Minntac BART Report 

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Minntac BART Report 

September 8, 2006

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 

⋅ Line 5 = 182 lbs/hr 

⋅ Line 6 = 284 lbs/hr 

⋅ Line 7 = 284 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. 

⋅ Line 5: 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. 

⋅ Line 7: Installation of low-NOx burners on the pre-heat section, 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 timeframe 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 visibilityimpairing pollutant from the emission units meeting the two criteria above. 

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

required under another standard (e.g., MACT, NSPS and BACT) 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

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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. 

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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. 

 

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

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

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

finished pellets), 

• Material Transfer Points, 

• Plant Roadways, 

• Tailings basins, 

• Pellet loading areas, and 

• Yard areas. 

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

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

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 
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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-toBART in the State of Minnesota.
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(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. 
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Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis 
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Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data 
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Table 3-3 De Minimis Visibility Modeling Results 
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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. 
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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

o Line 4 Rotary Kiln (EU 261 / SV 118) - NOx and SO2

o Line 5 Rotary Kiln (EU 280 / SV 127) - NOx and SO2

o Line 6 Rotary Kiln (EU 315 / SV 144) - NOx and SO2

o Line 7 Rotary Kiln (EU 334 / SV 151) - 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 
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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. 
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Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data 
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Table 4-2 Baseline Visibility Modeling Results 
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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) 

o Line 4 Rotary Kiln (EU 261 / SV 118) 

o Line 5 Rotary Kiln (EU 282 / SV 127) 

o Line 6 Rotary Kiln (EU 315 / SV 144) 

o Line 7 Rotary Kiln (EU 334 / SV 151) 

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

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

o Utility Plant Heating Boiler #2 (EU 002 / SV 002) 

o Utility Plant Heating Boiler #4 (EU 004 / SV 004) 

o Utility Plant Heating Boiler #5 (EU 005 / SV 005) 

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. 
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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 4 Rotary Kiln (EU 261 / SV 118) – natural gas, biomass, and fuel oil 

• Line 5 Rotary Kiln (EU 282 / SV 127) – 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 
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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. 
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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: 

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

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? 

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

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

reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

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

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

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

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

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

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

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

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source? 

Wet Walled Electrostatic 

Precipitator (WWESP) 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% 
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5.A.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-2 above, the technically feasible control 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. 
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Table 5-3 Indurating Furnace SO2 Control Cost Summary 
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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 rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled 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. 
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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. 
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Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission 

Rates 
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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. 
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Table 5-5 Indurating Furnace Post-BART SO2 Modeling Scenarios - Visibility Modeling 

Results 
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5.A.ii Nitrogen Oxide Controls 

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

mechanisms by which NOx production occurs: 

• 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 

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: 

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

BART analysis? 

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

is undergoing the BART analysis? 
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3. Are there source-specific issues/conditions that would make the control technology 

not technically feasible? 

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. 
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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 
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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. 
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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 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. 
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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. 

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

option, not to direct the fuel choice.26 

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. 

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 

 

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

27 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4. 
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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. 
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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 
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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; 
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• 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) 
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Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

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

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

feasibility as determined in Step 2 is also included in Table 5-6.
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Table 5-6 Indurating Furnace NOx Control Technology – Availability, Applicability, and 

Technical Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

Is this a generally available control technology? Is the control technology available to indurating furnaces? Is the control technology applicable to this specific source? Is it technically feasible for this source? 

External Flue Gas 

Recirculation (EFGR) Y Y N --- 

Low-NOx Burners Y Y 

Y 

(preheat 

section) 

Y 

Induced Flue Gas 

Recirculation Burners Y Y N --- 

Energy Efficiency Projects 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 

Non-Selective Catalytic 

Reduction (NSCR) Y N --- --- 

Selective Catalytic Reduction 

(SCR) with conventional 

reheat 

Y Y Y Y 

Regenerative SCR Y N --- --- 

Selective Non-Catalytic 

Reduction (SNCR) Y N --- --- 

Low Temperature Oxidation 

(LTO) Y N --- --- 
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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. 
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Table 5-8 Indurating Furnace NOx Control Cost Summary 
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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. 

