is evaluated by answering three specific questions:

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

BART analysis?

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

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

2 40 CFR 51 Appendix Y 3 Federal Register 70, No. 128 (July 6, 2005): 39164



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

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

dissimilar source type.” 4

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

is undergoing the BART analysis?

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

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

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

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

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

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

applied previously.”5

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

not technically feasible?

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

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

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

technology.” This also involves the identification of “un-resolvable technical

difficulties.” However, when the technical difficulties are merely a matter of

increased cost, the technology should be considered technically feasible and the

technological difficulty evaluated as part of the economic analysis.6

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

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

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

EPA does not consider the lack of a vender guarantee as “sufficient justification

that a control option or emission limit is technically infeasible.” In general, the

decisions on technical feasibility should be based on a combination of the

4 Federal Register 70, No. 128 (July 6, 2005): 39165 5 IBID 6 IBID



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evaluation of the chemical and engineering analysis and the information from

vendor guarantees.7

Step 3 - Evaluate Control Effectiveness

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

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

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

Step 4 - Evaluate Impacts and Document Results

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

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

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

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

others. Finally, step four includes an assessment of energy impacts and other non-air

quality environmental impacts.

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

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

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

Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model

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

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

control cost analysis worksheets as found in Appendix A.

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

such as CALPUFF. The modeling protocol8, including receptor grid, meteorological

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

Pollution Control Agency. The model outputs, including the 98th percentile deciview

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

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

improvement that can be reasonably attributed to each technology.

7 IBID 8 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to

BART in the State of Minnesota.



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

through 5. When selecting the “best alternative,” the U.S. EPA and MPCA guidance states that the

“affordability” of the controls should be considered, and specifically states:

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

of controls would affect the viability of plant operations.

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

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

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

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

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

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

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

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

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

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

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

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

information is available.9

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

the BART requirements and requires compliance within a reasonable period of time.”10 Those limits

must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in

December of 2007. In addition, the analysis must include requirements that the source “employ

techniques that ensure compliance on a continuous basis”11 which could include the incorporation of

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

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

technological or economic limitations make measurement methodology for an emission unit

9 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 10 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 11 IBID



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

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

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

the Minnesota SIP.

12 IBID



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3. Streamlined BART Analysis

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

a streamlined approach for BART analyses13. The streamlined approach will allow both states and the

facilities to focus their resources on the main contributors to visibility impairment. The following

outlines the MPCA-approved streamlined BART analysis for taconite facilities and presents the

results of the streamlined approach in Table 3-1.

3.A Indurating Furnaces The indurating furnace is a source of three visibility impairing pollutants: NOx, SO2, and PM.

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

furnace is subject to the taconite MACT standard [40 CFR Part 63 Subpart RRRRR-NESHAPS:

Taconite Iron Ore Processing] for the PM emissions. MPCA’s guidance for conducting a BART

review states that “MPCA will rely on MACT standards to represent BART level of control for those

visibility impairing pollutants addressed by the MACT standard unless there are new technologies

subsequent to the MACT standard, which would lead to cost-effective increases in the level of

control.”14 Since the MACT standard was established very recently and becomes effective in 2006,

the technology analysis is up-to-date. As a result, BART will be presumed to be equivalent to

MACT for PM and no further analysis will be required to establish BART for PM for these sources.

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

3.B PM-Only Taconite MACT Emission Units In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from

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

These sources operate near ambient temperature, only emit PM, and do not emit NOx or SO2. The

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

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

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

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

emissions.15 Therefore, the emissions from the pellet coolers are considered to have a negligible

13 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 14 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 2. 15 Federal Register 67, no. 143 (December 18, 2002): 77570



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

with the intention of the BART analysis.

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

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

to be equivalent to MACT according to MPCA guidance.

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

3.C Sources of fugitive PM that are subject to MACT standards The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from non-

MACT sources are addressed in section 3.D). These sources operate at ambient temperature, only

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

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

finished pellets),

• Material Transfer Points,

• Plant Roadways,

• Tailings basins,

• Pellet loading areas, and

• Yard areas.

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

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

control plans consist of monitoring, primary controls, and contingent measures to prevent or mitigate

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

and weather conditions. Since the MACT standard was established recently and will become

effective in 2006, the technology analysis is up-to-date. Again, for these units subject to a MACT

standard, BART will be presumed to be equivalent to MACT according to MPCA guidance.

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



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3.D Non-MACT Units and Fugitive Sources (PM only) A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard.

They include units such as:

• Bentonite storage and handling

• Additive storage and handling

• Concentrate storage and handling

• Coal and/or solid fuel storage and handling Considering all PM emissions which are subject to the BART standard, the PM emissions from the

above units typically represent approximately 1% of PM emissions from the facility, which are

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

The point source emission units are controlled by either baghouses or scrubbers, which are

technologies that achieve high levels of control for PM. Since these units already have control

equipment for PM emissions, and since the PM emissions from these sources are small relative to the

total PM emissions that are subject to the BART standard, additional control of these sources can be

presumed to have minimal impact on visibility improvement in Class I areas. For the controlled

sources, existing controls will be considered BART consistent with direction from MPCA in the May

18, 2006 meeting, and no further analysis will be required to establish BART for these sources. If

any sources do not have existing controls, the facility will conduct an analysis for these sources to

demonstrate that the impact on visibility in Class I areas is negligible. The procedure for the analysis

is detailed in section 3.F of this document. Assuming that the modeling demonstrates that the

sources have a negligible impact on visibility in Class I areas and no further analysis will be required

to establish BART for these sources.

3.E Other Combustion Units This facility has several other combustion units that are subject-to-BART. The combustion units are

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

sources include process heaters, boilers, emergency generators, air compressors, and fire pumps. It is

important to note that the emissions from the indurating furnaces represent the vast majority of

emissions of all visibility impairing pollutants, with the all other emission units contributing less than

1% of the total emissions of each pollutant from sources that are subject-to-BART. The emissions

from all the remaining sources are small relative to the total emissions that are subject to the BART

standard. Additional control of these sources can be presumed to have minimal impact on visibility

improvement in Class I areas. As directed by MPCA in the May 18, 2006 meeting, the existing



12

operations for emergency generators and fire pumps will be considered BART. This facility has

conducted an analysis for the remaining sources to demonstrate that the impact on visibility is

negligible. The procedure for the analysis is detailed in section 3.F of this document. For the

sources for which the modeling demonstrates negligible impact on visibility in Class I areas, no

further analysis will be required to establish BART for these sources.

3.F Visibility Impact Modeling for Negligible Impacts As described in section 3.D and 3.E of this document, this facility contains several sources that are

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

assumption, a modeling analysis was conducted to determine the impact of the emissions from these

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

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

fugitive sources for the facility, as described in sections 3.D and 3.E above. The

modeling was conducted based on MPCA modeling protocol16. One modeling

analysis was conducted. The modeling was conducted on a focused grid (as

previously agreed to with MPCA) which is based on the facility impacts as presented

by MPCA in “Results of Best Available Retrofit Technology (BART) Modeling to

Determine Sources Subject-to-BART in the State of Minnesota” (March 2006).

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

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

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

assessed over the 3-year period 2002-2004.

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

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

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

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

establish BART for these sources.

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

BART in the State of Minnesota.



13

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

equal to 0.05 deciviews, a full BART analysis will be conducted on the emission

sources.

The de minimis modeling input data is presented in Table 3-2. A summary of the results of the de

minimis modeling is presented in Table 3-3. The details of the de minimis modeling are presented in

Appendix C.



14

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



15

Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data



16

Table 3-3 De Minimis Visibility Modeling Results



17

4. Baseline Conditions and Visibility Impacts for BART Eligible Units

As indicated in U.S. EPA’s final BART guidance17, one of the factors to consider when determining

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

technology. The visibility impacts for this facility were determined using CALPUFF, a U.S. EPA

approved model. The CALPUFF program models how a pollutant contributes to visibility

impairment with consideration for the background atmospheric ammonia, ozone and meteorological

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

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

approach when assessing visibility impacts.

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

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

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

the maximum 24-hour actual emissions18.

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

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

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

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

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

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

reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions

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

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

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

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

this facility is subject-to-BART.

17 Federal Register 70, no. 128 (July 6, 2005): 39106. 18 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources

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



18

It is important to note that the MPCA subject-to-BART modeling only included the induration

furnace sources. This is due to the fact that this facility contains 375 BART-eligible emission units,

which would have added increased complexity to the modeling. However, the modeling results of

only the indurating furnaces demonstrated that the facility is subject-to-BART.

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

On behalf of this facility and the other Minnesota taconite facilities, Barr Engineering proposed

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

presented in Appendix B. The MPCA has given verbal approval to the proposed changes to the

modeling protocol.

Consistent with MPCA modeling and as agreed upon in the MPCA-approved changed to the

modeling protocol, only the induration furnaces were required to be modeled for this facility.

However, the NOx emissions from Boilers #1, #2, #4 and #5 were also added to the visibility model

as these sources are also subject to a full BART analysis for NOx.

In addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to

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

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

the highest emission rate as measured during a representative stack test, as opposed to the emission

rate as measured during the most recent stack test. The baseline emission rates from the following

sources were adjusted using this criteria:

o Line 3 Rotary Kiln (EU 225 / SV 103) - NOx and SO2





The MPCA visibility impairment modeling evaluated the impacts of the maximum 24-hour emissions

of SO2, NOx, and PM. However, it is important to note that the worst-case SO2 emissions scenario is

based on solid fuel operation and the worst-case NOx emissions scenario is based on natural gas



19

operation. Therefore, baseline modeling was conducted for two separate operating scenarios for fuel

burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that

natural gas is the only fuel that is burned in the preheat section of the kiln.

The facility baseline data reflecting these changes is summarized in the Table 4-1. The full modeling

analysis is presented in Appendix C.

4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol also describes the post processing elements of the

analysis.19 The CALBART output files provide the following two methods to assess the expected

post-BART visibility improvement:

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

identifies the Minnesota facilities that are subject to BART20, a source "contributes to

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

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

protected Class I area receptor.

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

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

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

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

the modeling of the revised baseline emissions confirms that the facility is considered to contribute to

visibility impairment in Class I areas because the modeled 98th percentile of the baseline conditions

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

modeling analysis in section 6 of this document.

The full modeling analysis is presented in Appendix C.

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

Subject-to-BART in the State of Minnesota. Page 8. 20 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources

Subject-to-BART in the State of Minnesota.



20

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



21

Table 4-2 Baseline Visibility Modeling Results



22

5. BART Analysis for BART Eligible Emission Units

BART eligible sources at this facility can be divided into groups based upon type of process. The

Minntac facility had two types of processes which were required to undergo a full BART analysis:

• Indurating Furnaces for NOx and SO2 (Section 5.A)

o Line 3 Rotary Kiln (EU 225 / SV 103)





• External Combustion Sources for NOx (Section 5.B)

o Utility Plant Heating Boiler #1 (EU 001 / SV 001)




5.A Indurating Furnace “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The induration

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

This facility has five grate/kiln induration furnaces, in which the pellets are dried on a grate and then

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

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

meet taconite pellet product specifications. Fuel combustion in the induration furnace is carried out at

approximately 15% to 18% oxygen to provide sufficient oxygen for pellet oxidation.



23

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

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

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

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

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

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

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

The five grate/kiln induration furnaces at this facility utilize the following fuels:

• Line 3 Rotary Kiln (EU 225 / SV 103) – natural gas, biomass, and fuel oil



• Line 6 Rotary Kiln (EU 315 / SV 144) – natural gas, biomass, fuel oil and coal

• Line 7 Rotary Kiln (EU 334 / SV 151) – natural gas, biomass, fuel oil and coal

Emissions from the induration furnaces are controlled as follows:

• PM / PM10: PM emissions are controlled by a wet scrubbers with water used as the scrubbing

solution. The PM emissions from the indurating furnace are subject to the taconite MACT

standard. are regulated by the Taconite MACT. As addressed in section 3.A, BART will be

presumed to be equivalent to MACT for PM and no further analysis will be required to

establish BART for PM for these sources.

On lines 4, 5, 6 and 7, the water from the scrubber passes through the scrubber once, with

some of the discharge water being used immediately used as process water in the

concentrator with the remainder of the water being discharged to the tailings basin. The wet

scrubbers are designed to remove PM and are considered a high efficiency PM wet scrubbers

and will be evaluated as such within this BART analysis.

The Line 3 wet scrubber was installed after the BART baseline period and started operation

on June 2006. The scrubber is a recirculating scrubber with the scrubber blowdown water

being treated before being discharged to the tailings basin. The wet scrubber is designed to



24

remove PM and is considered a high efficiency PM wet scrubber and will be evaluated as

such within this BART analysis. Since the scrubber was installed after the baseline date, the

emissions in the post-BART modeling analysis were adjusted to account for the improved

removal efficiency.

• SO2: SO2 emissions are controlled as collateral SO2 reductions by the existing wet scrubbers.

Therefore, the existing wet scrubbers are considered a low-efficiency SO2 scrubbers and will

be evaluated as such within this BART analysis.

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

emissions when burning solid fuels). NOX emissions are monitored using NOX continuous

emissions monitoring systems (CEMS).

Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of

the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March

2002, Minntac submitted a report to MPCA presenting an analysis of the NOX emissions from

Line 7 before and after the installation of the ports. This report is presented in Appendix D.

As described in the report, the NOX emissions from the kiln decreased by approximately 5%

when burning natural gas. However, no emission reduction was noted when burning solid

fuels. When evaluating the use of air injection ports for the reduction of NOX emissions, it is

important to note that solid fuels are typically burned in the furnaces and therefore, the actual

improvement in NOX emissions would be significantly less than 5% estimate.

In April 2006, replacement and reconfigured burners were installed into the preheat section

of Line 6. The burners were installed as an energy efficiency project. However, after

installation of the burners, the emissions from the kiln were evaluated using the data from the

NOx CEMS. This evaluation showed a reduction in NOX emissions from the kiln of

approximately 10% when the preheat section was in operation. Since the low-NOX burners

were installed after the baseline date, the emissions in the post-BART modeling analysis

were adjusted to account for the reduced emissions from Line 6. Additional information

regarding the post-BART modeling is presented in Step 5 of this BART analysis.



25

5.A.i Sulfur Dioxide Controls

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

Step 1 identifies a comprehensive list of all potential retrofit control technologies that were

evaluated. Many emerging technologies were identified that are not currently commercially

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

technology as it was understood at that time. In regards to the availability of the technology with

respect to Step 1 of the BART analysis, the list has not changed from the information submitted at

that time. The comprehensive list of control technologies is presented in Appendix E.

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

Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As

stated in section 2.B of this document, the technical feasibility of each option is determined by

answering three specific questions:


BART analysis?





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

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

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

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

technology.

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

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

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

Wet Walled Electrostatic Precipitator (WWESP)

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

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



26

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

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

rapping and fall into hoppers for collection and removal.

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

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

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

absorber.

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

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

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

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

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

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

process specific operating parameters.

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

technology for SO2 reduction for this BART analysis.

Wet Scrubbing (High and Low Efficiency)

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

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

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

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

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

wastewater.

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

designs for removal efficiency up to 95% SO2. Typical high efficiency SO2 wet scrubbers are packed-

bed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet scrubber can

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

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

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

emission reduction.



27

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

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

reactions are shown in the following equations:

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

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

follows:

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O

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

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

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

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

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

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

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

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

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

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

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

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

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

wet scrubber.

As previously stated, wet scrubbers are currently in place on the furnaces exhausts and are believed

to remove 15% to 30% of the SO2 in the exhaust based on Barr’s experience and testing which has



28

been completed. Taking into consideration the removal of SO2 from the low-efficiency primary PM

scrubber as well as a high efficiency SO2 polishing wet scrubber, an estimated overall efficiency of

the control train would then be approximately 80%.

In theory, the SO2 removal efficiency of the existing scrubbers could be improved through the

additions of caustic, lime, or limestone in the scrubber water to raise the pH. The existing scrubber

on lines 4-7 currently operates at approximately a neutral pH. However, the scrubbers, piping,

pumps and water tanks were not designed to operate at a higher pH so corrosion of the system would

be a concern. The addition of the chemicals and increased SO2 removal would create additional

solids and sulfates in the scrubber discharged to the tailings basin which would require substantial

and expensive treatment to maintain an acceptable water quality which could be discharged through

the existing NPDES permit. The new scrubber on Line 3 is a recirculating scrubber which operates

at a pH which is typically less than 7. The scrubber was operated temporarily at a higher pH, but

plugging and other operational problems resulted and the scrubber was returned to the current

operating pH. Based on these concerns, the improvement of SO2 removal efficiency of the existing

scrubbers is not a practical solution and is not considered further in this report.

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

technology for SO2 reduction for this BART analysis.

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)

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

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

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

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

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

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

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

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

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

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

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

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

content and will not be further evaluated in this report.



29

Spray Dryer Absorption (SDA)

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

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

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

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

desulfurization (FGD) may also be used.

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

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

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

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

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

be further evaluated in this report.

Energy Efficiency Projects

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

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

emissions. An example of an energy efficiency project would be to use waste heat to preheat

incoming make-up air or pellet feed. Each project is very dependent upon the fuel usage, process

equipment, type of product and many other variables.

Due to the increased price of fuel, this facility has already implemented several energy efficiency

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

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

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

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

implement energy efficiency projects as they arise.

Alternate Fuels

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

facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources.

These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO2 emissions

through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal,

and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one

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



30

significantly less NOx when burning solid fuels. Therefore, if this option is pursued, the impact on

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

to determine the net benefit of a particular alternative fuel.

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

option, not to direct the fuel choice.21

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

impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative

fuels as an air pollution control technology will not be further evaluated in this report.

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

fuel usage as the feasibility arises.

Coal Processing

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

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

and potential contaminants from the coal prior to use.

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

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

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

material.22 The processed coal is then passed on to an intermediate storage facility prior to being sent

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

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

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

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

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

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

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

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

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



31

To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coal-

fired boiler. Using processed fuels at a taconite plant would require research, test burns, and

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

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

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

Coal drying is currently being explored at a coal-fired utility in North Dakota as a potential viable

option a pre-combustion control for SO2 reduction. In the process, raw coal is crushed and screened

to remove rocks and other impurities, such as pyretic sulfur. The crushed coal is then thermally

processed to remove excess moisture. For this option to be viable, excess heat or low pressure steam

must be available to dry the coal. Since this heat source is not available at this facility, coal drying is

not feasible and will not be further evaluated in this report.

Step 2 Conclusion

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

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

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



32

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

Step 1 Step 2

SO2 Pollution Control Technology Is

th

is a

g

en

era

lly

a

va

ila

ble

co

ntr

ol

tec

hn

olo

gy

?

Is t

he

co

ntr

ol

tec

hn

olo

gy

a

va

ila

ble

to

in

du

rati

ng

fu

rna

ce

s?

Is t

he

co

ntr

ol

tec

hn

olo

gy

a

pp

lic

ab

le t

o t

his

s

pe

cif

ic s

ou

rce

?

Is i

t te

ch

nic

all

y

fea

sib

le f

or

this

s

ou

rce

?


Y Y Y Y

Secondary Wet Scrubber Y Y Y Y

Modifications to Existing Wet Scrubbing (Low Efficiency)

Y Y N N

Dry Sorbent Injection Y Y Y N

Spray Dry Absorption Y Y Y N

Energy Efficiency Projects Y Y Y N

Alternative Fuels Y Y Y

N

(not required by BART)

Coal Processing Y Y Y N

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

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

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

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

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80%

Secondary Wet Scrubber 60%



33

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

As illustrated in Table 5-2 above, the technically feasible control technologies remaining provide

varying levels of emission reduction. Therefore, it is necessary to consider the economic, energy,

and environmental impacts to better differentiate as presented below.