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

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

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

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

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

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

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

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant30. 

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

evaluated for visibility improvement, energy and other impacts. 

 

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. 
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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 lowNOx 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 

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

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

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

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

document. 

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 
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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. Similar to the modeling for the baseline or preBART 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. 

Post-BART Visibility Impacts Modeling Results 

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. 
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• 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. 

A summary of visibility impacts for the total facility BART analysis are presented in Section 6. 
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Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum 

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

Results 
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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 
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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 

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: 

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

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) 

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 
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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 

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. 
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Energy Efficiency Projects 

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

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

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.31 

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 

fuel usage as the feasibility arises. 

 

31 Federal Register 70, no. 128 (July 6, 2005): 39164
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Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the 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. 

Non-Selective Catalytic Reduction (NSCR) 

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

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

primarily in natural gas combustion applications. 

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

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

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

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

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

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

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

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

liquid fuels. 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: 
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4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

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

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

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

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

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

corrosion problems. 

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

temperature range. However, these catalysts are very expensive. 

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

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

low loads because of the low gas temperature. 

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

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

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

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

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

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

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

recovery. The 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. 

Selective Non-Catalytic Reduction (SNCR) 

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 
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NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F, 

reaction (2) will dominate. This control option is considered feasible. 

Low Temperature Oxidation (LTO) 

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

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

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

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

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

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

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

available and applicable to the indurating furnace process are identified in Table 5-12. The technical 

feasibility as determined in Step 2 is also included in Table 5-13.
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Table 5-12 Boiler NOx Control Technology – Availability, Applicability, and Technical 

Feasibility 

Step 1 Step 2 

SO2 Pollution Control 

Technology 

Is this a generally available control technology? Is the control technology available to heating boiler? Is the control technology applicable to this specific source? Is it technically feasible for this source? 

External Flue Gas 

Recirculation (EFGR) 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 

Energy Efficiency Projects Y Y Y N 

Alternative Fuels Y Y Y N 

Non-Selective Catalytic 

Reduction (NSCR) Y Y Y N 

Selective Catalytic Reduction 

(SCR) Y Y Y Y 

Regenerative SCR Y Y Y Y 

Selective Non-Catalytic 

Reduction (SNCR) Y Y Y Y 

Low Temperature Oxidation 

(LTO) 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. 
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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. 

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

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

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

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

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

proposing BART in lieu of developing industry and site specific data. 
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Table 5-14 Boiler NOx Control Cost Summary 
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The annualized pollution control cost value was used to determine whether or not additional impacts 

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

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

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

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant32. 

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

evaluated for visibility improvement, energy and other impacts. 

The 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 

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

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

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

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

document. 

Predicted 24-Hour Maximum Emission Rates 

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

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

maximum 24-hour average project emission rate. 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 postbaseline (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. 
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Post-BART Visibility Impacts Modeling Results 

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. 

A summary of visibility impacts for the total facility BART analysis are presented in Section 6. 
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Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates 
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Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results 
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6. Visibility Impacts 

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

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

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

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

The visibility impacts of individual control technologies were presented in Step 5 of 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. 
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• 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 
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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. 
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Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results 
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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) 

• Line 4 Rotary Kiln (EU 261 / SV 118) 

• Line 5 Rotary Kiln (EU 282 / SV 127) 

• Line 6 Rotary Kiln (EU 315 / SV 144) 

• Line 7 Rotary Kiln (EU 334 / SV 151) 

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: 
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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: 

⋅ Line 4 = 182 lbs/hr 

⋅ Line 5 = 182 lbs/hr 

⋅ Line 6 = 284 lbs/hr 

⋅ Line 7 = 284 lbs/hr 

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

furnace. 
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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 4: Installation of low-NOx burners on the pre-heat section, existing 

combustion controls, and fuel blending. 

⋅ Line 5: Installation of low-NOx burners on the pre-heat section, existing 

combustion controls, and fuel blending. 

⋅ 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. 

⋅ Line 7: Installation of low-NOx burners on the pre-heat section, 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. 
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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: 

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

o Utility Plant Heating Boiler #2 (EU 002 / SV 002) 

o Utility Plant Heating Boiler #3 (EU 003 / SV 003) 

o Utility Plant Heating Boiler #4 (EU 004 / SV 004) 

o Utility Plant Heating Boiler #5 (EU 005 / SV 005) 

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

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 A

3.A. Indurating Furnaces

EU 223 Traveling Grate (Line 3) --- --- 655.2 0.01 SV 103 BART A

EU 225 Rotary Kiln (Line 3) --- --- Incl with EU223 0.01 SV 103 BART AEU 226 Pellet Cooler Secondary Air (Line 3) --- --- Incl with EU223 0.01 SV 103 BART AEU 259 Traveling Grate (Line 4) --- --- 1,504.8 0.01 SV 118 BART AEU 260 Recouperative System Air (Line 4) --- --- Incl with EU259 0.01 SV 118 BART AEU 261 Rotary Kiln (Line 4) --- --- Incl with EU259 0.01 SV 118 BART AEU 262 Pellet Cooler Secondary Air (Line 4) --- --- Incl with EU259 0.01 SV 118 BART AEU 280 Traveling Grate (Line 5) --- --- 2,568.0 0.01 SV 127 BART AEU 281 Recouperative System Air (Line 5) --- --- Incl with EU280 0.01 SV 127 BART AEU 282 Rotary Kiln (Line 5) --- --- Incl with EU280 0.01 SV 127 BART AEU 283 Pellet Cooler Secondary Air (Line 5) --- --- Incl with EU280 0.01 SV 127 BART AEU 313 Traveling Grate (Line 6) --- --- 1,944.0 0.01 SV 144 BART AEU 314 Recoup System (Line 6) --- --- Incl with EU314 0.01 SV 144 BART AEU 315 Rotary Kiln (Line 6) --- --- Incl with EU314 0.01 SV 144 BART AEU 316 Pellet Cooler Secondary Air (Line 6) --- --- Incl with EU314 0.01 SV 144 BART AEU 332 Traveling Grate (Line 7) --- --- 1,968.0 0.01 SV 151 BART AEU 333 Recoup System (Line 7) --- --- Incl with EU332 0.01 SV 151 BART AEU 334 Rotary Kiln (Line 7) --- --- Incl with EU332 0.01 SV 151 BART AEU 335 Pellet Cooler Secondary Air (Line 7) --- --- Incl with EU332 0.01 SV 151 BART A

3.B. PM-Only Taconite MACT Emission Units

EU 013 Dump Pocket --- --- 62.4 0.008 SV 013 

EU 014 Crusher --- --- Incl with EU013 0.008 SV 013 EU 015 Dump Pocket --- --- 62.4 0.008 SV 014 

EU 016 Crusher --- --- Incl with EU015 0.008 SV 014 EU 017 Dump Pocket --- --- 62.4 0.008 SV 015 

EU 018 Crusher --- --- Incl with EU017 0.008 SV 015 EU 019 Dump Pocket --- --- Incl with EU017 0.008 SV 015 

EU 020 Crusher --- --- Incl with EU017 0.008 SV 015 EU 022 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 016 

EU 023 Pre-1969 Panfeeder --- --- Incl with EU022 0.008 SV 016 

EU 024 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 017 

EU 025 Pre-1969 Panfeeder --- --- Incl with EU024 0.008 SV 017 

EU 026 Post-1969 Panfeeder --- --- 11.0 0.008 SV 018 

EU 027 Post-1969 Panfeeder --- --- Incl with EU026 0.008 SV 018 

EU 034 Ore Transfer From 061-02-1 to 005-02-1 --- --- 31.2 0.008 SV 021 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 035 Ore Transfer From 061-02-1 to 005-02-1 --- --- Incl with EU034 0.008 SV 021 