Economic Impacts

Table 5-3 details the expected costs associated with installation of a secondary wet scrubber or a wet

walled electrostatic precipitator (WWESP) after the existing scrubber on each stack. Equipment

design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models.

Capital costs were based on recent vendor quotations. The cost for that unit was scaled to each

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

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

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

EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours

per year (EPA default value). Operating costs of consumable materials, such as electricity, water, and

chemicals were established based on the U.S. EPA control cost manual23 and engineering experience,

and were adjusted for the specific flow rates and pollutant concentrations.

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

for a retrofit installation.24 After discussions with facility staff and management, it was determined

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

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

design of the existing building would not support additional equipment, such as an SO2 scrubber or

WWESP, on the roof. Therefore, the cost estimates provide for additional site-work and construction

costs to accommodate the new equipment within the facility. A site-specific estimate for site work,

foundations, and structural steel was added to arrive at the total retrofit installed cost of the control

technology. The site specific estimate was based on recent actual retrofit costs for installation of a

secondary wet scrubber at the facility. The detailed cost analysis is provided in Appendix A.

23 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 24 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2.



34

Table 5-3 Indurating Furnace SO2 Control Cost Summary



35

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

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

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

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

measure of affordability for the electric utility industry used by USEPA to support the BART rule-

making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant25.

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

evaluated for visibility improvement, energy and other impacts.

The cost of SO2 control for both of the technically feasible technologies is greater than $12,000 per

ton of pollutant removed. This cost is higher than the MPCA-directed annualized cost screening

level and is far in excess of any cost that is considered to be cost effective for BART. Therefore,

these alternatives are removed from further consideration in this analysis.

Energy and Environmental Issues

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

cost effective technology, these alternatives are removed from further consideration in this analysis.

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

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

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

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

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



36

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

document. Because the cost of SO2 controls is so high and does not meet a reasonable definition of

cost effective technology, visibility impacts were not modeled for SO2.

However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline

period and started operation on June 2006. The scrubber is considered a high efficiency scrubber for

PM and a low efficiency scrubber for SO2. Since the scrubber was installed after the baseline date,

the emissions in the post-BART modeling analysis must be adjusted to account for the improved

removal efficiency. Also as previously stated, replacement and reconfigured burners were installed

into the preheat section of Line 6 on April 2006 which reduced the NOX emissions from the kiln of

approximately 10% when the preheat section was in operation. Since the low-NOX burners were

installed after the baseline date, the emissions in the post-BART modeling analysis must also be

adjusted to account for the reduced emissions from Line 6. Therefore, the visibility impacts

modeling presented in this section represent the post-baseline (i.e. post-BART) current operations of

the facility.

Predicted 24-Hour Maximum Emission Rates

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

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

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

emissions from the Line 3 indurating furnaces were adjusted to account for the new wet scrubber and

the emissions from the Line 6 indurating furnace was adjusted to account for replacement and

reconfigured low-NOx burners which have been installed in the preheat section. The emissions from

all other Subject-to-BART sources were not changed. Table 5-4 provides a summary of the modeled

SO2, NOX, and PM 24-hour maximum emission rates for the post-baseline (i.e. post-BART) current

operations. Similar to the modeling for the baseline or pre-BART operating conditions, modeling

was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural

gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in

the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature)

were assumed to remain unchanged from the baseline modeling.



37

Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates



38

Post-BART Visibility Impacts Modeling Results

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

5-5. The results summarize 98th percentile dV value and the number of days the facility contributes

more than a 0.5 dV of visibility impairment at each of the Class I areas.

As illustrated in tables 5-5, the current operation of the facility results in a visibility improvement of

0.196 dV when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln.

Both of these values represent a 3% improvement compared to the baseline or pre-BART emissions.

A summary of visibility impacts for the total facility BART analysis are presented in Section 6.



39

Table 5-5 Indurating Furnace Post-BART SO2 Modeling Scenarios - Visibility Modeling Results



40

5.A.ii Nitrogen Oxide Controls

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

mechanisms by which NOx production occurs:

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

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

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

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

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

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

minor amounts of NOx are emitted as prompt NOx.

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

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

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

Step 1 identifies a comprehensive list of all potential retrofit control technologies that were

evaluated. Many emerging technologies were identified that are not currently commercially

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

technology as it was understood at that time. In regards to the availability of the technology with

respect to Step 1 of the BART analysis, the list has not changed from the information submitted at

that time. The comprehensive list of control technologies is presented in Appendix E.

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





BART analysis?





41



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

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

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

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

technology.

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

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

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

External Flue Gas Recirculation (EFGR)

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

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

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

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

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

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

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

the burner tip.

The typical NOx control efficiency range for EFGR on a boiler is 30% to 50%.

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

1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen

versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so

it can be used as a diluent for oxygen for flame temperature reduction. Taconite waste

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

equivalent to adding combustion air instead of an inert gas.

2. The oxidation zone of induration furnaces needs to be above 2,400oF in order to meet

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



42

Application of EFGR would reduce flame temperatures. Lower flame temperatures

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

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

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

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

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

equipment failures.

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

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

Low-NOx Burners

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

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

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

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

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

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

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

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

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

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

If LNB were to be applied in the indurating section of the furnace, the reduced flame temperatures

associated with LNB would adversely affect taconite pellet product quality. In addition, the oxygen

concentration cannot be controlled at the burner tip in the induration section of the furnace.

Therefore, LNB is not feasible in the induration section of the permit.

However, the use LNB in the pre-heat section of the furnace is feasible and NOx reductions could be

credited for that section of the furnace. However, the NOx emissions from the pre-heat section

cannot be measured separately from the total furnace NOx emissions, so the actual emission reduction

from the burners is unknown. However, in April 2006 replacement and reconfigured burners were

installed into the preheat section of Line 6. The burners were installed as an energy efficiency

project. After installation of the burners, the emissions from the kiln were evaluated using the data



43

from the NOx CEMS. This analysis showed a reduction in NOX emissions from the kiln of

approximately 10% when the preheat section was in operation. Based on this information, a 10%

reduction was assumed for the installation of low-NOx burners on the preheat sections of lines 4, 5,

and 7 (Line 3 does not currently use burners in the preheat section). However, due to differences in

design and operation of the various kilns, the 10% reduction should only be treated as an estimate as

the actual emissions reduction would not be known until after installation and testing. Low-NOx

burners will be considered an available and applicable technology for lines with preheat sections.

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

are not yet commercially available. Some incorporate various fuel dilution techniques to reduce

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

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

successfully used for reducing NOx emissions from gas turbines. The water injection technique

shows promise for high temperature applications, but will not be further investigated in this report as

the technology is still in the research and development phase.

Induced Flue Gas Recirculation Burners

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

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

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

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

burners in high temperature applications is 25-50%.

As previously noted, taconite furnaces are designed to operate with oxygen levels of approximately

15% to 18%. At these oxygen levels, flue gas recirculation is ineffective at NOx reduction, and it

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

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

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

rises up. Furthermore, IFGR is not feasible in the kiln because the reduced flame temperatures

associated with IFGR could adversely affect taconite pellet product quality.

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

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



44


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

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

emissions. An example of an energy efficiency project could be to preheat incoming make-up air or

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

and many other variables.

Due to the increased price of fuel, this facility has already implemented several energy efficiency

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

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

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

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

implement energy efficiency projects as they arise.

Ported Kilns

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

kiln. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln

bed. Ports are installed about the circumference of the kiln. Each port is equipped with a closure

device that opens when it is at the bottom position to inject air in the pellet bed, and closed when it

rotates out of position. The purpose of air injection is to provide additional oxygen for pellet

oxidation. The oxidation reaction extracts enough heat to offset the heat loss associated with air

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

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

Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports

is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac

submitted a report to MPCA presenting an analysis of the NOX emissions from Line 7 before and

after the installation of the ports. This report is presented in Appendix D. As described in the report,

the NOX emissions from the kiln decreased by approximately 5% when burning natural gas.

However, no emission reduction was noted when burning solid fuels. When evaluating the use of air

injection ports for the reduction of NOx emissions, it is important to note that solid fuels are typically

burned in the furnaces and therefore, the actual improvement in NOX emissions would be

significantly less than 5% estimate.



45

Alternate Fuels

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

facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources.

These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO2 emissions

through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal,

and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one

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

significantly less NOx when burning solid fuels. Therefore, if this option is pursued, the impact on

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

to determine the net benefit of a particular alternative fuel.



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

impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative

fuels as an air pollution control technology will not be further evaluated in this report.

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


Process Optimization with NOx CEMS or Other Parametric Monitoring

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

emissions27. Based on conversations with MPCA staff, this work practice would include process

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

would be measured using the NOx CEMS. If NOx CEMS are not installed, it may also be possible to

measure the impact of the process changes using parametric monitoring.

As part of the negotiation of the draft PSD permit, Minntac has installed NOx CEMS on all five

indurating furnaces. The use of the NOx CEMS has resulted in lower emissions being reported in the

annual emissions inventory. However, this decrease may be due to having actual emission data

available for the report rather than using the emissions from stack tests which were conducted at


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



46

worst-case operating conditions. In addition, the NOx CEMS has allowed Minntac to quantify the

emissions rates for all fuel combinations.

Although the NOx CEMS has allowed the facility to use better data for reporting, the facility has not

yet identified specific operating parameters which can be controlled to reduce emissions without

sacrificing unit efficiency or product quality.

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

achieved through the use of the process optimization, using NOx CEMS as a control technology.

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

Post Combustion Controls

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

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

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

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

In addition to these treatment systems, there are a large number of other processes being developed

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

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

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

alternatives are described below.

Non-Selective Catalytic Reduction (NSCR)

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

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

primarily in natural gas combustion applications.



47

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

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

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

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

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

are:

2CO + 2NO → 2CO2 + N2 (1)

[UBH] + NO → N2 + CO2 + H2O (2)

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

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

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

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

this report.

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction

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

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

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)

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

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

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

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

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

to 1000°F temperature range. However, these catalysts are very expensive.

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

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

low loads because of the low gas temperature.

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

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



48

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

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

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

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

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

recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95%

versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to

70%.

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

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

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

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

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

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

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

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

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

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

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

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

furnace:

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

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

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

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

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

to the erosive nature of the taconite dust;

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

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

corrosion protection;



49

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

local environment and have adverse impact. The impact of SCR on mercury emissions needs

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

mitigation methods if needed.

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

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

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

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

BART analysis.

However, SCR with reheat through a conventional duct burner (rather than using a regenerative

heater) has been successfully implemented more widely and in higher airflow applications and will

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

to be technically feasible.

Low Temperature Oxidation (LTO)

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

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

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

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

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

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

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

NO + O3 → NO2 + O2 (1)

NO2 + O3 → NO3 + O2 (2)

NO3 + NO2 → N2O5 (3)

N2O5 + H2O → 2HNO3 (4)

HNO3 + NaOH → NaNO3 + H2O (5)



50

Low Temperature Oxidation (Tri-NOx®)

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

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

reactions are as follows:

O3 + NO → O2 + NO2 (1)

2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)

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

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

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

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

advantage of the Tri-NOx® process is that concurrent scrubbing of sulfuric acid mist can be achieved.

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

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

300 ppm. Therefore, Tri-NOx® is not applicable to taconite processing and will not be analyzed

further in this BART analysis.

Low Temperature Oxidation (LoTOx®)

BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone

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

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

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

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

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

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

generation.

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

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

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

technology applies to an indurating furnace, the technology has not been demonstrated on a taconite

pellet indurating furnace. This raises uncertainties about how or whether the technology will

transfer. The second component of the technical feasibility review includes determining if the



51

technology is commercially available. Evaluations of LTO found that it has only been applied to

small to medium sized coal or gas fired boiler applications, and has never been demonstrated on a

large-scale facility. For example, the current installations of LoTOx® are on sources with flue gas

flow rates from 150 – 35,000 acfm, which is quite small, compared to the indurating furnace flue gas

flow rates of more than 500,000 acfm. This large scale-up is contrary to good engineering practices

and could be problematic in maintaining the current removal efficiencies.

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

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

demonstrated to be an effective technology in widespread application.

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

indurating furnace:

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

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

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

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

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

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

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

generated or a decrease in the estimated control efficiency;

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

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

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

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

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

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

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

problems and would likely cause additional problems with National Pollutant Discharge

Elimination System (NPDES) discharge limits and requirements.



52

In addition, application of this technology has not been applied to taconite induration furnaces, to

airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high

moisture content. Using LTO at a taconite plant would require research, test runs, and extended trials

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

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

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

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

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

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

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

implementation plan (SIP) by December 2007.

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

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

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

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

this application and will not be evaluated further.

Step 2 Conclusion

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





53

Table 5-6 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility

Step 1 Step 2


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Y Y N ---

Low-NOx Burners Y Y

Y

(preheat section)

Y


Y Y N ---


Ported Kilns Y Y Y Y

Alternative Fuels Y Y N

N

(not required by BART)

Process Optimization using

NOx CEMS Y Y Y N


Y N --- ---

Selective Catalytic Reduction (SCR) with conventional reheat

Y Y Y Y

Regenerative SCR Y N --- ---

Selective Non-Catalytic Reduction (SNCR)

Y N --- ---


Y N --- ---



54

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

Table 5-7 describes the expected control efficiency from each of the remaining technically feasible

control options as identified in Step 2.

Table 5-7 Indurating Furnace NOx Control Technology Effectiveness

NOx Pollution Control Technology

Approximate Control Efficiency

SCR with Conventional Reheat

80%

Low-NOx Burners 10%

Ported Kilns 5%

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

Table 5-8 details the expected costs associated with installation of SCR with conventional reheat, low

NOx burners, ported kilns, and a combination of low-NOx burners and ported kilns.

Equipment design was based on the maximum 24-hour emissions, vendor estimates (when available),

and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that

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

equation:

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

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

EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours

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

established based on the U.S. EPA control cost manual28 and engineering experience, and were

adjusted for the specific flow rates and pollutant concentrations.

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



55

Table 5-8 Indurating Furnace NOx Control Cost Summary



56

Due to space considerations, 60%29 of the total capital investment was included in the costs to

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

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

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

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

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

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

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

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

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



















29 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 30 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.



57

The cost of NOx control for using SCR with conventional reheat is far in excess of any cost that is

considered to be cost effective for BART, or even for BACT. Therefore, this technology is not

carried forward in the analysis. The costs for ported kilns, low-NOx burners, and ported kilns with

low-NOx burners, where appropriate, are below the MPCA recommended screening threshold of

$12,000 per ton, and therefore are carried forward in the BART analysis.

Energy and Environmental Issues

The energy and non-air quality impacts for ported kilns, low-NOx burners, and ported kilns with low-

NOx burners, where appropriate, are presented in Table 5-9.

Table 5-9 Indurating Furnace NOx Control Technology Impacts Assessment

Control Technology Energy Impacts Other Impacts

Ported Kilns • None • None

Low-NOx Burners • Improved efficiency of preheat section

• None

Ported Kilns with

Low-NOx Burners • Improved efficiency

of preheat section • None

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





document.

However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline

period and started operation in June 2006. The scrubber is considered a high efficiency scrubber for

PM and a low efficiency scrubber for SO2. Since the scrubber was installed after the baseline date,

the emissions in the post-BART modeling analysis must be adjusted to account for the improved

removal efficiency. Also as previously stated, replacement and reconfigured burners were installed

into the preheat section of Line 6 which reduced the NOX emissions from the kiln of approximately

10% when the preheat section was in operation. Since the low-NOX burners were installed after the

baseline date, the emissions in the post-BART modeling analysis must also be adjusted to account for



58

the reduced emissions from Line 6. Therefore, the visibility impacts modeling presented in this

section represent the post-baseline (i.e. post-BART) current operations of the facility.




maximum 24-hour average projected emission rate. Similar to the modeling for the baseline or pre-

BART operating conditions, modeling was conducted for two separate operating scenarios for fuel

burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that

natural gas is the only fuel that is burned in the preheat section of the kiln. The stack parameters

(location, height, velocity, and temperature) were assumed to remain unchanged from the baseline

modeling. In the visibility impacts modeling analysis, the emissions were adjusted as follows:

• Line 3 indurating furnaces emissions were adjusted to account for the new wet scrubber and

the emissions;

• Line 6 indurating furnace emissions were adjusted to account for the replacement and

reconfigured low-NOx burners which have been installed in the preheat section.

• The emissions during current operations for all indurating furnaces were adjusted for each

control technology, as appropriate; and

• The emissions from all other Subject-to-BART sources were not changed.

Table 5-10 provides a summary of the modeled SO2, NOX, and PM 24-hour maximum emission rates

for the post-baseline (i.e. post-BART) current operations.


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

5-11. The results summarize 98th percentile dV value and the number of days the facility contributes

more than a 0.5 dV of visibility impairment at each of the Class I areas. As illustrated in tables 5-11,

post-BART modeled visibility improvements are as follows:

• The current operation of the facility results in a visibility improvement of 0.196 dV when

burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln. Both of

these values represent a 3% improvement compared to the baseline emissions.



59

• The installation of ported kilns on lines 3, 4, and 5 could result in a visibility improvement of

0.330 dV when burning natural gas in the kiln, which represents a 5% improvement from the

baseline when burning natural gas in the kiln. Since ported kilns do not reduce emissions

when burning solid fuels, there is no additional visibility improvement for that scenario

compared to current operations. It is very important to note that normal operation of the

indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no

improvement in visibility for ported kilns under normal operation.

• The installation of low-NOx burners on the preheat sections of lines 4, 5, and 7 results in a

visibility improvement of 0.488 dV when burning natural gas in the kiln, and 0.465 dV when

burning solid fuels in the kiln. Both of these values represent a 7% improvement compared

to the baseline emissions.

• The combined installation of ported kilns on lines 3, 4, and 5 and low-NOx burners on lines 4,

5, and 7 results in a visibility improvement of 0.627 dV when burning natural gas in the kiln

and 0.465 dV when burning solid fuels in the kiln. Since ported kilns do not reduce

emissions when burning solid fuels, it is again very important to note that normal operation

of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no

improvement in visibility for ported kilns under normal operation and the visibility

improvement for normal operation is only due to the low-NOX burners on the preheat

sections of lines 4, 5, and 7.




60

Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates



61

Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results



62

5.B External Combustion Sources

Five utility plant heating boilers are subject-to-BART at this facility. As shown in section 4, the five

boilers underwent a streamlined analysis for SO2 and PM and one of the boilers underwent a

streamlined analysis for NOx. Therefore, the remaining four boilers require a full BART analysis for

NOX.

The utility plant heating boilers are permitted to burn natural gas and fuel oil. The boilers are

generally operated on a seasonal basis to provide heat to the facility. The highest emitting days are

typically cold days in which the facility has a high heat demand and on which a natural gas

curtailment occurs which requires the burning of the higher-emitting fuel oil.

5.B.i Nitrogen Oxide Controls

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

mechanisms by which NOx production occurs:

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

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

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

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

Conditions for formation of thermal NOx exist primarily in the burner flame.

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

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

minor amounts of NOx are emitted as prompt NOx.

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

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

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

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

evaluated. Step 1 identifies a comprehensive list of all potential retrofit control technologies that

were evaluated. Many emerging technologies were identified that are not currently commercially



63

available. Appendix G presents the current status of the availability and applicability of each

technology.

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





BART analysis?

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

undergoing the BART analysis?

3. Are there source-specific issues/conditions that would make the control technology not

technically feasible?

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

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

is technically feasible for indurating furnaces.


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

reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is collected from the

heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air

and this mixture is introduced into the burner. The addition of flue gas reduces the oxygen content of the

“combustion air” (air + flue gas) in the burner. The lower oxygen level in the combustion zone reduces flame

temperatures; which in turn reduces NOx emissions. For a boiler to accommodate EFGR, air ducts and registers

need to be able to withstand higher temperatures and flow rates, burners must be able to produce a stable flame

with the flue gas added, and the firebox must be able to accommodate longer flame length to avoid flame

impingement. Based on conversations with utility plant staff, the existing equipment cannot meet these

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

Low NOx Burners (LNB)

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

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

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



64

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

levels limit flame temperatures resulting in less NOx formation. The primary zone is then followed by

a secondary zone in which the incomplete combustion products formed in the primary zone act as

reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce

flame temperature to reduce NOx formation. In the secondary zone, combustion products formed in

the primary zone act to lower the local oxygen concentration, resulting in a decrease in NOx

formation. Low NOx burners typically achieve NOx emission reductions of 25% - 50% for process

boilers. LNB is a technology commonly used on boilers and is considered a available and applicable

technology.

Overfire Air (OFA)

Overfire air diverts a portion of the total combustion air from the burners and injects it through

separate air ports above the top level of burners. OFA is the typical NOx control technology used in

boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates an initial

fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of

thermal NOx by lowering combustion temperature and limiting the availability of oxygen in the

combustion zone where NOx is most likely to be formed. LNB is a technology commonly used on

boilers and is considered a available and applicable technology. In addition, OFA can also be used in

combination with LNB.


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

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

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

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

burners in high temperature applications is 50-75%. This technology is considered an available and

applicable technology.



65


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

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

efficiency project would be to reduce steam consumption which would decrease fuel burning

requirements. Each project is very dependent upon the fuel usage, process equipment, type of

product and many other variables.

Due to the increased price of fuel, Minntac has already implemented several energy efficiency

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

would be impossible to assign a general potential emission reduction for the energy efficient

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

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

energy efficiency projects as they arise.

Alternate Fuels

The increased price of fuel has pushed companies to evaluate alternate fuel consumption and

available fuel sources. These fuel sources come in all forms – solid, liquid and gas. The heating

boilers at Minntac are capable of burning natural gas and fuel oil. Since the boilers do not burn solid

fuels, the options for alternate fuels are limited. Normal operation is on natural gas which is

generally the lowest emitting fuel for a boiler.



Therefore, due to the uncertainty of alternative fuel costs, the limited options available, the fact that

natural gas is the typical fuel burned in the boilers and the fact that BART is not intended to mandate

a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in

this report

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





66


NOx can be controlled using add-on systems located downstream of the boiler combustion process.

The two main techniques in commercial service include the selective non catalytic reduction (SNCR)

process and the selective catalytic reduction (SCR) process. There are a number of different process

systems in each of these categories of control techniques.

In addition to these treatment systems, there are a large number of other processes being developed

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

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

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

alternatives is described below.


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

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

primarily in natural gas combustion applications.

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

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

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

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

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

are:

2CO + 2NO → 2CO2 + N2 (1)

[UBH] + NO → N2 + CO2 + H2O (2)

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

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

liquid fuels. Since the highest emitting days occur while burning fuel oil, this technology will not be

further evaluated in this report.

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction

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

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



67

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)

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

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

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

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

corrosion problems.

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

temperature range. However, these catalysts are very expensive.

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

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

low loads because of the low gas temperature.

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

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

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

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

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

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

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

recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95%

versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to

70%.

SCR and R-SCR have both been applied to boilers. Although there may be concerns about the actual

applicability of the technology to the boilers at this facility, the technologies will be considered

feasible for the purposes of this report.


In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%.

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The

relevant reactions are as follows:



68

NO + NH3 + ¼O2 → N2 + 3/2H2O (1)

NH3 + ¼O2 → NO + 3/2H2O (2)

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F,

reaction (2) will dominate. This control option is considered feasible.


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

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

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

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

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

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

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

NO + O3 → NO2 + O2 (1)

NO2 + O3 → NO3 + O2 (2)

NO3 + NO2 → N2O5 (3)

N2O5 + H2O → 2HNO3 (4)

HNO3 + NaOH → NaNO3 + H2O (5)

Low Temperature Oxidation (Tri-NOx®)

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

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

reactions are as follows:

O3 + NO → O2 + NO2 (1)

2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)

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

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

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



69

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

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

(1,000 ppm NOx).

Low Temperature Oxidation (LoTOx®)

BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone

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

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

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

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

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

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

generation.

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

LoTOx has been applied to gas and coal fired boilers. Therefore, although LoTOx is an emerging

technology, has limited installations, and there may be concerns about the actual applicability of the

technology to the boilers at this facility, the technologies will be considered feasible for the purposes

of this report.

Step 2 Conclusion

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





70

Table 5-12 Boiler NOx Control Technology – Availability, Applicability, and Technical Feasibility

Step 1 Step 2


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er?

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?


Y Y N ---

Low-NOx Burners Y Y Y Y

Overfired Air Y Y Y Y

Induced Flue Gas Recirculation (IFGR)

Y Y Y Y


Alternative Fuels Y Y Y N


Y Y Y N

Selective Catalytic Reduction (SCR)

Y Y Y Y

Regenerative SCR Y Y Y Y


Y Y Y Y


Y Y Y Y

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

Table 5-13 describes the expected control efficiency from each of the remaining technically feasible

control options as identified in Step 2.



71

Table 5-13 Boiler NOx Control Technology Effectiveness

NOx Pollution Control Technology Approximate Control

Efficiency

LoTOx 90%

SCR 80%

Low-NOx Burners with IFGR 75%

R-SCR 70%

Low-NOx Burners with OFA 67%

Low-NOx Burners 50%

Selective Non-Catalytic Reduction (SNCR) 50%

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

Table 5-14 details the expected costs associated with installation of NOx controls. Capital costs were

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

Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate

using the 6/10 power law to account for the economy of scale. Operating costs were based on 93%

utilization and 3,156 operating hours per year, which is based on historic operating records.

Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant

concentrations. Where applicable, a site-specific estimate for site-work, foundations, and structural

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

technology. The detailed cost analysis is provided in Appendix A.














72

Table 5-14 Boiler NOx Control Cost Summary



73








The costs of NOx control for SCR, low-NOx burners with flue gas recirculation, low-NOX burners

with overfire air, and SNCR are far in excess of any cost that is considered to be cost effective for

BART, or even for BACT. Therefore, these technologies are not carried forward in the analysis.

The costs for low-NOx burners are below the MPCA recommended screening threshold of $12,000

per ton, and therefore are carried forward in the BART analysis.

Energy and Environmental Impacts

The energy and environmental impacts for low-NOx burners are minimal.

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





document.




maximum 24-hour average project emission rate. The stack parameters (location, height, velocity,

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

Table 5-15 provides a summary of the modeled NOX 24-hour maximum emission rates for the post-

baseline (i.e. post-BART) operating scenario for installing low-NOX burners on the four boilers.

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



74


Results of the post-BART visibility impacts modeling summarize 98th percentile dV value and the

number of days the facility contributes more than a 0.5 dV of visibility impairment at each of the

Class I areas. As illustrated in tables 5-16, post-BART modeled visibility improvements are as

follows:

• The installation of low-NOx burners on the boilers results in a visibility improvement of

0.008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these

modeling results, the visibility improvement for the installation of low-NOx burners on the

boilers is basically negligible.




75

Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates



76

Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results



77

6. Visibility Impacts



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

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

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

5.A.ii.e, and 5.B.i.e. This section of the report evaluates the various BART control scenarios

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

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

controls. However, since there were no control technologies for SO2 that required visibility impacts

analysis, there are no SO2/NOx combinations that need to be evaluated. Therefore, no new or

additional modeling scenarios are presented in this section.

6.A Post-BART Modeling Scenarios All of the modeling scenario results, as presented in sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e or this

report, are presented in Table 6-1. As previously stated, no new or additional modeling scenarios are

presented.

6.B Post-BART Modeling Results Results of all post-BART modeling scenarios are presented in Table 6-1. These results were also

presented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. As previously stated, no new or

additional modeling scenarios are presented. The results summarize 98th percentile dV value and the

number of days the facility contributes more than a 0.5 dV of visibility impairment at each of the

Class I areas.

When reviewing the modeling results for the indurating furnaces, it is important to note the

following:

• Current Operation:

o The current operation of the facility results in a visibility improvement of 0.196 dV

when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the

kiln. Both of these values represent a 3% improvement compared to the baseline

emissions.



78

• Ported Kilns:

o Natural Gas Operation: The installation of ported kilns on lines 3, 4, and 5 results in a

visibility improvement of 0.330 dV when burning natural gas in the kiln, which

represents an addition 0.134 dV compared to the current operation when burning

natural gas in the kiln. This is a 5% improvement from the baseline when burning

natural gas in the kiln and a 2% improvement from the current operation when

burning natural gas in the kiln.

o Solid Fuel Operation: Since ported kilns do not reduce emissions when burning solid

fuels, there is no additional visibility improvement for that scenario compared to

current operations. It is very important to note that normal operation of the

indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no

improvement in visibility for ported kilns under normal operation.

• Low-NOX Burners:

o Natural Gas Operation: The installation of low-NOx burners on the preheat sections

of lines 4, 5, and 7 results in a visibility improvement of 0.488 dV when burning

natural gas in the kiln which represents an addition 0.292 dV compared to the current

operation when burning natural gas in the kiln. This is a 7% improvement from the

baseline when burning natural gas and a 4% improvement from the current operation

when burning natural gas.

o Solid Fuel Operation: The installation of low-NOx burners on the preheat sections of

lines 4, 5, and 7 results in a visibility improvement of 0.465 dV when burning solid

fuels in the kiln which represents an addition 0.277 dV compared to the current

operation when burning solid fuels in the kiln. This is a 7% improvement from the

baseline when burning solid fuels in the kiln and a 4% improvement from the current

operation when burning solid fuels in the kiln.

• Ported Kilns with Low-NOX Burners:

o Natural Gas Operation: The combined installation of ported kilns on lines 3, 4, and 5

and low-NOx burners on lines 4, 5, and 7 results in a visibility improvement of 0.627

dV when burning natural gas in the kiln which represents an addition 0.431 dV



79

compared to the current operation when burning natural gas in the kiln. This is a 9%

improvement from the baseline when burning natural gas in the kiln and a 6%

improvement from the current operation when burning natural gas in the kiln.

o Solid Fuel Operation: The combined installation of ported kilns on lines 3, 4, and 5

and low-NOx burners on lines 4, 5, and 7 results in a visibility improvement of 0.465

dV when burning solid fuels in the kiln which represents an addition 0.277 dV

compared to the current operation when burning solid fuels in the kiln. This is a 7%

improvement from the baseline when burning solid fuels in the kiln and a 7%

improvement from the current operation when burning solid fuels in the kiln.

When reviewing the modeling results for the boilers, it is important to note the following:

• The installation of low-NOx burners on the boilers results in a visibility improvement of

0.008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these

modeling results, the visibility improvement for the installation of low-NOx burners on the

boilers is basically negligible.



80

Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results



81

7. Select BART

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

through 5, as presented in section 5 of this report.

7.A Indurating Furnaces Minntac operates five indurating furnaces which are subject-to-BART:

• Line 3 Rotary Kiln (EU 225 / SV 103)





As presented in section 3 of the report, the PM emissions from the indurating furnaces were subject

to a streamlined BART analysis based on the specific provision that compliance with the Taconite

MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions is equivalent to BART. The Taconite

MACT standard includes requirements for performance testing and continuous parametric monitoring

for compliance demonstration.

As presented in section 5.A of this report, the five indurating furnaces at Minntac were required to

undergo a full BART analysis for NOx and SO2.

As presented in section 5.A of this report, the indurating furnace was required to undergo a full

BART analysis for SO2 and NOx. The selection is based on consideration of all of the criteria

presented in MPCA and U.S. EPA guidance for determining BART, as presented in this report.

The following technologies were identified as technically feasible and subject to the full BART

analysis: new wet scrubbers that control PM and SO2, add-on secondary wet scrubber to control

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

secondary wet scrubber, ported kiln, and SCR alternatives were not proposed as BART for the

following reasons:



82

Ported Kiln

Converting the kilns 3, 4 and 5 to ported kilns would result in only an estimated 5% decrease

in NOx emissions when burning gas in the kiln and the corresponding impact on visibility is

also minimal. It would not result in emissions reductions when burning solid fuel in the kiln,

which is the primary fuel used by Minntac. Therefore, the technology will not result in any

significant visibility improvement at the Class I areas compared to the current operation.

Further, it is not cost effective at an estimated amount of more than $5,000/ton NOx removed.

Based on the consideration of all of the criteria presented in the BART analysis, Minntac proposes

the following as BART for SO2 and NOX for the Indurating Furnaces:

• BART for SO2:

o SO2 emissions will be controlled by the existing wet scrubbers, which will be

operated as required in accordance with provisions of the Taconite MACT.

o SO2 emission limit for the Indurating Furnace on Line 3 will be determined based

on upcoming performance testing to determine the actual emission rate from the

furnace with the addition of the new scrubber. A proposed SO2 limit for the

furnace in the draft PSD permit for Minntac does not reflect the recently installed

wet scrubber.

o SO2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the

limits which are based on using the existing wet scrubbers and reflect air

dispersion modeling results for regional haze as proposed in the draft PSD

permit:





o Compliance will be initially be demonstrated by a performance test at each

furnace.



83

o Continuous compliance will be demonstrated by continuous monitoring of

scrubber water flow rate and scrubber pressure drop, which are the same

parameters that will be monitored under the Taconite MACT. The operating

limits will be determined based on the initial SO2 compliance test and will be

based on a 24-hour block average, consistent with the Taconite MACT.

• BART for NOx:

o NOx emissions will be controlled as follows:

⋅ Line 3: Existing combustion controls and fuel blending. Line 3 does not

currently use burners in its pre-heat section, and therefore low-NOx burners

cannot be applied at this furnace.





⋅ Line 6: Operation of low-NOx burners on the pre-heat section (installed as

replacement and reconfigured burners in April 2006), existing combustion

controls, and fuel blending.



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

installation of the low-NOx burners to allow the facility sufficient time for

process and emissions monitoring using NOx CEMS to determine the actual

emission rates under a variety of operating conditions. Although the facility

anticipates a significant reduction in NOx emissions with the installation of the

low-NOx burners, the actual emissions reduction cannot be determined until the

burners are operated under a variety of operation conditions.



84

o Initial and continuous compliance will be demonstrated after the appropriate

emission limits have been determined. Compliance will be demonstrated using

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

The schedule for implementation of these controls, specifically installation of low-NOx burners and

subsequent testing to demonstrate the appropriate BART emission limit, will be within the 5-year

time-frame required for BART implementation. In addition, Minntac will continue to evaluate energy

efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission

rates.

Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for

the installation of low-NOx burners, the proposed BART controls will result in visibility

improvement on the 98th percentile day of approximately 0.488 dV when burning gas in the kiln and

0.465 dV when burning solid fuels in the kiln. This is a visibility improvement of approximately 7%

compared to the baseline (pre-BART) operating conditions.

7.B External Combustion Sources Minntac operates 5 utility plant heating boilers which are subject-to-BART:






As presented in section 3 of the report, the SO2 and PM emissions from all five boilers underwent a

streamlined BART analysis based on the de minimis modeling results as presented in section 3.F. In

addition, the NOx emissions from boiler #3 underwent a streamlined BART analysis for NOx. Based

on the consideration of all of the criteria presented in the BART analysis, Minntac proposes no

additional controls, emission limits, or monitoring requirements for the NOx emissions from four

heating boilers. This is based on the conclusion that the control technologies that meet the cost

screening threshold do not provide significant improvement in the visibility modeling. It is also



85

important to note that due to the relatively small size of the boilers and the low hours of operation,

the actual visibility impact of the boilers is small.


Emission

Unit # Emission Unit Description

NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack

Number Actions Required

3.A. Indurating Furnaces

EU 223 Traveling Grate (Line 3) --- --- 655.2 0.01 SV 103 BART Analysis for SO2 + NOx

EU 225 Rotary Kiln (Line 3) --- --- Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOx

EU 226 Pellet Cooler Secondary Air (Line 3) --- --- Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOx

EU 259 Traveling Grate (Line 4) --- --- 1,504.8 0.01 SV 118 BART Analysis for SO2 + NOx

EU 260 Recouperative System Air (Line 4) --- --- Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOx




EU 281 Recouperative System Air (Line 5) --- --- Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOx




EU 314 Recoup System (Line 6) --- --- Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOx




EU 333 Recoup System (Line 7) --- --- Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOx



3.B. PM-Only Taconite MACT Emission Units

EU 013 Dump Pocket --- --- 62.4 0.008 SV 013 None

EU 014 Crusher --- --- Incl with EU013 0.008 SV 013 None





EU 019 Dump Pocket --- --- Incl with EU017 0.008 SV 015 None


EU 022 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 016 None

EU 023 Pre-1969 Panfeeder --- --- Incl with EU022 0.008 SV 016 None

EU 024 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 017 None

EU 025 Pre-1969 Panfeeder --- --- Incl with EU024 0.008 SV 017 None

EU 026 Post-1969 Panfeeder --- --- 11.0 0.008 SV 018 None

EU 027 Post-1969 Panfeeder --- --- Incl with EU026 0.008 SV 018 None

EU 034 Ore Transfer From 061-02-1 to 005-02-1 --- --- 31.2 0.008 SV 021 None


Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


EU 035 Ore Transfer From 061-02-1 to 005-02-1 --- --- Incl with EU034 0.008 SV 021 None


EU 037 Ore Transfer Fr 004-01-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 None

EU 038 Ore Transfer Fr 004-02-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 None






EU 044 Ore Transfer From 011-03-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 None




EU 048 Ore Transfer From Stockpile to 011-01-1 --- --- 31.2 0.008 SV 026 None

EU 052 Ore Transfer Fr 008-01-1 to 009-01-1 or 009-02-1 --- --- 6.0 0.008 SV 030 None


EU 054 Secondary Crusher --- --- 14.2 0.008 SV 031 None















EU 069 Tertiary Crusher --- --- 7.2 0.008 SV 038 None






Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack







































Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack





































EU 155 Ore Transfer From 020-01-1 to Bin 100-06 --- --- 5.5 0.008 SV 089 None


Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


EU 156 Ore Transfer From 020-01-1 to Bin 100-07 --- --- Incl with EU155 0.008 SV 089 None





































Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack

























EU 221 Traveling Grate --- --- 4.6 0.008 SV 101 None


EU 227 L3 Pellet Cooler --- --- 832.8 0.008 SV 104 None

EU 228 L3 Pellet Cooler Dump Zone --- --- 9.4 0.008 SV 105 None

EU 229 L3 Feeder 041/046 Belts --- --- 912.0 0.008 SV 106 None

EU 230 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 --- --- 4.3 0.008 SV 107 None

EU 231 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 --- --- Incl with EU230 0.008 SV 107 None

EU 232 Pellet Transfer From 042-01-1 to 043-01-1 --- --- 4.3 0.008 SV 108 None

EU 233 Pellet Transfer From 042-01-2 to 043-01-2 --- --- Incl with EU232 0.008 SV 108 None






Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack



EU 264 L4 Conv. Trans. Feeder --- --- 912.0 0.008 SV 120 None







EU 285 L5 Conv. Trans. Feeder --- --- 912.0 0.008 SV 129 None




EU 289 Conveyor --- --- 77.8 0.008 SV 132 None







EU 296 Pellet Transfer From 046-06-2 to 042-07-2 --- --- Incl with EU295 0.008 SV 138 None


















Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


















EU 366 Pellet Hopper --- --- 204.4 0.008 SV 180 None

EU 397 Line 6 Cooler Vent Stack --- --- 648.0 0.008 SV 196 None

EU 398 Line 7 Cooler Vent Stack --- --- 616.1 0.008 SV 197 None

N/A N/A - Total facility fugitive sources --- --- 5,650.4 --- N/A None

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

EU 148Limestone Transfer

(formerly Ore Transfer From 020-01-1 to Bin 100-01) --- --- 9.6 --- SV 088 None


(formerly Ore Transfer From 020-01-1 to Bin 100-02) --- --- Incl with EU148 --- SV 088 None




(formerly Ore Transfer From 021-01-1 to 022-01-1) --- --- Incl with EU148 --- SV 088 None




(formerly Ore Transfer From 021-02-1 to 022-02-1) --- --- Incl with EU148 --- SV 088 None



EU 217 Pekay Mixer --- --- 2.4 --- SV 100 None

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


Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


EU 218 Pekay Mixer --- --- Incl with EU217 --- SV 100 None



EU 236 Bentonite Bin --- --- 3.1 --- SV 110 None

EU 237 Bentonite Bin --- --- Incl with EU236 --- SV 110 None

EU 238 Bentonite Bin --- --- Incl with EU236 --- SV 110 None

EU 239 Bentonite Day Bin --- --- 0.3 --- SV 111 None

EU 240 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 None



EU 243 Bentonite Unloading Hopper --- --- 0.1 --- SV 112 None

EU 244 Bentonite Storage Bin --- --- 3.1 --- SV 113 None

EU 245 Bentonite Storage Bin --- --- Incl with EU244 --- SV 113 None


EU 247 Storage Bin --- --- 0.3 --- SV 114 None

EU 248 Storage Bin --- --- Incl with EU247 --- SV 114 None



















EU 297 Bentonite Storage Bin --- --- 3.1 --- SV 139 None



Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack



EU 300 Bentonite Unloading Hopper --- --- Incl with EU297 --- SV 139 None





















EU 367 Coal Unload Hopper --- --- 0.2 --- SV 181 None

EU 368 Coal Hopper Conveyor --- --- Incl with EU367 --- SV 181 None

EU 369 Coal Conv. Feed --- --- Incl with EU367 --- SV 181 None

EU 370 Coal Silo Feed --- --- Incl with EU367 --- SV 181 None

EU 371 Coal Silo Discharge --- --- Incl with EU367 --- SV 181 None

EU 372 Coal Silo Transfer --- --- Incl with EU367 --- SV 181 None

EU 373 Coal Silo --- --- Incl with EU367 --- SV 181 None

EU 374 Coal Conv. Discharge --- --- 0.2 --- SV 182 None

EU 375 Coal Screen --- --- Incl with EU374 --- SV 182 None

EU 376 Coal Reversing Belt --- --- Incl with EU374 --- SV 182 None

EU 377 Day Bin Belt Feed --- --- Incl with EU374 --- SV 182 None

EU 378 Day Bin Belt Discharge --- --- Incl with EU374 --- SV 182 None

EU 379 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10

EU 380 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10


Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


EU 381 Coal Day Bin --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10

EU 382 Coal Day Bin --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10

3.E. Other Combustion Units

EU 001 Utility Plant Heating Boiler #1 193.5 0.4 5.3 --- SV 001

BART Analysis for NOx

De Minimis Modeling for PM10 and SO2













EU 006 Utility Plant Diesel Generator 3.1 0.2 0.2 --- SV 006 None

EU 008 Utility Plant Diesel Generator 8.4 0.6 0.6 --- SV 008 None

EU 009 Utility Plant Diesel Fire Pump 10.9 0.7 0.7 --- SV 009 None

EU 010 Mobile Eqp Shop Heating Boiler #1 6.8 0.0 0.2 --- SV 010 De Minimis Modeling for SO2 + NOx

EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 Incl with EU010 --- SV 011 De Minimis Modeling for SO2 + NOx

EU 012 Mobile Eqp Shop Diesel Generator 2.3 0.2 0.2 --- SV 012 None

EU 028 Coarse Crusher Zinc Furnace 3.3 0.0 0.3 --- SV 019 De Minimis Modeling for SO2, NOx + PM10

EU 032 Coarse Crusher Zinc Furnace 0.5 1.4 0.0 --- SV 020 De Minimis Modeling for SO2, NOx + PM10

EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 Incl with EU032 --- SV 020 De Minimis Modeling for SO2, NOx + PM10

EU 051 Crusher Area Diesel Generator 2.0 0.1 0.1 --- SV 029 None

EU 142 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Modeling for SO2, NOx + PM10

EU 143 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Modeling for SO2, NOx + PM10

EU 215 Concentrator Area Diesel Generator 45.0 3.0 3.1 --- SV 098 None

EU 383 Diesel Generator 15.4 1.0 1.1 --- SV 183 None





Emission


NOx Max. 24-hr

Actual

Emissions (lb/day)

SO2 Max. 24-

hr Actual

Emissions

(lb/day)

PM10 Max. 24-

hr Actual

Emissions

(lb/day)

MACT

PM Emission

Limit*

(g/dscf)

Stack


EU 387 Air Compressor 171.1 11.3 11.8 --- SV 187 De Minimis Modeling for SO2, NOx + PM10

* The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the

regulation.

Table 3-2: De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data

EU # EU Description

SO2 Maximum

24-hr Emission

Rate (lbs/day)

NOx Maximum

24-hr Emission

Rate (lbs/day)

PM2.5

Maximum 24-

hr Emission

Rate (lbs/day)

PM10 Maximum

24-hr Emission

Rate (lbs/day) SV #

Stack Easting

(utm)

Stack

Northing

(utm)

Height of

Opening

from

Ground (ft)

Base

Elevation

of

Ground

(ft)

Stack length,

width, or

Diameter (ft)

Flow

Rate at

exit

(acfm)

Exit

Temp

(°F)

Basis for SO2 24-

hour Actual

Emissions

Basis for NOx 24-

hour Actual

Emissions

Basis for

PM2.5 24-

hour

Actual

Emissions

Basis for PM10 24-

hour Actual

Emissions

EU 379 Coal Pulverizer 0.00 0.00 0.00 0.15 SV 182 NA NA 163.5 1676 2.83 29000.0 70 n/a n/a n/aAP-42 Emission

Factor

EU 380 Coal Pulverizer 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382

EU 381 Coal Day Bin 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382

EU 382 Coal Day Bin 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382

EU 001 Utility Plant Heating Boiler #1 0.41 193.52 0.00 5.25 SV 001 527605.4429 5268166.228 67.25 1682 4.50 17000.0 380AP-42 Emission

Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor


Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor


Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor


Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor


Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor

EU 010 Mobile Eqp Shop Heating Boiler #1 0.01 6.79 0.00 0.18 SV 010 527646.157 5266984.445 58.84 1619 2.50 4100.0 380AP-42 Emission

Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor

EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 0.00 Incl with EU010 SV 011 527650.711 5266985.142 58.84 1619 2.50 4100.0 380 Incl with EU010 Incl with EU010 n/a Incl with EU010

EU 028 Coarse Crusher Zinc Furnace 0.00 3.29 0.00 0.31 SV 019 527252.4492 5267524.117 32 1732 1.67 36700.0 700AP-42 Emission

Factor

AP-42 Emission

Factorn/a

AP-42 Emission

Factor

EU 032 Coarse Crusher Zinc Furnace 1.44 0.48 0.00 0.02 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 700

19 gallons used in

Jan of 2005 * AP-42

Emission Factor

19 gallons used in

Jan of 2005 * AP-42

Emission Factor

n/a

19 gallons used in

Jan of 2005 * AP-42

Emission Factor

EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 0.00 Incl with EU032 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 700 Incl with EU032 Incl with EU032 n/a Incl with EU032

EU 142 Fine Crusher Zinc Furnace 16.72 5.59 0.00 0.25 SV 086 527183.7471 5267919.903 29 1731 1.67 36700.0 700

Assume one full day

of operation: 24 hrs *

operating rate * AP-

42 Emission Factor

Assume one full day

of operation: 24 hrs

* operating rate *

AP-42 Emission

Factor

n/a

Assume one full day


* operating rate *

AP-42 Emission

Facto

EU 143 Fine Crusher Zinc Furnace 16.72 5.59 0.00 0.25 SV 086 527173.7879 5267919.13 29 1731 1.67 36700.0 700

Assume one full day

of operation: 24 hrs *

operating rate * AP-

42 Emission Factor

Assume one full day


* operating rate *

AP-42 Emission

Factor

n/a

Assume one full day


* operating rate *

AP-42 Emission

Facto

EU 387 Air Compressor 11.28 171.12 0.00 11.76 SV 187 NA NA 40 1676 1.00 12000 80 Based on PTE Based on PTE n/a Based on PTE

Table 3-3 De Minimis Visibility Modeling Results

2002 2003 2004 2002 – 2004 Combined

Class I

Area with

Greatest

Impact Model Scenario

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

BWCA De Minimis 0.040 0 0.034 0 0.029 0 0.031 0

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

EU # EU Description

SO2 Maximum

24-hr Emission

Rate (lbs/day)

NOx Maximum

24-hr Emission

Rate (lbs/day)

PM2.5

Maximum 24-hr

Emission Rate

(lbs/day)

PM10 Maximum

24-hr Emission

Rate (lbs/day) SV #

Stack

Easting

(utm)

Stack

Northing

(utm)

Height of

Opening

from

Ground (ft)

Base

Elevation

of

Ground

(ft)

Stack length,

width, or

Diameter (ft)

Flow Rate

at exit

(acfm)

Exit

Temp

(°F)

Basis for SO2 24-

hour Actual

Emissions

Basis for NOx 24-

hour Actual

Emissions

Basis for

PM2.5 24-

hour Actual

Emissions

Basis for PM10 24-

hour Actual

Emissions

Baseline Conditions - Utility Plant Heating Boilers

EU 001 Utility Plant Heating Boiler #1 0.41 194 n/a 5.3 SV 001 527605.4429 5268166.228 67.25 1682 4.5 17,000 380AP-42 Emission

Factor

AP-42 Emission

FactorN/A

AP-42 Emission

Factor


Factor

AP-42 Emission

FactorN/A

AP-42 Emission

Factor


Factor

AP-42 Emission

FactorN/A

AP-42 Emission

Factor


Factor

AP-42 Emission

FactorN/A

AP-42 Emission

Factor


Factor

AP-42 Emission

FactorN/A

AP-42 Emission

Factor

Baseline Conditions - Indurating Furnaces - Natural Gas Burning in Kiln

EU 223 Line 3 3072 19133 n/a 6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130Stack Test

May 2005

Stack Test

June 1997N/A

Stack Test

May 2005

EU 259 Line 4 3192 29520 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack Test

July 2006

Stack Test

April 2004N/A

Stack Test

July 2005

EU 280 Line 5 3192 29520 n/a 2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as Line 4 Same as line 4 N/AStack Test

May 2005

EU 313 Line 6 2520 26232 n/a 1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as Line 7 Same as line 7 N/AStack Test

April 2005


June 2002

Stack Test

June 2002 N/A

Stack Test

April 2005

Baseline Conditions - Indurating Furnaces - Solid Fuel Burning in Kiln


March 1994

Stack Test

April 2004N/A

Stack Test

May 2005

EU 259 Line 4 3192 27360 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack Test

July 2005

Stack Test

April 2004N/A

Stack Test

July 2005

EU 280 Line 5 3192 27360 n/a 2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as line 4 Same as line 4 N/AStack Test

May 2005

EU 313 Line 6 4032 19440 n/a 1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as line 7 Same as line 7 N/AStack Test

April 2005


March 1994

Stack Test

May 2004 N/A

Stack Test

April 2005

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

2002 2003 2004 2002 – 2004 Combined

Modeling

Scenario SO2 NOx

Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

0

Baseline

Indurating Furnaces

burning Natural Gas

Baseline

Indurating Furnaces

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 6.209 505

1

Baseline

Indurating Furnaces

burning

Solid Fuels

Baseline

Indurating Furnaces

burning

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 5.52 490

Scenario Control Technology

Table 5-3 SO2 Control Cost Summary

Control

Technology

Installed Capital Cost

(MM$)

Operating Cost

(MM$/yr)

Annualized

Pollution

Control Cost

($/ton)

Line 3 $27,948,027 $5,322,323 $20,201

Line 4 $39,347,773 $8,448,332 $23,597

Line 5 $39,347,773 $8,448,332 $23,597

Line 6 $36,370,821 $7,939,628 $18,216

Line 7 $37,793,453 $8,123,761 $18,638

Line 3 $19,626,314 $2,816,433 $14,253

Line 4 $26,664,036 $4,123,939 $15,358

Line 5 $26,664,036 $4,123,939 $15,358

Line 6 $25,704,464 $3,953,025 $12,093

Line 7 $25,704,464 $3,953,025 $12,093

Secondary Wet Scrubber


Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates

Scenario Control Technology SO2 NOx

Control

Scenario SV #

Emission

Unit SO2 NOx% Reduction

Max 24-hour

lbs/day % Reduction

Max 24-hour

lbs/day

SV 103 Line 3 30% 2,150 --- 19,128

SV 118 Line 4 --- 3,192 --- 29,520

SV 127 Line 5 --- 3,192 --- 29,520

SV 144 Line 6 --- 2,520 10% 23,609

SV 151 Line 7 --- 2,520 --- 26,232

SV 103 Line 3 30% 2,150 --- 12,168

SV 118 Line 4 --- 3,192 --- 27,360

SV 127 Line 5 --- 3,192 --- 27,360

SV 144 Line 6 --- 4,032 10% 17,496

SV 151 Line 7 --- 4,032 --- 19,440

2 Current Operations

w/ Line 3 Scrubber

Indurating Furnaces Burning

Nat Gas

Current Operation

w/ line 6 Burners

Indurating Furances Burning

Nat Gas


w/ Line 3 Scrubber


Solid Fuel

Current Operation

w/ line 6 Burners


Solid Fuel

Table 5-5 Post-BART SO2 Modeling Scenarios - Visibility Modeling Results

Scenario # SO2 NOx

Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

0 Baseline

Indurating Furnaces

burning Natural Gas

Baseline

Indurating Furnaces

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 6.209 505

1 Baseline

Indurating Furnaces

burning

Solid Fuels

Baseline

Indurating Furnaces

burning

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 5.52 490


w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Current Operation

w/ line 6 Burners

Indurating Furances

Burning Nat Gas

BWCA 5.333 176 7.005 168 5.807 157 6.043 501


w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Current Operation

w/ line 6 Burners

Indurating Furnaces

Burning Solid Fuel

BWCA 4.642 171 6.189 159 5.106 148 5.365 478

Scenario Control Technology 2004

2002 – 2004

Combined2002 2003

Table 5-8 Indurating Furnace NOx Control Cost Summary

Control

Technology

Installed

Capital Cost

(MM$)

Operating

Cost (MM$/yr)

Annualized

Pollution

Control Cost

($/ton)

Incremental

Control Cost

($/ton)

Line 3 $69,222,423 $19,513,772 $18,135 n/a

Line 4 $58,874,795 $28,169,433 $19,433 n/a

Line 5 $58,874,795 $28,169,433 $19,347 n/a

Line 6 $56,748,729 $26,419,264 $18,595 n/a

Line 7 $56,748,729 $26,419,264 $17,129 n/a

Line 3 n/a n/a n/a n/a

Line 4 $5,091,356 $480,588 $5,844 $5,076

Line 5 $6,474,892 $611,184 $5,974 $5,209




Line 4 $1,474,892 $139,219 $768 -$3,673

Line 5 $1,474,892 $139,219 $765 -$3,657


Line 7 $1,200,000 $113,272 $588 n/a

Line 3 $3,616,464 $341,369 $5,076 n/a

Line 4 $5,000,000 $471,965 $5,209 n/a

Line 5 $5,000,000 $471,965 $5,186 n/a



Low-NOx Burners

Ported Kilns


Low-NOx Burners + Ported Kilns



Control

Scenario SV #

Emission


Max 24-hour

lbs/day % Reduction

Max 24-hour

lbs/day

SV 103 Line 3 --- 2,150 5% 18,172

SV 118 Line 4 --- 3,192 5% 28,044

SV 127 Line 5 --- 3,192 5% 28,044

SV 144 Line 6 --- 2,520Ports already

installed23,609

SV 151 Line 7 --- 2,520Ports already

installed26,232

SV 103 Line 3 --- 2,150

No NOx

improvement

on solid fuels

12,168

SV 118 Line 4 --- 3,192

No NOx

improvement

on solid fuels

27,360

SV 127 Line 5 --- 3,192

No NOx

improvement

on solid fuels

27,360

SV 144 Line 6 --- 4,032

No NOx

improvement

on solid fuels

17,496

SV 151 Line 7 --- 4,032

No NOx

improvement

on solid fuels

19,440

4

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Nat Gas

5

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Solid Fuel

6



Control

Scenario SV #

Emission


Max 24-hour

lbs/day % Reduction

Max 24-hour

lbs/day

4SV 103 Line 3 --- 2,150

low-NOx Not

Available19,128

SV 118 Line 4 --- 3,192 10% 26,568

SV 127 Line 5 --- 3,192 10% 26,568

SV 144 Line 6 --- 2,520

low-NOx

Already

Installed

23,609

SV 151 Line 7 --- 2,520 10% 23,609

SV 103 Line 3 --- 2,150low-NOx Not

Available12,168

SV 118 Line 4 --- 3,192 10% 24,624

SV 127 Line 5 --- 3,192 10% 24,624

SV 144 Line 6 --- 4,032

low-NOx

Already

Installed

17,496

SV 151 Line 7 --- 4,032 10% 17,496

SV 103 Line 3 --- 2,150 5% 18,172

SV 118 Line 4 --- 3,192 15% 25,092

SV 127 Line 5 --- 3,192 15% 25,092

SV 144 Line 6 --- 2,520 0% 23,609

SV 151 Line 7 --- 2,520 10% 23,609

SV 103 Line 3 --- 2,150 0% 12,168

SV 118 Line 4 --- 3,192 10% 24,624

SV 127 Line 5 --- 3,192 10% 24,624

SV 144 Line 6 --- 4,032 0% 17,496

SV 151 Line 7 --- 4,032 10% 17,496

6

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Nat Gas

7

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Solid Fuel


w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)


w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)


Scenario # Operating Conditions Operating Conditions

Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

0

Baseline

Indurating Furnaces

burning Natural Gas

Baseline

Indurating Furnaces

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 6.209 505

1

Baseline

Indurating Furnaces

burning

Solid Fuels

Baseline

Indurating Furnaces

burning

Solid Fuels

BWCA 4.780 173 6.377 162 5.260 155 5.520 490

2

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Current Operation

w/ line 6 Burners

Indurating Furances

Burning Nat Gas

BWCA 5.333 176 7.005 168 5.807 157 6.043 501

3

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Current Operation

w/ line 6 Burners

Indurating Furnaces

Burning Solid Fuel

BWCA 4.642 171 6.189 159 5.106 148 5.365 478

4

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Nat Gas

BWCA 5.219 174 6.871 168 5.677 156 5.931 498

5

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Solid Fuel

BWCA 4.642 171 6.189 159 5.106 148 5.365 478

2002 2003 2004

2002 – 2004

Combined



Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

2002 2003 2004

2002 – 2004

Combined

6

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Nat Gas

BWCA 5.088 174 6.713 166 5.542 153 5.758 493

7

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Solid Fuel

BWCA 4.408 165 5.912 153 4.858 142 5.095 460

8

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)