EU 036 Ore Transfer From 061-03-1 to 010-01-1 --- --- 31.2 0.008 SV 022 

EU 037 Ore Transfer Fr 004-01-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 EU 038 Ore Transfer Fr 004-02-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 EU 039 Ore Transfer From 011-01-1 to 060-01-1 --- --- Incl with EU036 0.008 SV 022 

EU 040 Ore Transfer From 061-01-1 to 005-01-1 --- --- 31.2 0.008 SV 023 

EU 041 Ore Transfer From 061-08-1 to 010-02-1 --- --- 31.2 0.008 SV 024 

EU 042 Ore Transfer From 061-07-1 to 005-03-1 --- --- Incl with EU041 0.008 SV 024 

EU 043 Ore Transfer From 061-06-1 to 005-04-1 --- --- Incl with EU041 0.008 SV 024 

EU 044 Ore Transfer From 011-03-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 

EU 045 Ore Transfer From 004-03-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 

EU 046 Ore Transfer From 004-04-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 

EU 047 Ore Transfer From 011-02-1 to 011-03-1 --- --- 31.2 0.008 SV 025 

EU 048 Ore Transfer From Stockpile to 011-01-1 --- --- 31.2 0.008 SV 026 

EU 052 Ore Transfer Fr 008-01-1 to 009-01-1 or 009-02-1 --- --- 6.0 0.008 SV 030 EU 053 Ore Transfer From 008-02-1 to 009-02-1 --- --- Incl with EU052 0.008 SV 030 

EU 054 Secondary Crusher --- --- 14.2 0.008 SV 031 

EU 055 Secondary Crusher --- --- 14.2 0.008 SV 032 

EU 056 Secondary Crusher --- --- 12.0 0.008 SV 033 

EU 057 Secondary Crusher --- --- 14.2 0.008 SV 034 

EU 058 Ore Transfer From 001-01-1 to 070-01-1 --- --- 5.5 0.008 SV 035 EU 059 Ore Transfer From 005-02-1 to 006-02-1 --- --- Incl with EU058 0.008 SV 035 

EU 060 Ore Transfer From 005-01-1 to 006-01-1 --- --- Incl with EU058 0.008 SV 035 

EU 061 Ore Transfer From 003-01-1 to 004-01-1 --- --- 5.5 0.008 SV 036 

EU 062 Ore Transfer From 003-02-1 to 004-02-1 --- --- Incl with EU061 0.008 SV 036 

EU 063 Ore Transfer From 003-03-1 to 004-01-1 --- --- Incl with EU061 0.008 SV 036 

EU 064 Ore Transfer From 003-04-1 to 004-02-1 --- --- Incl with EU061 0.008 SV 036 

EU 065 Ore Transfer From 006-01-1 to 080-01-1 --- --- 5.5 0.008 SV 037 EU 066 Ore Transfer From 006-01-1 to 080-03-1 --- --- Incl with EU065 0.008 SV 037 

EU 067 Ore Transfer From 006-01-1 to 080-05-1 --- --- Incl with EU065 0.008 SV 037 

EU 068 Ore Transfer From 006-01-1 to 080-07-1 --- --- Incl with EU065 0.008 SV 037 

EU 069 Tertiary Crusher --- --- 7.2 0.008 SV 038 EU 070 Tertiary Crusher --- --- 7.2 0.008 SV 039 EU 071 Tertiary Crusher --- --- 7.2 0.008 SV 040 EU 072 Tertiary Crusher --- --- 7.2 0.008 SV 041 EU 073 Tertiary Crusher --- --- 7.2 0.008 SV 042 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 074 Tertiary Crusher --- --- 7.2 0.008 SV 043 EU 075 Tertiary Crusher --- --- 7.2 0.008 SV 044 EU 076 Tertiary Crusher --- --- 7.2 0.008 SV 045 EU 077 Tertiary Crusher --- --- 7.2 0.008 SV 046 EU 078 Tertiary Crusher --- --- 7.2 0.008 SV 047 EU 079 Tertiary Crusher --- --- 7.2 0.008 SV 048 EU 080 Tertiary Crusher --- --- 7.2 0.008 SV 049 EU 081 Tertiary Crusher --- --- 16.6 0.008 SV 050 