Burning Nat Gas

BWCA 4.970 173 6.574 162 5.417 153 5.641 488

9

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Solid Fuel

BWCA 4.408 165 5.912 153 4.858 142 5.095 460

Table 5-14 Boiler NOx Control Cost Summary

Control Technology

Installed

Capital Cost

(MM$)

Operating

Cost

(MM$/yr)

Annualized

Pollution Control

Cost ($/ton)

Low Temperature Oxidation (LoTOx)

Utility Plant Heater Boiler #1 $1,681,680 $304,052 $23,668









Low NOX Burner / Flue Gas Recirculation





Regenerative Selective Catalytic Reduction (R-SCR)





Low NOX Burner / Overfire Air (OFA)





Low NOX Burner

Utility Plant Heater Boiler #1 $344,269 $47,480 $6,653









Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates

Scenario Control Technology NOx

Control

Scenario SV #

Emission

Unit NOx% Reduction Max 24-hour lbs/day

SV 001 EU 001 --- 194

SV 002 EU 002 --- 720

SV 004 EU 004 --- 231

SV 005 EU 005 --- 226

SV 001 EU 001 50% 97

SV 002 EU 002 50% 360

SV 004 EU 004 50% 115

SV 005 EU 005 50% 113

0

(baseline)

Baseline

Indurating Furnaces burning Natural

Gas

1

Utility Plant Heating Boilers

Low-NOx Burners

Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results

Scenario # SO2 NOx

Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

0

Baseline

Indurating Furnaces

burning Natural Gas

Baseline

Indurating Furnaces

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 6.209 505

10

Baseline

Indurating Furnaces

burning Natural Gas

Utility Plant Heating

Boilers

Low-NOx Burners

BWCA 5.486 177 7.178 168 5.957 158 6.201 503

2002 – 2004

CombinedScenario Control Technology 2002 2003 2004



Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

0

Baseline

Indurating Furnaces

burning Natural Gas

Baseline

Indurating Furnaces

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 6.209 505

1

Baseline

Indurating Furnaces

burning

Solid Fuels

Baseline

Indurating Furnaces

burning

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 5.52 490

2

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Current Operation

w/ line 6 Burners

Indurating Furances

Burning Nat Gas

BWCA 5.333 176 7.005 168 5.807 157 6.043 501

3

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Current Operation

w/ line 6 Burners

Indurating Furnaces

Burning Solid Fuel

BWCA 4.642 171 6.189 159 5.106 148 5.365 478

4

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Nat Gas

BWCA 5.219 174 6.871 168 5.677 156 5.931 498

5

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

Indurating Furances

Burning Solid Fuel

BWCA 4.642 171 6.189 159 5.106 148 5.365 478

2002 2003 2004

2002 – 2004

Combined



Class I Area

with Greatest

Impact

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

Modeled 98th

Percentile

Value

(deciview)

No. of days

exceeding 0.5

deciview

2002 2003 2004

2002 – 2004

Combined

6

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Nat Gas

BWCA 5.088 174 6.713 166 5.542 153 5.758 493

7

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Solid Fuel

BWCA 4.408 165 5.912 153 4.858 142 5.095 460

8

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Nat Gas

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)

Burning Nat Gas

BWCA 4.97 173 6.574 162 5.417 153 5.641 488

9

Current Operations

w/ Line 3 Scrubber

Indurating Furnaces

Burning Solid Fuel

Ported Kilns

(lines 3, 4, 5)

+

Low NOx Burners

(lines 4, 5, 7)

Indurating Furances

Burning Solid Fuel

BWCA 4.408 165 5.912 153 4.858 142 5.095 460

10

Baseline

Indurating Furnaces

burning Natural Gas

Utility Plant Heating

Boilers

Low-NOx Burners

BWCA 5.486 177 7.178 168 5.957 158 6.201 503

US Steel - Minntac 9/6/2006

BART Report - Attachment A: Emission Control Cost Analysis

Table A.1: Furnaces Cost Summary

NOx Control Cost Summary

Control TechnologyControl

Eff %

Controlled

Emissions T/y

Emission

Reduction T/yr

Installed Capital

Cost $

Annualized

Operating Cost $/yr

Pollution Control

Cost $/ton

Incremental

Control Cost

$/ton

Selective Catalytic Reduction with Reheat (SCR)

Line 3 80% 269.0 1076.0 $69,222,423 $19,513,772 $18,135 n/a

Line 4 80% 362.4 1449.6 $58,874,795 $28,169,433 $19,433 n/a

Line 5 80% 364.0 1456.0 $58,874,795 $28,169,433 $19,347 n/a

Line 6 80% 355.2 1420.8 $56,748,729 $26,419,264 $18,595 n/a

Line 7 80% 385.6 1542.4 $56,748,729 $26,419,264 $17,129 n/a

Low NOX Burners + Ported Kilns

Line 3 n/a n/a n/a n/a n/a n/a n/a

Line 4 15% 2908.6 248.5 $5,091,356 $480,588 $5,844 $5,076

Line 5 15% 3359.4 272.6 $6,474,892 $611,184 $5,974 $5,209



Low NOX Burners


Line 4 10% 1630.8 181.2 $1,474,892 $139,219 $768 -$3,673

Line 5 10% 1638.0 182.0 $1,474,892 $139,219 $765 -$3,657


Line 7 10% 1735.2 192.8 $1,200,000 $113,272 $588 n/a

Ported Kilns

Line 3 5% 1277.8 67.3 $3,616,464 $341,369 $5,076 n/a

Line 4 5% 1721.4 90.6 $5,000,000 $471,965 $5,209 n/a

Line 5 5% 1729.0 91.0 $5,000,000 $471,965 $5,186 n/a



SO2 Control Cost Summary

Control TechnologyControl

Eff %

Controlled

Emissions T/y

Emission

Reduction T/yr

Installed Capital

Cost $

Annualized

Operating Cost $/yr

Pollution Control

Cost $/ton

Incremental

Control Cost

$/ton

Line 3 80% 65.9 263.5 $27,948,027 $5,322,323 $20,201 n/a

Line 4 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a

Line 5 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a

Line 6 80% 109.0 435.9 $36,370,821 $7,939,628 $18,216 n/a

Line 7 80% 109.0 435.9 $37,793,453 $8,123,761 $18,638 n/a

Line 3 60% 131.7 197.6 $19,626,314 $2,816,433 $14,253 n/a

Line 4 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a

Line 5 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a

Line 6 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a

Line 7 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a

Secondary Wet Scrubber

(after existing scrubber)


(after existing scrubber)

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

Cost Summary 9/7/2006 Page 1 of 75

US Steel - Minntac


Table A.2 - Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 3 waste gas Study Year 2006

Emission Unit Number EU 223

Stack/Vent Number SV 103

Operating Unit: Line 4 waste gas












Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 61 $/hr Per Chrissy Bartovich e-mail

Maintenance Labor 61 $/hr Per Chrissy Bartovich e-mail

Electricity 0.051 $/kwh 2006

Expected annual average industrial price of

electricity in the West North Central Division

for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage.htm

Natural Gas 9.2575 $/mscf 2005

Energy Information Administration. Average

US Industrial Natural Gas Prices. July '05 to

June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htm

Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail

Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail

Compressed Air 0.32 $/mscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th

Ed 2002, Section 6 Chapter 1

Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%

inflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002


Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch

3 lists $1.30 - $2.15/1,000 gal

Chemicals & Supplies

Lime 91.40 $/ton 91.40 2006 Estimate from Cutler-Magney Company

Oxygen 40.00 $/ton 2006 BOC estimate.

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


Ed 2002, Section 4 Chapter 2, page 2-50

Annual costs for a retrofit SCR system example problem. '00 costs

adjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflation

SCR Catalyst 141.00 $/ft3

Cormetech, Inc.

Other

Sales Tax 6.5% %

Interest Rate 7.00% %

EPA Air Pollution Control Cost Manual

Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.

Operating Information

Annual Op. Hrs 7946 Hours Engineering Estimate

Utilization Rate 93%

Equipment Life 20 yrs Engineering Estimate


Utility Chem$ Data 9/7/2006 Page 2 of 75

Standardized Flow Rate

SV 103 268,515 scfm @ 32º F Calculated.





Temperature

SV 103 130 Deg F BART spreadsheet.





Moisture Content

SV 103 10.5% Assumed value.





Actual Flow Rate

SV 103 322,000 acfm BART spreadsheet.



SV 144 600,000 acfm Same as line 7










Dry Std Flow Rate

SV 103 257,906 dscfm @ 68º F Calculated.





24-hour

Max Emis Projected future actual lb/hr ton/year

Pollutant Lb/Hr emissions (tpy) ppmv ppmv Max 24 hour emissions source Projected future actual emissions source

Nitrous Oxides (NOx)

SV 103 876.9 1,345.0 474 166.1 Based on max stack test plus 10% Based on 2005 AEI plus 10%.





Sulfur Dioxides (SO2)

SV 103 98.6 329.3 38 29.2

Based on max stack test plus 10%, minus

30% to account for new scrubber.

Based on AEI avg 2004/2005 plus 10%., minus 30% to account for new

scrubber.

SV 118 146.3 447.5 27 19.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.






US Steel - Minntac


Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat


Emission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering

Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 scfm @ 32º F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 130 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F

Dry Std Flow Rate 257,906 dscfm @ 68º F

CONTROL EQUIPMENT COSTS

Capital Costs

Direct Capital Costs EPRI Correlation

Purchased Equipment 28,387,757

Purchased Equipment Total SCR Only 30,232,961

SCR + Reheat 30,950,318

Total Capital Investment (TCI) = DC + IC SCR + Reheat 69,222,423

Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 11,235,240

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 8,288,440

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 19,513,772

Emission Control Cost Calculation

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 876.9 1,345.0 80% 269.0 1,076.0 18,135

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

12 Site specific electricity costs

13 Catalyst replacement every 3 years.

14 CUECost Workbook Version 1.0, USEPA Document Page 2


Line3 SCR Line3 SCR 5 of 75

US Steel - Minntac



CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 28,387,757

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,845,204

Freight 5% of control device cost (A) NA

Purchased Equipment Total 30,232,961

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 9% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899

Project Contingeny (C) 15% of (A + B) 4,931,529

Total Plant Cost (D) A + B + C 37,808,389

Allowance for Funds During Construction (E) 0 for SCR 0

Royalty Allowance (F) 0 for SCR 0

Pre Production Costs (G) 2% of (D+E)) 756,168

Inventory Capital Reagent Vol * $/gal 102,618

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 38,667,175

Retrofit Factor (14) 60% of TCI 23,200,305

Sitework and foundations 1,400,000

Structural steel 4,800,000

Total Capital Investment Retrofit Installed 68,067,479

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177

Supervisor 15% 15% of Operator Costs 18,176

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 580,008

Maintenance Materials NA % of Maintenance Labor -

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization 245,543

SCR Catalyst 64.71 Catalyst Replacement 193,359

Ammonia (29% aqua.) 0.12 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization 2,694,872

Total Annual Direct Operating Costs 3,853,135

Indirect Operating Costs

Overhead 60% of total labor and material costs 94,284

Administration (2% total capital costs) 2% of total capital costs (TCI) 773,343

Property tax (1% total capital costs) 1% of total capital costs (TCI) 386,672

Insurance (1% total capital costs) 1% of total capital costs (TCI) 386,672

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,425,089

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,066,059

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,919,195

See Summary page for notes and assumptions



US Steel - Minntac



Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst Estimate amount of catalyst required

Equipment Life 24,000 hours Vol. #1 2708 ft3

Cormetech, Inc.

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

Rep part cost per unit $141 Flow #2 288,163 scfm

Vol #2 4408.7 ft3

Amount Required 4,409 ft3

Catalyst Cost 621,630

Y catalyst life factor 3 Years

Annualized Cost 193,359

Equivalent Duty 1,547 Plant Cap kW A 158,727

Est power platn eff 35% Unc Nox lb/mmBtu B 0.62 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 158,727 Capital Cost $/kW D $150.00 $23,809,086.67 Total SCR Equipment

Uncontrolled Nox t/y 3,840.9 Fixed O&M E $157,139.97

Annual Operating Hrs 7,946 Variable O&M F $394,208.98

Uncontrolled Nox lb/mmBtu 0.625 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 1,547

Electrical Use

Equivalent Duty 1,547 MMBtu/hr kW

NOx Cont Eff 80% Power 651.5

NOx in 0.62 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O

Total 651.5

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

877 lb/hr Neat 404.0 gal/hr

29% solution Volume 14 day inventory 135,729 gal $102,618 Inventory Cost

3024 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.625

Actual 77,372 dscf/MMBtu

Method 19 Factor 10,000 dscf/MMBtu

Adjusted Duty 1,547 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 580,008 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor


Electricity 0.051 $/kwh 651.5 kW-hr 4,814,574 245,543 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 193,359 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 3024 lb/hr 22,345,675 2,694,872 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization

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




US Steel - Minntac


Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs


Purchased Equipment (A) 590,417

Purchased Equipment Total (B) 22% of control device cost (A) 717,356

Installation - Standard Costs 30% of purchased equip cost (B) 215,207

Installation - Site Specific Costs NA

Installation Total 215,207

Total Direct Capital Cost, DC 932,563

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380

Total Capital Investment (TCI) = DC + IC 1,154,944

Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 7,382,105

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472


Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1



Line3 Reheat Line3 Reheat 8 of 75

US Steel - Minntac



CAPITAL COSTS


Purchased Equipment (A) (1) 590,417

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC

Instrumentation 10% of control device cost (A) 59,042

MN Sales Taxes 6.5% of control device cost (A) 38,377

Freight 5% of control device cost (A) 29,521

Purchased Equipment Total (B) 22% 717,356

Installation

Foundations & supports 8% of purchased equip cost (B) 57,389

Handling & erection 14% of purchased equip cost (B) 100,430

Electrical 4% of purchased equip cost (B) 28,694

Piping 2% of purchased equip cost (B) 14,347

Insulation 1% of purchased equip cost (B) 7,174

Painting 1% of purchased equip cost (B) 7,174

Installation Subtotal Standard Expenses 30% 215,207

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NAInstallation Total 215,207


Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 71,736

Construction & field expenses 5% of purchased equip cost (B) 35,868Contractor fees 10% of purchased equip cost (B) 71,736

Start-up 2% of purchased equip cost (B) 14,347

Performance test 1% of purchased equip cost (B) 7,174

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 21,521



Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,154,944

OPERATING COSTS


Operating Labor



Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294


Electricity 0.05 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization 449,620

Natural Gas 9.26 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization 6,837,058







Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 109,019






US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catalyst: Catalyst


CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

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

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

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


Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 322,000 19 0.6 1,193.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 322,000 23 0.6 1,444.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 1193.0

Reagent Use & Other Operating Costs Oxidizers - NA



Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr


Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor


Electricity 0.051 $/kwh 1193.0 kW-hr 8,816,081 449,620 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 1,666 scfm 738,543 6,837,058 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization





US Steel - Minntac



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

Auxiliary Fuel Use Equation 3.19

Twi 130 Deg F - Temperature of waste gas into heat recovery

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

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 564 Deg F - Temperature of waste gas out of heat recovery

Tfo 316 Deg F - Temperature of flue gas into of heat recovery

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

-hwg 0 Btu/lb Heat of combustion waste gas

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

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

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

Qwg 288,163 scfm - Flow of waste gas

Qaf 1,666 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%Cost Calculations 289,828 scfm Flue Gas Cost in 1989 $'s $495,188

Current Cost Using CHE Plant Cost Index $590,417

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



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)



US Steel - Minntac


Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat


Emission Unit Number EU 259 Stack/Vent Number SV 118

Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32º F

Expected Utilization Rate 93% Temperature 115 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm




Capital Costs




SCR + Reheat 25,409,745


Operating Costs







Nitrous Oxides (NOx) 1,353.0 1,812.0 80% 362.4 1,449.6 19,433

Notes & Assumptions

















US Steel - Minntac



CAPITAL COSTS

























OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



Cormetech, Inc.



Vol #2 9131.8 ft3


Catalyst Cost 1,287,579








Annual Operating Hrs 8000 Variable O&M F $624,082.60



Electrical Use

Equivalent Duty 3,484 MMBtu/hr kW

NOx Cont Eff 80% Power 1,409.2





Total 1409.2





4666 lb/hr


lb/MMBtu 80%









Operating Labor



Maintenance











US Steel - Minntac


Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs







Total Direct Capital Cost, DC 1,118,793



Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.3811






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance





Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization





US Steel - Minntac




















Heat Rec % A B








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


(EPA 453/B-96-001)



US Steel - Minntac


Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat










Capital Costs




SCR + Reheat 25,409,745


Operating Costs








Notes & Assumptions

















US Steel - Minntac



CAPITAL COSTS

























OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



Cormetech, Inc.



Vol #2 9131.8 ft3













SCR Capital Cost

Electrical Use

Duty 3,484 MMBtu/hr kW






Total 1409.2





4666 lb/hr


lb/MMBtu 80%









Operating Labor



Maintenance











US Steel - Minntac


Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.3811






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance










US Steel - Minntac




















Heat Rec % A B








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


(EPA 453/B-96-001)



US Steel - Minntac


Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat










Capital Costs




SCR + Reheat 24,289,858


Operating Costs








Notes & Assumptions

















US Steel - Minntac



CAPITAL COSTS

























OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



Cormetech, Inc.



Vol #2 8518.2 ft3













SCR Capital Cost

Electrical Use







Total 1308.9





4146 lb/hr


lb/MMBtu 80%









Operating Labor



Maintenance











US Steel - Minntac


Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.3811






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance










US Steel - Minntac




















Heat Rec % A B








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


(EPA 453/B-96-001)



US Steel - Minntac


Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat










Capital Costs




SCR + Reheat 24,289,858


Operating Costs








Notes & Assumptions

















US Steel - Minntac



CAPITAL COSTS

























OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



Cormetech, Inc.



Vol #2 8518.2 ft3













SCR Capital Cost

Electrical Use







Total 1308.9





4146 lb/hr


lb/MMBtu 80%









Operating Labor



Maintenance











US Steel - Minntac












Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.3811






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance










US Steel - Minntac




















Heat Rec % A B








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


(EPA 453/B-96-001)



US Steel - Minntac


Table A.4.a: NOX Control - Low-NOX Burners



Standardized Flow Rate 556,174 scfm @ 32º F






Size 165 mmbtu/hr


Capital Costs(1)


Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 139,219

Capital Recovery Factor

Interest Rate 7.00%


CRF 0.0944

Capital Recovery Cost 139,219

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Control Eff(3)

Exit Conc. Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,353.0 1,812.0 10% 1630.8 181.2 768

Sulfur Dioxide (SO2) 146.3 447.5 0% NA NA NA

Notes & Assumptions

1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section

Cost is ratioed to Line 4 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million

2 Total annualized cost is equal to the annualized capital cost.

3 Control efficiency based on estimated reduction of line 6 total NOX emissions based on NOX CEMS

US Steel - Minntac


Table A.4.b: NOX Control - Low-NOX Burners









Size 165 mmbtu/hr


Capital Costs(1)


Operating Costs(2)



Interest Rate 7.00%


CRF 0.0944


Actual







Notes & Assumptions


Cost is ratioed to Line 5 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million



US Steel - Minntac


Table A.4.c: NOX Control - Low-NOX Burners









Size 165 mmbtu/hr


Capital Costs(1)


Operating Costs(2)



Interest Rate 7.00%


CRF 0.0944


Actual







Notes & Assumptions




US Steel - Minntac


Table A.5.a: NOX Control - Ported Kilns









Size 165 mmbtu/hr


Capital Costs(1)

Minntac Line 4/5 Budget Estimate = 5,000,000$


Minntac Line 4/5 volumetric flow = 650,000 acfm

Operating Costs(2)

Minntac Line 3 volumetric flow = 378,824 acfm


Use "6/10 Rule" to calculate Line 3 Cost = 3,616,464$


Interest Rate 7.00%


CRF 0.0944


Actual



Controlled Emis Reduction Control Cost


Nitrous Oxides (NOx) 876.9 1,345.0 5% 1277.8 67.3 5,076

Notes & Assumptions

1 Capital costs based on Minntac Line 4/5 budget estimate and scaled to Line 3 stack flow rate.


3 Control efficiency based on report, "NOX Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

US Steel - Minntac


Table A.5.b: NOX Control - Ported Kilns









Size 165 mmbtu/hr


Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000$

Operating Costs(2)



Interest Rate 7.00%


CRF 0.0944


Actual





Nitrous Oxides (NOx) 1,353.0 1,812.0 5% 1721.4 90.6 5,209

Notes & Assumptions

1 Capital costs based on Minntac Line 4/5 budget estimate.



US Steel - Minntac


Table A.5.c: NOX Control - Ported Kilns









Size 165 mmbtu/hr


Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000$

Operating Costs(2)



Interest Rate 7.00%


CRF 0.0944


Actual





Nitrous Oxides (NOx) 1,353.0 1,820.0 5% 1729.0 91.0 5,186

Notes & Assumptions

1 Capital costs based on Minntac Line 4/5 budget estimate.



US Steel - Minntac


Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs


Purchased Equipment (A) 4,994,311

Purchased Equipment Total (B) 22% of control device cost (A) 6,068,088

Installation - Standard Costs 67% of purchased equip cost (B) 4,065,619

Installation - Site Specific Costs 6,200,000

Installation Total 4,065,619


Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810


Operating Costs




Actual


Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost


Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0 - NASulfur Dioxide (SO2) 98.6 329.3 80% 65.9 263.5 20,201

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm



Line3 WWESP 9/7/2006 Page 46 of 75

US Steel - Minntac



CAPITAL COSTS


Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 4,994,311




Purchased Equipment Total (B) 22% 6,068,088

Installation


Handling & erection 50% of purchased equip cost (B) 3,034,044





Installation Subtotal Standard Expenses 67% 4,065,619



Engineering, supervision 20% of purchased equip cost (B) 1,213,618

Construction & field expenses 20% of purchased equip cost (B) 1,213,618

Contractor fees 10% of purchased equip cost (B) 606,809


Performance test 1% of purchased equip cost (B) 60,681Model Studies 2% of purchased equip cost (B) 121,362




Retrofit multiplier3

60% of TCI 8,155,510

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000


Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 27,948,027

OPERATING COSTS


Operating Labor



Maintenance

Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 6,283

Maintenance Materials 1.00 % of Maintenance Labor 49,943



Water 0.08 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 57,108

WW Treat Neutralization 1.69 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 1,205,171

Caustic 305.96 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization 278,556Total Annual Direct Operating Costs 2,023,179









See summary page for notes and assumptions



US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811

Rep part cost per unit

Amount Required 0

Total Rep Parts Cost 0

Installation Labor 0

Total Installed Cost 0

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O kW

Fan Power 322,000 10 582.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 30.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 76,157 147.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 760.9


gpm

Water 5.00 gal/min-kacfm 1610.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 246.40 lb/hr caustic


Utilization Rate: 93.0%



Operating Labor

Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr


Maintenance

Maint Labor 61.00 $/Hr 15.0 hr/wk 660 6,283 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 49,943 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 760.9 kW-hr 5,622,840 286,765 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/mgal 1,610.0 gpm 713,853 57,108 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,610.0 gpm 713,853 1,205,171 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 246.4 lb/hr 910 278,556 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization





US Steel - Minntac


Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs










Operating Costs




Actual




Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NASulfur Dioxide (SO2) 146.3 447.5 80% 89.5 358.0 23,597

Notes & Assumptions






US Steel - Minntac



CAPITAL COSTS








Installation



















60% of TCI 12,430,415






OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use


Fan Power 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46



Plate Area


Total 1,536.0


gpm


lb/hr






Operating Labor



Maintenance



Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 1536.0 kW-hr 11,350,454 578,873 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/mgal 3,250.0 gpm 1,441,007 115,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 365.8 lb/hr 1,351 413,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization





US Steel - Minntac


Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs










Operating Costs




Actual





Notes & Assumptions






US Steel - Minntac



CAPITAL COSTS








Installation



















60% of TCI 12,430,415






OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 1,536.0


gpm


lb/hr






Operating Labor



Maintenance











US Steel - Minntac


Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs










Operating Costs




Actual





Notes & Assumptions






US Steel - Minntac



CAPITAL COSTS








Installation



















60% of TCI 11,314,058






OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 1,397.5


gpm


lb/hr






Operating Labor



Maintenance











US Steel - Minntac


Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator










Capital Costs










Operating Costs




Actual





Notes & Assumptions






US Steel - Minntac



CAPITAL COSTS








Installation



















60% of TCI 11,847,545






OPERATING COSTS


Operating Labor



Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Equipment Life 3

CRF 0.3811


Amount Required 0




Annualized Cost 0

Electrical Use





Plate Area


Total 1,417.8


gpm


lb/hr






Operating Labor



Maintenance











US Steel - Minntac


Table A.7.a: SO2 Control - Wet Scrubber










Capital Costs










Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 570,934



Actual




Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0 - NA

Sulfur Dioxide (SO2) 98.6 329.3 60% 131.7 197.6 14,253

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.


Line3 Wet Scrubber

US Steel - Minntac



CAPITAL COSTS


Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,453,270





Installation




Piping 30% of purchased equip cost (B) 1,258,717







Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 209,786Start-up 1% of purchased equip cost (B) 41,957Performance test 1% of purchased equip cost (B) 41,957

Model Studies NA of purchased equip cost (B) NA





60% of TCI 5,034,868



Site Specific - Other Site Specific 0



OPERATING COSTS


Operating Labor



Maintenance





Water 0.08 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization 10,717

WW Treat Neutralization 1.69 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization 183,186

Lime 91.40 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization 32,037Total Annual Direct Operating Costs 570,934










Line3 Wet Scrubber

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catalyst:


CRF 0.0000



Packing Cost 0 Cost adjusted for freight & sales tax



Annualized Cost 0


Equipment Life 3

CRF 0.3811

Rep part cost per unit 0.00 $ each


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

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


Annualized Cost 0

Electrical Use


Blower, Scrubber 322,000 8.55 0.7 - 460.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 12,236 gpm 1 60 0.7 - 197.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 302 gpm 1 60 0.7 - 4.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other

Total 662.2


Caustic Use 98.56 lb/hr SO2 2.50 lb NaOH/lb SO2 246.40 lb/hr Caustic

Lime Use 98.56 lb/hr SO2 0.96 lb Lime/lb SO2 94.86 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio

Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate2

12,236 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 302 gpm

Evaporation Loss4 = 57.42 gpm




Operating Labor



Maintenance




Electricity 0.051 $/kwh 662.2 kW-hr 4,893,479 249,567 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/kgal 302.1 gpm 133,963 10,717 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 244.7 gpm 108,506 183,186 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization

Lime 91.4 $/ton 94.9 lb/hr 351 32,037 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization



Line3 Wet Scrubber

US Steel - Minntac


Table A.7.b: SO2 Control - Wet Scrubber










Capital Costs

Direct Capital Costs (1)









Operating Costs




Actual




Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NA


Notes & Assumptions






Line4 Wet Scrubber

US Steel - Minntac



CAPITAL COSTS





MN Sales Taxes 7% of control device cost (A) 342,120



Installation


















60% of TCI 7,674,013






OPERATING COSTS


Operating Labor



Maintenance







Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555Total Annual Direct Operating Costs 1,038,186










Line4 Wet Scrubber

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 1336.7






24,700 gpm






Operating Labor



Maintenance










Line4 Wet Scrubber

US Steel - Minntac


Table A.7.c: SO2 Control - Wet Scrubber










Capital Costs










Operating Costs




Actual






Notes & Assumptions






Line5 Wet Scrubber

US Steel - Minntac



CAPITAL COSTS








Installation


















60% of TCI 7,674,013






OPERATING COSTS


Operating Labor



Maintenance







Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555Total Annual Direct Operating Costs 1,038,186










Line5 Wet Scrubber

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 1336.7






24,700 gpm






Operating Labor



Maintenance










Line5 Wet Scrubber

US Steel - Minntac


Table A.7.d: SO2 Control - Wet Scrubber










Capital Costs










Operating Costs




Actual






Notes & Assumptions






Line6 Wet Scrubber

US Steel - Minntac



CAPITAL COSTS








Installation


















60% of TCI 7,314,174






OPERATING COSTS


Operating Labor



Maintenance

















Line6 Wet Scrubber

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 1233.9






22,800 gpm






Operating Labor



Maintenance










Line6 Wet Scrubber

US Steel - Minntac


Table A.7.e: SO2 Control - Wet Scrubber










Capital Costs










Operating Costs




Actual






Notes & Assumptions






Line7 Wet Scrubber

US Steel - Minntac



CAPITAL COSTS








Installation


















60% of TCI 7,314,174






OPERATING COSTS


Operating Labor



Maintenance

















Line7 Wet Scrubber

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.0000






Annualized Cost 0


Equipment Life 3

CRF 0.3811






Annualized Cost 0

Electrical Use





Other

Total 1233.9






22,800 gpm






Operating Labor



Maintenance










Line7 Wet Scrubber

US Steel - Minntac


Table A.8: Utility Plant Heater Boilers Cost Summary

NOx Control Cost Summary

Control TechnologyControl Eff

%

Controlled

Emissions

T/y

Emission

Reduction

T/yr

Installed

Capital Cost $

Annualized

Operating

Cost $/yr

Pollution

Control

Cost $/ton

Low Temperature Oxidation (LoTOx)

Utility Plant Heater Boiler #1 90% 1.43 12.85 $1,681,680 $304,052 $23,668









Low NOX Burner / Flue Gas Recirculation





Regenerative Selective Catalytic Reduction (R-SCR)





Low NOX Burner / Overfire Air (OFA)





Low NOX Burner

Utility Plant Heater Boiler #1 50% 7.14 7.14 $344,269 $47,480 $6,653









P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART

Cost Summary Cost Summary 1 of 106

US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.9: Summary of Utility, Chemical and Supply Costs

Operating Unit: Utility Plant Heater Boiler #1 Study Year 2006



Operating Unit: Utility Plant Heater Boiler #2












Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 61.00 $/hr Per Chrissy Bartovich e-mail

Maintenance Labor 61.00 $/hr Per Chrissy Bartovich e-mail

Electricity 0.051 $/kwh 2006

Expected annual average industrial price of

electricity in the West North Central Division

for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage.htm

Natural Gas 9.2575 $/mscf 2005

Energy Information Administration. Average

US Industrial Natural Gas Prices. July '05 to

June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htm

Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail

Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail

Ch 1 Carbon Adsrobers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and

3% inflation

Compressed Air 0.32 $/kscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th Ed

2002, Section 6 Chapter 1

Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%

inflation

Wastewater Disposal Bio-Treat 4.28 $/kgal 3.80 2002


2002, Section 5.2 Chapter 1

Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost

adjusted for 3% inflation

Hazardous Waste Disposal 281.38 $/ton 250.00 2002


2002, Section 2 Chapter 2.5.5.5

Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%

inflation

Waste Transport 0.56 $/ton-mi 0.50 2002


2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation

Chemicals & Supplies

Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery

Oxygen 40.00 $/ton BOC

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


2002, Section 5 Chapter 2, page 2-50

Annual costs for a retrofit SCR system example problem. '00 costs

adjusted for 3% inflation.

Catayst & Replacement Parts


Cormetech, Inc.

Other

Sales Tax 6.5 %

Interest Rate 7.0% %

Please note, for units of measure, k = 1,000 units, MM = 1,000,000 units e.g. kgal = 1,000 gal

Operating Information

Annual Op. Hrs

Utility Plant Heater Boiler #1 3,156 Hours

Average actual operating hours based on 2004

and 2005 emission inventories





Utilization Rate

Utility Plant Heater Boiler #1 28%

Average actual utilization rate based on 2004

and 2005 emission inventories





Equipment Life 20 yrs Engineering Estimate

Desgin Capacity

Utility Plant Heater Boiler #1 104 MMBtu/hr






Utility Plant Heater Boiler #1 11,005 scfm @ 32º F





Temperature

Utility Plant Heater Boiler #1 380 Deg F





Moisture Content

Utility Plant Heater Boiler #1 13.3%





Actual Flow Rate

Utility Plant Heater Boiler #1 17,000 acfm











Dry Std Flow Rate

Utility Plant Heater Boiler #1 10,240 dscfm @ 68º F





Design Basis Baseline Emis. Baseline Emis. Max Emis. (Model) Max Emis.

Pollutant T/yr lb/MMBtu lb/hr lb/mmbtu

Nitrous Oxides (NOx)

Utility Plant Heater Boiler #1 14.3 0.03 29.2 0.28





Max emissions based on limited potential

emissions as reported in the BART

spreadsheet. Baseline emissions are based

on 2005 emission inventory.


Utility Chem$ Data Utility Chem$ Data 2 of 106

US Steel - Minntac


Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)



Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F

Expected Utiliztion Rate 28% Temperature 380 Deg F






Capital Costs








Operating Costs



Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052


Max Emis Annual Control EffControlled Emis Reduction Control Cost


Nitrous Oxides (NOx) 29.2 14.3 90% 1.4 12.8 23,668

Notes & Assumptions

1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter.

Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)

2 Handling and erection of ozone generators included in estimate from PCI Wedeco

3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project.

4 Oxygen plant site prep costs divided between all 5 lines

5 In order for LoTOx to work, a scrubber needs to be installed to capture NOX that has been converted to HNO3 and N2O5. This analysis

does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs;

however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.


#1 LoTOx #1 LoTOx 3 of 106

US Steel - Minntac



CAPITAL COSTS


Purchased Equipment (A)(1)

Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 768,944

Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894




Installation


Handling & erection(2)

0% of purchased equip cost (B) 0









Construction & field expenses 10% of purchased equip cost (B) 93,427









OPERATING COSTS


Operating Labor



Maintenance





Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502

Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367

Total Annual Direct Operating Costs 55,305











US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use

Flow acfm ∆∆∆∆ P in H2O Efficiency Hp kW

Blower, Scrubber 17,000 No extra load on blower

Flow Liquid SPGR ∆∆∆∆ P ft H2O Efficiency Hp kW

Circ Pump 126 gpm No extra load on circulation pump

H2O WW Disch 2 gpm No extra load on discharge pump

kW-hr

LoTOx Electric Use 4 kW/lb O3 189 per estimate from PCI Wedeco

Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2

Total 189


Ozone Needed 1.62 lb O3/lb NOx 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC

Oxygen Needed 10% wt O2 to O3 conversion 473.4 lb/hr O2 5,311 scfh O2

Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco

Circulating Water Rate 126.3 gpm

Water Makeup Rate 5.8 gpm

WW Discharge (blowdown) 2.2 gpm

Nitrate loading (as NaNO3) in scrubber water 49 lb/hr NaNO3





Operating Labor



Maintenance




Electricity 0.051 $/kwh 189.4 kW-hr 167,342 8,534 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization

Cooling Water 0.08 $/mgal 118.4 gpm 6,275 502 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization

Oxygen 40.00 $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization





US Steel - Minntac


Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)










Capital Costs








Operating Costs








Notes & Assumptions











US Steel - Minntac



CAPITAL COSTS








Installation









Installation Total













OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use






kW-hr



Total 189













Operating Labor



Maintenance











US Steel - Minntac


Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)










Capital Costs








Operating Costs








Notes & Assumptions











US Steel - Minntac



CAPITAL COSTS








Installation





















OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use






kW-hr



Total 278













Operating Labor



Maintenance











US Steel - Minntac


Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)










Capital Costs








Operating Costs








Notes & Assumptions











US Steel - Minntac



CAPITAL COSTS








Installation





















OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use






kW-hr



Total 278













Operating Labor



Maintenance











US Steel - Minntac


Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat



Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391






Capital Costs Year

Direct Capital Costs 2000 2,173,722

Purchased Equipment (A) 2005 2,585,117

Purchased Equipment Total (B) SCR + Reheat 2,907,528


Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165





Notes & Assumptions











#1 SCR #1 SCR 15 of 106

US Steel - Minntac



CAPITAL COSTS





ND Sales Taxes 0.0% of control device cost (A) NA


Purchased Equipment Total (A) 0% 2,585,117





Site Specific-Other 31% Replacement Power, two weeks 796,012

Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 507,169







Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance





Cat. Replacement 346.28 Catalyst Replacement 2,705

Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739



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






#1 SCR #1 SCR 16 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst

Equipment Life 24,000 hours

FCW 0.0975


# of Layers 10

Replacement Factor 8Layers replaced per year = 3.3





SCR Capital Cost per EPRI Method 2,173,722

Duty 104 MMBtu/hr Catalyst Area 50 ft2

308 f (h SCR)

Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH3)

NOx Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst)

Temperature 380 Deg F h SCR 81 ft f (h SCR)

Catalyst Volume 1,509 ft3

New/Retrofit R N or R

Electrical Use

Duty 104 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 79.1

NOx in 0.28 lb/MMBtun catalyst layers 11 layers



Total 79.1





101 lb/hr





Operating Labor

Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance





Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement

Ammonia (29% aqua.) 0.12059928 $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization

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



#1 SCR #1 SCR 17 of 106

US Steel - Minntac


Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)




Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390






Capital Costs









Total Capital Investment (TCI) = DC + IC 519,083

Operating Costs




Notes & Assumptions




#1 Reheat for SCR #1 Reheat for SCR 18 of 106

US Steel - Minntac



CAPITAL COSTS





ND Sales Taxes 6.5% of control device cost (A) 17,248



Installation






















Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083

OPERATING COSTS


Operating Labor



Maintenance





Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681













US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use


Blower, Thermal 17,000 19 0.6 63.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 17,000 23 0.6 76.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1






Operating Labor



Maintenance





Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization





US Steel - Minntac

















Qaf 16 scfm - Flow of auxiliary fuel



Heat Rec % A B








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

NOx Due to Duct Burner

939 scf/hr Flow of natural gas required

1.0 mmbtu/hr Heat required, assuming 1050 btu/scf

0.08 lb/mmbtu NOx emission factor for natural gas combustion

0.1 lb/hr Additional NOx from duct burners

0.345 tpy Additional NOx from duct burners


(EPA 453/B-96-001)



US Steel - Minntac


Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat










Capital Costs Year





Operating Costs








Notes & Assumptions











#2 SCR #2 SCR 22 of 106

US Steel - Minntac



CAPITAL COSTS






















OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance


















#2 SCR #2 SCR 23 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


FCW 0.0975


# of Layers 10








308 f (h SCR)

Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH3)








Electrical Use






Total 79.1





101 lb/hr





Operating Labor



Maintenance










#2 SCR #2 SCR 24 of 106

US Steel - Minntac


Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance





Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization





US Steel - Minntac




















Heat Rec % A B








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


939 scf/hr Flow of natural gas required






(EPA 453/B-96-001)



US Steel - Minntac


Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat










Capital Costs Year





Operating Costs








Notes & Assumptions











#4 SCR #4 SCR 29 of 106

US Steel - Minntac



CAPITAL COSTS






















OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance


















#4 SCR #4 SCR 30 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


FCW 0.0975


# of Layers 10








308 f (h SCR)

Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3)








Electrical Use






Total 116.4





148 lb/hr





Operating Labor



Maintenance










#4 SCR #4 SCR 31 of 106

US Steel - Minntac


Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance





Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization





US Steel - Minntac




















Heat Rec % A B








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


1,408 scf/hr Flow of natural gas required






(EPA 453/B-96-001)



US Steel - Minntac


Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat










Capital Costs Year





Operating Costs








Notes & Assumptions











#5 SCR #5 SCR 36 of 106

US Steel - Minntac



CAPITAL COSTS






















OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance


















#5 SCR #5 SCR 37 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


FCW 0.0975


# of Layers 10








308 f (h SCR)

Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3)








Electrical Use






Total 116.4





148 lb/hr





Operating Labor



Maintenance










#5 SCR #5 SCR 38 of 106

US Steel - Minntac


Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)










Capital Costs










Operating Costs




Notes & Assumptions





US Steel - Minntac



CAPITAL COSTS








Installation























OPERATING COSTS


Operating Labor



Maintenance


















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



CRF 0.5531






Annualized Cost 0


Equipment Life 3

CRF 0.3811





Annualized Cost 0

Electrical Use









Operating Labor



Maintenance





Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization





US Steel - Minntac




















Heat Rec % A B








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








(EPA 453/B-96-001)



US Steel - Minntac


Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation



Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390






Capital Costs





Installation - Site Specific Costs n/a

Installation Total n/a




Operating Costs

Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840




Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem


Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner.