EU 082 Tertiary Crusher --- --- 16.6 0.008 SV 051 

EU 083 Tertiary Crusher --- --- 16.6 0.008 SV 052 

EU 084 Tertiary Crusher --- --- 16.6 0.008 SV 053 

EU 085 Ore Transfer From 006-01-1 to 080-15-1 --- --- 16.8 0.008 SV 054 

EU 086 Ore Transfer From 006-01-1 to 080-09-1 --- --- Incl with EU085 0.008 SV 054 

EU 087 Ore Transfer From 006-01-1 to 080-11-1 --- --- Incl with EU085 0.008 SV 054 

EU 088 Ore Transfer From 006-01-1 to 080-13-1 --- --- Incl with EU085 0.008 SV 054 

EU 089 Ore Transfer From 006-01-2 to 080-15-1 --- --- Incl with EU085 0.008 SV 054 

EU 090 Ore Transfer From 006-01-2 to 080-09-1 --- --- Incl with EU085 0.008 SV 054 

EU 091 Ore Transfer From 006-01-2 to 080-11-1 --- --- Incl with EU085 0.008 SV 054 

EU 092 Ore Transfer From 006-01-2 to 080-13-1 --- --- Incl with EU085 0.008 SV 054 

EU 093 Secondary Crusher --- --- 18.7 0.008 SV 055 

EU 094 Secondary Crusher --- --- 18.7 0.008 SV 056 

EU 095 Secondary Crusher --- --- 18.7 0.008 SV 057 

EU 096 Secondary Crusher --- --- 18.7 0.008 SV 058 

EU 097 Secondary Crusher --- --- 18.7 0.008 SV 059 

EU 098 Ore Transfer From 008-03-1 to 009-03-1 --- --- 5.5 0.008 SV 060 

EU 099 Ore Transfer From 003-05-1 to 003-06-1 --- --- Incl with EU098 0.008 SV 060 

EU 100 Ore Transfer From 003-06-1 to 003-02-1 --- --- Incl with EU098 0.008 SV 060 

EU 101 Ore Transfer From 009-03-1 to 009-02-1 --- --- Incl with EU098 0.008 SV 060 

EU 102 Ore Transfer From 001-01-2 to 070-02-1 --- --- 7.7 0.008 SV 061 EU 103 Secondary Crusher --- --- 14.2 0.008 SV 062 

EU 104 Ore Transfer From 008-04-1 to 009-04-1 --- --- 6.0 0.008 SV 063 EU 105 Ore Transfer From 008-05-1 to 009-05-1 --- --- Incl with EU105 0.008 SV 063 

EU 106 Secondary Crusher --- --- 14.6 0.008 SV 064 

EU 107 Secondary Crusher --- --- 18.7 0.008 SV 065 

EU 108 Secondary Crusher --- --- 18.7 0.008 SV 066 

EU 109 Secondary Crusher --- --- 18.7 0.008 SV 067 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 110 Secondary Crusher --- --- 18.7 0.008 SV 068 

EU 111 Ore Transfer From 001-03-1 to 070-03-1 --- --- 4.8 0.008 SV 069 EU 112 Ore Transfer From 003-07-1 to 003-09-1 --- --- 6.0 0.008 SV 070 EU 113 Ore Transfer From 003-08-1 to 003-10-1 --- --- Incl with EU112 0.008 SV 070 

EU 114 Ore Transfer From 003-09-1 to 004-03-1 --- --- 6.0 0.008 SV 071 EU 115 Ore Transfer From 003-10-1 to 004-04-1 --- --- Incl with EU114 0.008 SV 071 