Thermal Oxidizer factor used because it has the lowest multipiler for installation cost



#1 LNB FGR 1/8/2008 Page 43 of 106

US Steel - Minntac



CAPITAL COSTS



Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC





Installation








Site Preparation, as required Site Specific n/a

Buildings, as required Site Specific n/a

Site Specific - Other Site Specific n/a

Total Site Specific Costs n/aInstallation Total n/a


Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 53,735








Retrofit Factor(3)

60% of TCI 519,082

TCI Retrofit Installed 1,384,220

OPERATING COSTS


Operating Labor

Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241

Supervisor 15% 15% of Operator Costs 36

Maintenance

Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241

Maintenance Materials 100% of maintenance labor costs 241


Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81

Total Annual Direct Operating Costs 840


Overhead 60% of total labor and material costs 455









#1 LNB FGR 1/8/2008 Page 44 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 5% of flue gas is recirculated)





Operating Labor


Supervisor 15% of Op. NA 36 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr



Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization




#1 LNB FGR 1/8/2008 Page 45 of 106

US Steel - Minntac











Capital Costs










Operating Costs







Notes & Assumptions






#2 LNB FGR 1/8/2008 Page 46 of 106

US Steel - Minntac



CAPITAL COSTS








Installation





















Retrofit Factor(3)

60% of TCI 519,082


OPERATING COSTS


Operating Labor



Maintenance
















#2 LNB FGR 1/8/2008 Page 47 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1






Operating Labor



Maintenance








#2 LNB FGR 1/8/2008 Page 48 of 106

US Steel - Minntac











Capital Costs










Operating Costs







Notes & Assumptions






#4 LNB FGR 1/8/2008 Page 49 of 106

US Steel - Minntac



CAPITAL COSTS








Installation





















Retrofit Factor(3)

60% of TCI 654,382


OPERATING COSTS


Operating Labor



Maintenance
















#4 LNB FGR 1/8/2008 Page 50 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944


Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1






Operating Labor



Maintenance








#4 LNB FGR 1/8/2008 Page 51 of 106

US Steel - Minntac











Capital Costs










Operating Costs







Notes & Assumptions






#5 LNB FGR 1/8/2008 Page 52 of 106

US Steel - Minntac



CAPITAL COSTS








Installation





















Retrofit Factor(3)

60% of TCI 654,382


OPERATING COSTS


Operating Labor



Maintenance
















#5 LNB FGR 1/8/2008 Page 53 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944








Operating Labor



Maintenance








#5 LNB FGR 1/8/2008 Page 54 of 106

US Steel - Minntac


Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction










Capital Costs





Operating Costs





Max Emis Annual Control Eff Controlled Emis Reduction Control Cost



Notes & Assumptions

1


3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective.

Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and

natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART#1 R-SCR Page 55 of 106

US Steel - Minntac



CAPITAL COSTS2


Purchased Equipment1 (A)



MN Sales Taxes 6.5% of control device cost (A) NA


Purchased Equipment Total (A) 1,201,308


General Facilities 5% of purchased equip cost (A) 60,065

Engineerin & Home Office 10% of purchased equip cost (A) 120,131

Process Contingency 5% of purchased equip cost (A) 60,065







Inventory Capital Reagent Vol * $/gal 0

Intial Catalyst and Chemicals 0 for SCR 0


OPERATING COSTS2


Operating Labor

Operator NA -

Supervisor NA -

Maintenance





Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933

Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25


SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204












US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst

Equipment Life 3 Years

CRF 0.3811

Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 87,139


Electrical Use

Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 51.5


Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5

Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators






Operating Labor

Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr


Maintenance





Natural Gas 9.26 $/mscf 1703.1 scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization

Comp Air 0.32 $/kscf 4.8 scfm 80 25 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization



0 ft3

0 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization




US Steel - Minntac



Duct Burner Fuel Usage Estimate

Auxiliary Fuel Use Equation 3.19 Input Numbers

Twi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers








Cp wg 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist air)












(EPA 453/B-96-001)


US Steel - Minntac


Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction










Capital Costs





Operating Costs








Notes & Assumptions

1






US Steel - Minntac



CAPITAL COSTS2





















OPERATING COSTS2


Operating Labor

Operator NA -

Supervisor NA -

Maintenance




















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


CRF 0.3811


Total cost 87,139


Electrical Use


Total 51.5










Operating Labor



Maintenance









0 ft3





US Steel - Minntac

























(EPA 453/B-96-001)


US Steel - Minntac


Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction










Capital Costs





Operating Costs








Notes & Assumptions

1






US Steel - Minntac



CAPITAL COSTS2





















OPERATING COSTS2


Operating Labor

Operator NA -

Supervisor NA -

Maintenance




















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


CRF 0.3811


Total cost 130,708


Electrical Use


Total 77.2










Operating Labor



Maintenance









0 ft3





US Steel - Minntac

























(EPA 453/B-96-001)


US Steel - Minntac


Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction










Capital Costs





Operating Costs








Notes & Assumptions

1






US Steel - Minntac



CAPITAL COSTS2





















OPERATING COSTS2


Operating Labor

Operator NA -

Supervisor NA -

Maintenance




















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Replacement Catayst


CRF 0.3811


Total cost 130,708


Electrical Use


Total 77.2










Operating Labor



Maintenance









0 ft3





US Steel - Minntac

























(EPA 453/B-96-001)


US Steel - Minntac











Capital Costs






Installation Total n/a Total Direct Capital Cost, DC 570,844



Operating Costs







Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application


Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost



#1 LNB OFA 1/8/2008 Page 71 of 106

US Steel - Minntac



CAPITAL COSTS








Installation










Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a






Performance test 1% of purchased equip cost (B) 4,391Model Studies 0% of purchased equip cost (B) 0




Retrofit Factor(3)

60% of TCI 424,181


OPERATING COSTSDirect Annual Operating Costs, DC

Operating Labor



Maintenance




Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326












#1 LNB OFA 1/8/2008 Page 72 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944



(assume 20% of flue gas used for OFA)




Operating Labor



Maintenance




Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr




#1 LNB OFA 1/8/2008 Page 73 of 106

US Steel - Minntac


Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation









Capital Costs









Operating Costs







Notes & Assumptions






#2 LNB OFA 1/8/2008 Page 74 of 106

US Steel - Minntac



CAPITAL COSTS








Installation




















Retrofit Factor(3)

60% of TCI 424,181



Operating Labor



Maintenance
















#2 LNB OFA 1/8/2008 Page 75 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944







Operating Labor



Maintenance








#2 LNB OFA 1/8/2008 Page 76 of 106

US Steel - Minntac


Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation









Capital Costs









Operating Costs







Notes & Assumptions






#4 LNB OFA 1/8/2008 Page 77 of 106

US Steel - Minntac



CAPITAL COSTS








Installation




















Retrofit Factor(3)

60% of TCI 534,744



Operating Labor



Maintenance
















#4 LNB OFA 1/8/2008 Page 78 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944







Operating Labor



Maintenance








#4 LNB OFA 1/8/2008 Page 79 of 106

US Steel - Minntac


Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation









Capital Costs









Operating Costs







Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application.





#5 LNB OFA 1/8/2008 Page 80 of 106

US Steel - Minntac



CAPITAL COSTS








Installation




















Retrofit Factor(3)

60% of TCI 534,744



Operating Labor



Maintenance
















#5 LNB OFA 1/8/2008 Page 81 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944







Operating Labor



Maintenance








#5 LNB OFA 1/8/2008 Page 82 of 106

US Steel - Minntac











Capital Costs









Operating Costs







Notes & Assumptions

1 Equipment cost based on estimate from John Zink




#1 LNB 1/8/2008 Page 83 of 106

US Steel - Minntac



CAPITAL COSTS








Installation

















Model Studies 0% of purchased equip cost (B) 0





Operating Labor



Maintenance















#1 LNB 1/8/2008 Page 84 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944




Operating Labor



MaintenanceMaint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr






#1 LNB 1/8/2008 Page 85 of 106

US Steel - Minntac











Capital Costs









Operating Costs







Notes & Assumptions





#2 LNB 1/8/2008 Page 86 of 106

US Steel - Minntac



CAPITAL COSTS








Installation






















Operating Labor



Maintenance















#2 LNB 1/8/2008 Page 87 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944




Operating Labor









#2 LNB 1/8/2008 Page 88 of 106

US Steel - Minntac











Capital Costs









Operating Costs







Notes & Assumptions





#4 LNB 1/8/2008 Page 89 of 106

US Steel - Minntac



CAPITAL COSTS








Installation






















Operating Labor



Maintenance















#4 LNB 1/8/2008 Page 90 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944




Operating Labor









#4 LNB 1/8/2008 Page 91 of 106

US Steel - Minntac











Capital Costs









Operating Costs







Notes & Assumptions





#5 LNB 1/8/2008 Page 92 of 106

US Steel - Minntac



CAPITAL COSTS








Installation






















Operating Labor



Maintenance















#5 LNB 1/8/2008 Page 93 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944




Operating Labor









#5 LNB 1/8/2008 Page 94 of 106

US Steel - Minntac


Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)



Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Plant Cost Index







Capital Costs






Operating Costs








Notes & Assumptions

1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19

Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21


#1 SNCR #1 SNCR 95 of 106

US Steel - Minntac



CAPITAL COSTS



Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260




Purchased Equipment Total (A) 769,260

Indirect Installation [1]





Project Contingeny ( C) 15% of (A + B) 138,467

Total Plant Cost D A + B + C 1,061,579

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0



Intial Catalyst and Chemicals 0 for SNCR 0


Retrofit Installation Factor 30% 325,322

Total Capital Investment, Retrofit Installed 1,409,728

OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance




Electricity 0.05 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization 89

Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1

Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198













US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use

NOx in 0.28 lb/MMBtu kW

NSR 1.37 equation 1.14

Power 2.0

Total 2.0

Reagent Use & Other Operating Costs Urea Use

11.73 lb/hr Neat equation 1.15

50% solution 71.0 lb/ft3 Density 50% Solution

23.46 lb/hr 2.5 gal/hr

831 gal $1,596 Inventory Cost

Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr





Operating Labor

Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yrSupervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment



Electricity 0.051 $/kwh 2.0 kW-hr 1,753 89 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization

Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization

Urea 405 $/ton 0.0117 ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization





US Steel - Minntac


Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)










Capital Costs






Operating Costs








Notes & Assumptions









US Steel - Minntac



CAPITAL COSTS























OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance



















US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use



Power 2.0

Total 2.0





831 gal $1,596 Inventory Cost






Operating Labor


Maintenance










#2 SNCR #2 SNCR 100 of 106

US Steel - Minntac


Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)


Emission Unit Number EU 004 Stack/Vent Number 0 Chemical Engineering








Capital Costs






Operating Costs








Notes & Assumptions








#4 SNCR #4 SNCR 101 of 106

US Steel - Minntac



CAPITAL COSTS























OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance


















#4 SNCR #4 SNCR 102 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use



Power 2.9

Total 2.9





1,220 gal $2,345 Inventory Cost






Operating Labor


Maintenance










#4 SNCR #4 SNCR 103 of 106

US Steel - Minntac


Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)










Capital Costs






Operating Costs








Notes & Assumptions








#5 SNCR #5 SNCR 104 of 106

US Steel - Minntac



CAPITAL COSTS























OPERATING COSTS


Operating Labor

Operator NA -

Supervisor NA -

Maintenance


















#5 SNCR #5 SNCR 105 of 106

US Steel - Minntac





Interest Rate 7.00%


CRF 0.0944

Electrical Use



Power 2.9

Total 2.9





1,220 gal $2,345 Inventory Cost






Operating Labor


Maintenance










#5 SNCR #5 SNCR 106 of 106

Memorandum

To: Margaret McCourtney

From: Andrew Skoglund

Subject: Revisions per your comments

Date: May 16, 2006

Project: Taconite Industry BART Clients

c: Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps.

Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are

set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files

and a figure depicting the proposed modeling domain are also included, as requested.

The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling

protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel

Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with

observations for review. The values noted are representative of those that were used after receiving

comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005,

with FLM response on June 14, 2005. FLMs approved of the submitted values.

The comments section regarding receptors has been revised to indicate that we will be using a subset of the

original MPCA receptor group, using only BWCA and Voyageurs receptors.

Thank you,

Andrew J. Skoglund

Barr Engineering Co.

(952) 832 - 2685

[email protected]

Barr Engineering Company Appendix B

4700 West 77th Street • Minneapolis, MN 55435-4803

Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO

!;N

Barr F

ooter

: Date

: 6/3/

2004

4:10

:56 PM

File

: C:\T

emp\T

est.m

xd U

ser:

bal

0 100Kilometers

MODELING DOMAINTaconite BART ModelingTaconite Industry Group

Minnesota

0 100Miles

LegendModeling Domain

Class I AreaBWCAVoyageurs

TERREL

Variable Description Value Default Comments

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

XREFKM Reference point coordinates for grid 168 n/a

YREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CTGPROC


XREFKM Reference point coordinates for grid 168 n/a

YREFKM Reference point coordinates for grid 720 n/a



CALMET


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



XORIGKM Reference point coordinates for grid 168 n/a

YORIGKM Reference point coordinates for grid 720 n/a

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

NSSTA Number of Surface Stations 74 n/a 74 surface weather stations

NPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations

RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with Observations

RMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observations

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

R2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observations

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

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

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

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

JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater data

JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater data

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

Input Group 0b

Input Group 2

Input Group 2

Input Group 2

Input Group 4

Input Group 5

Input Group 6

CALPUFF


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

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

XORIGKM Reference point coordinates for met grid 168 n/a

YORIGKM Reference point coordinates for met grid 720 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 40 n/a

JECOMP Y index of UR corner 30 n/a

MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, and MI observation stations

NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyageurs from MPCA protocol

Input Group 11

Input Group 17

Input Group 4

Appendix C

1. CALPUFF Modeling System

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

from sources. This model was used in accordance with the guidelines found in the Best Available

Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of

Minnesota, Final1, with the modifications found in Appendix B.

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

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

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

described below:

• CALMET is a meteorological model that develops hourly wind and temperature fields on a three-

dimensional gridded modeling domain. Associated two-dimensional fields such as mixing

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

file produced by CALMET.

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

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

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

generated by CALMET.

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

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

measures of visibility impairment at selected averaging times and locations.

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

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

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

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

Subject to BART in the State of Minnesota.

CALMET

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

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

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

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

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

required by CALMET were obtained from the MPCA.

CALPUFF

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

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

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

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

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

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

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

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

values provided by MPCA.

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

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

CALPOST

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

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

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

modeling protocol.

2. Visibility Impacts Analysis

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

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

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

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

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

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

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

Assessing Visibility Impairment

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

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

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

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

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

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

on which a source exceeds an impairment threshold.

As defined by federal guidance4 a source "contributes to visibility impairment” if the 98th percentile of

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

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

Pollution Control Agency identified this facility as having BART eligible source(s)5 that could cause or

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

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

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

on which a source exceeds 0.5 dV.

2 40 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-

to-Bart in the State of Minnesota. 4 40 CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-

to-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, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98th percentile modeled impact for these sources was 0.04 dV, meeting the required de

minimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.

Modeled 98th Percentile Impact

2002 2003 2004 2002-2004 Maximum

BWCA 0.040 0.034 0.029 0.031 0.040

Voyageurs 0.019 0.020 0.016 0.018 0.020

Predicting 24-Hour Maximum Emission Rates

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for pre-

BART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should

reflect a maximum 24-hour average basis.

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

respectively.

Modeled Results

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

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

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

included in Table 6-3.

Appendix C

1. CALPUFF Modeling System

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

from sources. This model was used in accordance with the guidelines found in the Best Available

Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of

Minnesota, Final1, with the modifications found in Appendix B.

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

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

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

described below:

• CALMET is a meteorological model that develops hourly wind and temperature fields on a three-

dimensional gridded modeling domain. Associated two-dimensional fields such as mixing

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

file produced by CALMET.

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

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

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

generated by CALMET.

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

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

measures of visibility impairment at selected averaging times and locations.

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

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

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

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

Subject to BART in the State of Minnesota.

CALMET

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

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

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

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

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

required by CALMET were obtained from the MPCA.

CALPUFF

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

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

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

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

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

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

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

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

values provided by MPCA.

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

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

CALPOST

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

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

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

modeling protocol.

2. Visibility Impacts Analysis

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

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

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

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

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

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

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

Assessing Visibility Impairment

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

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

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

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

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

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

on which a source exceeds an impairment threshold.

As defined by federal guidance4 a source "contributes to visibility impairment” if the 98th percentile of

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

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

Pollution Control Agency identified this facility as having BART eligible source(s)5 that could cause or

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

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

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

on which a source exceeds 0.5 dV.

2 40 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-

to-Bart in the State of Minnesota. 4 40 CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-

to-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, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98th percentile modeled impact for these sources was 0.04 dV, meeting the required de

minimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.

Modeled 98th Percentile Impact

2002 2003 2004 2002-2004 Maximum

BWCA 0.040 0.034 0.029 0.031 0.040

Voyageurs 0.019 0.020 0.016 0.018 0.020

Predicting 24-Hour Maximum Emission Rates

Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for pre-

BART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should

reflect a maximum 24-hour average basis.

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

respectively.

Modeled Results

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

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

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

included in Table 6-3.

� �N

Barr Footer: Date: 7/5/2006 1:27:58 PM File: I:\projects\23\00\Minntac.mxd User: ams

1000

100200

MetersM

inntac Aerial P

hoto

1000

100200

Meters

Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable ReviewRevised: August 23, 2006

Step 1 Step 2 Reference(s)

This table is part of the Taconite BART Report and should not be

distributed without the full text of the report so that the information is

not taken out of context.

Refe

ren

ce N

o.1

NOx Pollution Control

Technology Is t

his

a g

en

era

lly

avail

ab

le c

on

tro

l

tech

no

log

y?

Is t

he c

on

tro

l te

ch

no

log

y

avail

ab

le t

o i

nd

ura

tin

g

furn

aces?

Is t

he c

on

tro

l te

ch

no

log

y

ap

pli

cab

le t

o t

his

sp

ecif

ic

so

urc

e?

Is i

t te

ch

nic

all

y f

easib

le

for

this

so

urc

e?

Approximate

Control

Efficiency MP

CA

Taco

nit

e B

AR

T

Rep

ort

MP

CA

BA

RT

Gu

idan

ce

(Att

ach

men

t 2)

Oth

er2

Comments Basic Principle

Combustion Controls

1 Overfire Air (OFA) Y N --- --- --- xNOx formation front is not stationary in

an indurating furnace

Combustion air is separated into primary and secondary flow sections to

achieve complete burnout and to encourage the formation of N2 rather

than NOx

2External Flue Gas

Recirculation (EFGR)Y Y N --- --- x x

Mixes flue gas with combustion air which reduces oxygen content and

therefore reduces flame temperature

3 Low-NOx Burners Y Y

Y

(preheat

burners)

Y

(preheat

burners)

10-20% x x x

Higher control efficiency at the burner,

but the listed control efficiency is for

the entire furnace.

Burners are designed to reduce NOx formation through restriction of

oxygen, flame temperature, and/or residence time

4Induced Flue Gas

Recirculation BurnersY Y N --- --- x x x

Need to be upfired. Need convective

loop to get gas recirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature

5 Low Excess Air Y N --- --- --- xNeed high O2 for process requirements

and product qualityReduces oxygen content in flue gas and reduces flame temperature

6Burners out of Service

(BOOS)Y N --- --- --- x

Need capacity of all burners for worst

case scenario

Shut off the fuel flow from one burner or more to create fuel rich and fuel

lean zones

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

Combustion is staged by diverting fuel from the upper level burners to the

lower ones or from the center to the side burners to create fuel-rich and

fuel-lean zones

8 Reburning Y N --- --- --- xKiln configuration not correct for this

technology.

Part of the total fuel heat input is injected into the furnace in a region

above the primary (main burners) flames to create a reducing atmosphere

(re-burn zone), where hydrocarbon radicals react with NOx to produce

elemental nitrogen

9 Load Reduction N --- --- --- --- xPower plant technology -product

demand side solution

This is a strategy to reduce load on a power plant by reducing the

electrical demand throught efficiency projects.

10 Energy Efficiency Projects Y Y

Y

(for large

projects like

heat-recoup)

Y

(for large

projects like

heat-recoup)

Site-specific x decrease amount of fuel required to make an acceptable product

11 Coal Drying Y N --- --- --- x Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is

required to be burned. Specific energy efficiency project

12

Coal Addition to Pellets with

Low Excess Air in the

Induration Furnace

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

13 Ported Kilns Y Y

Y

(grate-kilns

only)

N

(Metso says

no NOx

improvement)

--- x x Applicable to grate kilns. Provides additional oxygen for pellet oxidation which reduces the overall

energy use of the kiln

14 Combustion Zone Cooling Y N --- --- --- x Boiler technologyCooling of the primary flame zone by heat transfer to surrounding

surfaces

15 Alternate Fuels Y Y

Y

(for furnaces

capable of

multiple fuels)

Y

(not required

by BART)

Site-specific x x

Requires case by case analysis.

Typically, facilities experience lower

NOx when burning solid fuels.

Lower combustion temps with solid fuels vs gas. May also reduce fuel

NOx by using a fuel with less nitrogen.

16Oxygen Enhanced

CombustionN --- --- --- --- x Research level A small fraction of the combustion air is replaced with oxygen.


NOx Control

Indurating Furnaces






Refe

ren

ce N

o.1


Technology Is t

his

a g

en

era

lly

avail

ab

le c

on

tro

l

tech

no

log

y?

Is t

he c

on

tro

l te

ch

no

log

y

avail

ab

le t

o i

nd

ura

tin

g

furn

aces?

Is t

he c

on

tro

l te

ch

no

log

y

ap

pli

cab

le t

o t

his

sp

ecif

ic

so

urc

e?

Is i

t te

ch

nic

all

y f

easib

le

for

this

so

urc

e?

Approximate

Control

Efficiency MP

CA

Taco

nit

e B

AR

T

Rep

ort

MP

CA

BA

RT

Gu

idan

ce

(Att

ach

men

t 2)

Oth

er2


17 Preheat Combustion N --- --- --- --- x Research level

Pulverized coal preheated and volatiles and fuel-bound nitrogen

compounds are released in a controlled reducing atmosphere where the

nitrogen compounds are reduced to N2.

18 ROFA-ROTAMIX Y N --- --- --- x

Can't achieve correct temperature

window (1400-1800F). Too hot in kiln

too cold in reheat

Combination of OFA and SCR. Wall-fired or tangentially-fired furnace that

utilizes high velocity overfire air. Additional NOx reductions are achieved

with ammonia injection (Rotamix)

19 NOx CEMS Y N --- --- --- x x Optimization of combustion

20 Parametric Monitoring Y N --- --- --- x x Optimization of combustion

38Catalyst Injection

(EPS Technologies)N --- --- --- --- x Research Level

A combustion catalyst is directly injected into the air intake stream and

delivered to the combustion site, initiating chemical reactions that change

the dynamics of the flame.


21Non-Selective Catalytic

Reduction (NSCR)Y N --- --- --- x x

For clean services. Too much stuff in

flue gas would poison catalyst

Under near stoichiometric conditions, in the presence of a catalyst, NOx is

reduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).

22Low Temperature Oxidation

(LTO) - Tri-NOx® Y N --- --- --- x x Used for higher flue gas concentrations

Utilizes an oxidizing agent such as ozone to oxidize various pollutants

including NOx


(LTO) - LoTOxY N --- --- --- x x x

Has been included as an "applicable

and available" technology in recent

BACT analyses from multiple facilities.

Utilizes an oxidizing agent such as ozone to oxidize various pollutants

including NOx

24Selective Catalytic

Reduction (SCR)Y Y Y Y 80% x x x

Need to inject at appropriate

temperature (reheat will be required).

Applicable on clean side only.

Although this hasn't been

demonstrated on an indurating

furnace, the stream characteristics

appear to make this technology

feasible.

Ammonia (NH3) is injected into the flue gas stream in the presence of a

catalyst to convert NOx into N2 and water

25 Regenerative SCR Y N --- --- --- x Clean side only

26Selective Non-Catalytic

Reduction (SNCR)Y N --- --- --- x x

Can't achieve correct temperature

window (1400-1800F). Too hot in kiln

too cold in reheat

Urea or ammonia-based chemicals are injected into the flue gas stream to

convert NO to molecular nitrogen, N2, and water

27 Adsorption N --- --- --- --- x Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen

28 Absorption Y N --- --- --- x Similar to TriNOx

Use of water, hydroxide and carbonate solutions, sulfuric acid, organic

solutions, molten alkali carbonates, or hydroxides to absorb oxides of

nitrogen.

29 Oxidizer Y N --- --- --- x Redundant to regenerative SCR

Gas stream is sent through the regenerative, recuperative, catalytic or

direct fired oxidizer where pollutants are heated to a combustion point and

destroyed.


NOx Control

Indurating Furnaces






Refe

ren

ce N

o.1


Technology Is t

his

a g

en

era

lly

avail

ab

le c

on

tro

l

tech

no

log

y?

Is t

he c

on

tro

l te

ch

no

log

y

avail

ab

le t

o i

nd

ura

tin

g

furn

aces?

Is t

he c

on

tro

l te

ch

no

log

y

ap

pli

cab

le t

o t

his

sp

ecif

ic

so

urc

e?

Is i

t te

ch

nic

all

y f

easib

le

for

this

so

urc

e?

Approximate

Control

Efficiency MP

CA

Taco

nit

e B

AR

T

Rep

ort

MP

CA

BA

RT

Gu

idan

ce

(Att

ach

men

t 2)

Oth

er2


30 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the presence of ammonia (NH3), followed by

catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter

passes through a novel glass-tube condenser in which the SO3 is

hydrated to H2SO4 vapor and then condensed to a concentrated liquid

sulfuric acid (H2SO4).

31 SOx-NOx-Rox-Box N --- --- --- --- xTechnology has not been

demonstrated

Dry sorbent injection upstream of the baghouse for removal of SOx and

ammonia injection upstream of a zeolitic selective catalytic reduction

(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.

32 Electron (E-Beam) Process N --- --- --- --- xNo operating commercial applications

on coal

Electron beam irradiation in the presence of ammonia to initiate chemical

conversion of sulfur and nitrogen oxides into components which can be

easily collected by conventional methods such as an ESP or baghouse.

33 Electrocatalytic Oxidation N --- --- --- --- xSimilar to cold plasma. Will keep

watch for availability of this technology

Utilizes 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.

34 NOXSO N --- --- --- ---

Commercial version of adsorption.

Limited experience (proof-of-concept

tests).

Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from

flue gas from coal-fired utility and industrial boilers. In the process, the

SO2 is converted to a saleable sulfur by-product (liquid SO2, elemental

sulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.

35 Copper-Oxide N --- --- --- --- xAbsorption and SCR. Experience

limited to pilot scale.

SO2 in the flue gas reacts with copper oxide, supported on small spheres

of alumina, to form copper sulfate. Ammonia is injected into the flue gas

before the absorption reactor and a selective catalytic reduction-type

reaction occurs that reduces the nitric oxides in the flue gas. In the

regeneration step, the copper sulfate is reduced in a regenerator with a

reducing agent, such as natural gas, producing a concentrated stream of

SO2.

36 Cold Plasma N --- --- --- --- x Research Level

37 Biofilters Y N --- --- --- x Not applicable to furnaces.

Gas stream is passed through a filter medium of soil and microbes.

Pollutants are adsorbed and degraded by microbial metabolism forming

the products carbon dioxide and water.

38 Pahlman Process N --- --- --- --- x Research Level

Gas stream is passed through a filter baghouse in which specially-

developed, small-particle, high-surface area metal oxide sorbent have

been deployed. Pollutants are removed from the gases 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.htm

2) c) New and Emerging Environmental Technologies, http://neet.rti.org/

2) d) ND BART Reports


SO2 Control

Indurating Furnaces

Available and Applicable Review

Revised: August 23, 2006





Ref

eren

ce N

o.1

SO2 Pollution Control

TechnologyIs

th

is a

gen

era

lly

avail

ab

le c

on

tro

l

tech

no

log

y?

Is t

he c

on

tro

l te

ch

no

log

y

avail

ab

le t

o i

nd

ura

tin

g

furn

aces?

Is t

he c

on

tro

l te

ch

no

log

y

ap

pli

cab

le t

o t

his

sp

ecif

ic

so

urc

e?

Is i

t te

ch

nic

all

y f

easib

le

for

this

so

urc

e?

Approximate

Control

Efficiency

MP

CA

Ta

con

ite

BA

RT

Rep

ort

MP

CA

BA

RT

Gu

ida

nce

(Att

ach

men

t 2

)

Oth

er2


1Wet Scrubbing (High

Efficiency)Y Y Y Y 90-95% x x x Absorption and reaction using an alkaline reagent to produce a solid compound

2Wet Scrubbing (Low

Efficiency)Y Y Y Y <50% x x x Absorption and reaction using an alkaline reagent to produce a solid compound

3Wet Walled Electrostatic

Precipitator (WWESP)Y Y Y Y 80% x x

Suspended particles are separated from the flue gas stream, attracted to plates, and

collected in hoppers

4 Dry sorbent injection Y Y Y N --- x x x

Pulverized lime or limestone is directly injected into the duct upstream of the fabric

filter. Dry sorption of SO2 onto the lime or limestone particle occurs and the solid

particles are collected with a fabric filter

5 Spray Dryer Absorption (SDA) Y Y Y N --- x xLime slurry is sprayed into an absorption tower where SO2 is absorbed by the

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces

capable of

multiple fuels)

Y

(not required

by BART)

Site-specific x x Natural gas is base case Use a fuel with lower sulfur content.

7 Load Reduction N --- --- --- --- x Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electrical

demand throught efficiency projects.

8 Energy Efficiency Projects Y Y

Y

(for large

projects like

heat-recoup)

Y

(for large

projects like

heat-recoup)

Site-specific x decrease amount of fuel required to make an acceptable product

9 Coal Drying Y N --- --- --- x Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is required

to be burned. Specific energy efficiency project

10 Bio Filters N --- --- --- --- x Research level

Gas stream passes through a packed bed of specially engineered biomedia which

supports the growth of active bacterial species. The pollutants in the gas stream are

biodegraded or biotransformed into innocuous products, such as carbon dioxide,

water, chloride ion in water, sulfate or nitrate ions in water.

11 CANSOLV Regenerable SO2 N --- --- --- --- x Research level

An aqueous solution of proprietary diamine captures SO2 from the feed gas in a

countercurrent absorption tower. The rich solvent is regenerated by steam

stripping, giving a byproduct of pure, water saturated SO2 gas and lean solvent for

recycling to the absorber.

12 Pahlman Process N --- --- --- --- x Research level

Gas stream is passed through a filter baghouse in which specially-developed, small-

particle, high-surface area metal oxide sorbent have been deployed. Pollutants are

removed from the gases by adsorption.

13 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated

Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia

injection upstream of a zeolitic selective catalytic reduction (SCR) catalyst

incorporated in the baghouse to reduce NOx emissions.

14 Electron (E-Beam) Process N --- --- --- --- xNo operating commercial applications on

coal

Electron beam irradiation in the presence of ammonia to initiate chemical

conversion of sulfur and nitrogen oxides into components which can be easily

collected by conventional methods such as an ESP or baghouse.


SO2 Control

Indurating Furnaces


Revised: August 23, 2006





Ref

eren

ce N

o.1

SO2 Pollution Control

TechnologyIs

th

is a

gen

era

lly

avail

ab

le c

on

tro

l

tech

no

log

y?

Is t

he c

on

tro

l te

ch

no

log

y

avail

ab

le t

o i

nd

ura

tin

g

furn

aces?

Is t

he c

on

tro

l te

ch

no

log

y

ap

pli

cab

le t

o t

his

sp

ecif

ic

so

urc

e?

Is i

t te

ch

nic

all

y f

easib

le

for

this

so

urc

e?

Approximate

Control

Efficiency

MP

CA

Ta

con

ite

BA

RT

Rep

ort

MP

CA

BA

RT

Gu

ida

nce

(Att

ach

men

t 2

)

Oth

er2


15 Electrocatalytic Oxidation N --- --- --- --- xSimilar to cold plasma. Will keep watch for

availability of this technology

Utilizes 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.

16 NOXSO N --- --- --- ---Commercial version of adsorption. Limited

experience (proof-of-concept tests).

Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from flue gas

from coal-fired utility and industrial boilers. In the process, the SO2 is converted to

a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and the

NOx is converted to nitrogen and oxygen.

17 Copper-Oxide N --- --- --- --- xAbsorption and SCR. Experience limited to

pilot scale.

SO2 in the flue gas reacts with copper oxide, supported on small spheres of

alumina, to form copper sulfate. Ammonia is injected into the flue gas before the

absorption reactor and a selective catalytic reduction-type reaction occurs that

reduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfate

is reduced in a regenerator with a reducing agent, such as natural gas, producing a

concentrated stream of SO2.

18 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the presence of ammonia (NH3), followed by

catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter passes

through a novel glass-tube condenser in which the SO3 is hydrated to H2SO4 vapor

and then condensed to a concentrated liquid sulfuric acid (H2SO4).

19 Cold Plasma N --- --- --- --- x Research level






Summary of Relevant Economic Feasibility ($/ton) Control Costs

Avg. Expected Values

($/ton)

Limiting/Marginal values

($/ton)

Reference Regulatory Body/Rule SO2 NOx SO2 NOx Comments

BART 100 - 1000 100 - 1000 70 FR 39135

BART 281 - 1296 70 FR 39135 Table 3

BART 919 70 FR 39133 FR Notice 6JULY05 Final Rule

BART Guidelines disparagingly reference "thousands of dollars per ton" in commenting on the need to exceed MACT and its general unreasonableness.

70 FR 25210 CAIR CAIR 1300 Estimated Marginal cost 2009

BART(proposed rule) 200-1000

BART proposed lists this as values for 90-95% SO2 control, which is still assumed, or .1 to .15 lb/MMBtu. Dropped from final to give states flexibility to require more. Says for scrubbers, bypasses aren't BART, only 100% scrubbing is BART. FR Notice 5MAY04 Proposed Rule

BART(proposed rule) 0.2 lb/MMBtu for NOx is assumed reasonable. Recognizes that some sources may need SCR to get this level. For those, state discretion of the cost vs. visibility value is necessary.

CAIR(using IPM) 1000 1500

CAIR ( 2009 in 1999$) 900 2400

CAIR ( 2015 in 1999$) 1800 3000

Midwest RPO Report Referencing CAIR

CAIR (depending on Nat'l emissions)

1200 - 3000 1400- 2100 This was modeled with TRUM (Technology Retrofitting Updating Model) to develop the marginal values.

Kammer EPA Decision Kammer Decision > 1000 > 1000

LADCO Midwest RPO Boiler Analysis

LADCO/Midwest RPO 1240 - 3822 607 - 4493

MANE-VU BART Control Assessment

MANE-VU 200 - 500 200 - 1500

Bowers vs. SWAPCA Bowers vs. SWAPCA 300 300 1000 1000 954-1134 was ruled too much, in favor of 256-310 for SO2. This did consider incremental value. Sections XVII to XIX

WRAP 3000 WRAP Trading Program Methodology EPA - Referenced by

Wrap

References EPA-600S\7-90-018. Low is <$500/ton, Moderate is $500-3000/ton, High is over $3000/ton

The dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory programs such as CAIR, and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BART ruling, concretely support an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,000 to $1,300 per ton of SO2 removed. The BART presumptive limits were set based on cost effective controls that were on average less than these ranges. As an example, the presumptive SO2 limit was established based on an average cost effectiveness of less than $1,000/ton. As the cost analysis extends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and difficult to predict. For ease of comparison, the federally established ranges for NOx and SO2 were used as a BART cost threshold basis.


NOX Control

Process Boilers


Step 1 Step 2

Re

fere

nc

e N

o.1


Technology Is t

his

a g

en

era

lly

av

aila

ble

co

ntr

ol

tec

hn

olo

gy

?

Is t

he

co

ntr

ol te

ch

no

log

y

av

aila

ble

to

pro

ce

ss

bo

ile

rs?

Is t

he

co

ntr

ol te

ch

no

log

y

ap

plic

ab

le t

o t

his

sp

ec

ific

so

urc

e?

Is it

tec

hn

ica

lly

fe

as

ible

for

this

so

urc

e?

Approximate Control

Efficiency

Combustion Controls

1External Flue Gas

Recirculation (EFGR)Y Y N N ---

2 Low-NOx Burners (LNB) Y Y Y Y 50%

3 LNB with Overfire Air (OFA) Y Y Y Y 68%

4Induced Flue Gas

Recirculation BurnersY Y Y Y 75%

10 Energy Efficiency Projects Y Y Y Y Site-specific

15 Alternate Fuels Y Y Y

Y

(not required by

BART)

Site-specific


21Non-Selective Catalytic

Reduction (NSCR)Y N --- --- ---


(LTO) - Tri-NOx® Y N --- --- ---


(LTO) - LoTOxY Y Y Y 90%

24Selective Catalytic

Reduction (SCR)Y Y Y Y 80%

25 Regenerative SCR Y Y Y Y 70%

26Selective Non-Catalytic

Reduction (SNCR)Y Y Y Y 50%






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