EU 116 Ore Transfer From 006-03-1 to 080-18-1 --- --- 12.5 0.008 SV 072 

EU 117 Ore Transfer From 006-03-1 to 080-20-1 --- --- Incl with EU116 0.008 SV 072 

EU 118 Ore Transfer From 006-03-1 to 080-22-1 --- --- Incl with EU116 0.008 SV 072 

EU 119 Ore Transfer From 006-03-1 to 080-24-1 --- --- Incl with EU116 0.008 SV 072 

EU 120 Ore Transfer From 006-03-1 to 080-26-1 --- --- Incl with EU116 0.008 SV 072 

EU 121 Ore Transfer From 006-03-1 to 080-28-1 --- --- Incl with EU116 0.008 SV 072 

EU 122 Ore Transfer From 006-04-1 to 080-18-1 --- --- Incl with EU116 0.008 SV 072 

EU 123 Ore Transfer From 006-04-1 to 080-20-1 --- --- Incl with EU116 0.008 SV 072 

EU 124 Ore Transfer From 006-04-1 to 080-22-1 --- --- Incl with EU116 0.008 SV 072 

EU 125 Ore Transfer From 006-04-1 to 080-24-1 --- --- Incl with EU116 0.008 SV 072 

EU 126 Ore Transfer From 006-04-1 to 080-26-1 --- --- Incl with EU116 0.008 SV 072 

EU 127 Ore Transfer From 006-04-1 to 080-28-1 --- --- Incl with EU116 0.008 SV 072 

EU 128 Tertiary Crusher --- --- 10.6 0.008 SV 073 

EU 129 Tertiary Crusher --- --- 10.6 0.008 SV 074 

EU 130 Tertiary Crusher --- --- 10.6 0.008 SV 075 

EU 131 Tertiary Crusher --- --- 10.6 0.008 SV 076 

EU 132 Tertiary Crusher --- --- 10.6 0.008 SV 077 

EU 133 Tertiary Crusher --- --- 10.6 0.008 SV 078 

EU 134 Tertiary Crusher --- --- 10.6 0.008 SV 079 

EU 135 Tertiary Crusher --- --- 10.6 0.008 SV 080 

EU 136 Tertiary Crusher --- --- 10.6 0.008 SV 081 

EU 137 Tertiary Crusher --- --- 10.6 0.008 SV 082 

EU 138 Tertiary Crusher --- --- 10.6 0.008 SV 083 

EU 140 Ore Transfer From 005-03-1 to 006-03-1 --- --- 5.5 0.008 SV 085 

EU 141 Ore Transfer From 005-04-1 to 006-04-1 --- --- Incl with EU140 0.008 SV 085 

EU 144 Ore Transfer From 009-01-1 to 020-01-1 --- --- 10.6 0.008 SV 087 

EU 145 Ore Transfer From 009-02-1 to 020-02-1 --- --- Incl with EU144 0.008 SV 087 

EU 146 Ore Transfer From 009-02-1 to 020-06-1 --- --- Incl with EU144 0.008 SV 087 

EU 147 Ore Transfer From 020-05-1 to 020-01-1 --- --- Incl with EU144 0.008 SV 087 

EU 155 Ore Transfer From 020-01-1 to Bin 100-06 --- --- 5.5 0.008 SV 089 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 156 Ore Transfer From 020-01-1 to Bin 100-07 --- --- Incl with EU155 0.008 SV 089 EU 157 Ore Transfer From 020-01-1 to Bin 100-08 --- --- Incl with EU155 0.008 SV 089 EU 158 Ore Transfer From 020-01-1 to Bin 100-09 --- --- Incl with EU155 0.008 SV 089 EU 159 Ore Transfer From 020-01-1 to Bin 100-10 --- --- Incl with EU155 0.008 SV 089 EU 160 Ore Transfer From 021-03-1 to 022-03-1 --- --- Incl with EU155 0.008 SV 089 

EU 161 Ore Transfer From 021-04-1 to 022-04-1 --- --- Incl with EU155 0.008 SV 089 

EU 162 Ore Transfer From 020-01-1 to Bin 100-11 --- --- 9.1 0.008 SV 090 EU 163 Ore Transfer From 020-01-1 to Bin 100-12 --- --- Incl with EU162 0.008 SV 090 EU 164 Ore Transfer From 020-01-1 to Bin 100-13 --- --- Incl with EU162 0.008 SV 090 EU 165 Ore Transfer From 020-01-1 to Bin 100-14 --- --- Incl with EU162 0.008 SV 090 EU 166 Ore Transfer From 020-01-1 to Bin 100-15 --- --- Incl with EU162 0.008 SV 090 EU 167 Ore Transfer From 021-05-1 to 022-05-1 --- --- Incl with EU162 0.008 SV 090 

EU 168 Ore Transfer From 021-06-1 to 022-06-1 --- --- Incl with EU162 0.008 SV 090 

EU 169 Ore Transfer From 020-01-1 to Bin 100-16 --- --- 4.3 0.008 SV 091 EU 170 Ore Transfer From 020-01-1 to Bin 100-17 --- --- Incl with EU169 0.008 SV 091 EU 171 Ore Transfer From 020-01-1 to Bin 100-18 --- --- Incl with EU169 0.008 SV 091 EU 172 Ore Transfer From 020-01-1 to Bin 100-19 --- --- Incl with EU169 0.008 SV 091 EU 173 Ore Transfer From 020-01-1 to Bin 100-20 --- --- Incl with EU169 0.008 SV 091 EU 174 Ore Transfer From 021-07-1 to 022-07-1 --- --- Incl with EU169 0.008 SV 091 

EU 175 Ore Transfer From 021-08-1 to 022-08-1 --- --- Incl with EU169 0.008 SV 091 

EU 176 Ore Transfer From 020-01-1 to Bin 100-21 --- --- 10.6 0.008 SV 092 EU 177 Ore Transfer From 020-01-1 to Bin 100-22 --- --- Incl with EU176 0.008 SV 092 EU 178 Ore Transfer From 020-01-1 to Bin 100-23 --- --- Incl with EU176 0.008 SV 092 EU 179 Ore Transfer From 020-01-1 to Bin 100-24 --- --- Incl with EU176 0.008 SV 092 EU 180 Ore Transfer From 020-01-1 to Bin 100-25 --- --- Incl with EU176 0.008 SV 092 EU 181 Ore Transfer From 021-09-1 to 022-09-1 --- --- Incl with EU176 0.008 SV 092 

EU 182 Ore Transfer From 021-10-1 to 022-10-1 --- --- Incl with EU176 0.008 SV 092 

EU 183 Ore Transfer From 020-01-1 to Bin 100-26 --- --- 10.6 0.008 SV 093 EU 184 Ore Transfer From 020-01-1 to Bin 100-27 --- --- Incl with EU183 0.008 SV 093 EU 185 Ore Transfer From 020-01-1 to Bin 100-28 --- --- Incl with EU183 0.008 SV 093 EU 186 Ore Transfer From 020-01-1 to Bin 100-29 --- --- Incl with EU183 0.008 SV 093 EU 187 Ore Transfer From 020-01-1 to Bin 100-30 --- --- Incl with EU183 0.008 SV 093 EU 188 Ore Transfer From 021-11-1 to 022-11-1 --- --- Incl with EU183 0.008 SV 093 

EU 189 Ore Transfer From 021-12-1 to 022-12-1 --- --- Incl with EU183 0.008 SV 093 

EU 190 Ore Transfer From 009-04-1 to 020-04-1 --- --- 10.6 0.008 SV 094 

EU 191 Ore Transfer From 009-05-1 to 020-03-1 --- --- Incl with EU190 0.008 SV 094 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 192 Ore Transfer From 009-05-1 to 020-05-1 --- --- Incl with EU190 0.008 SV 094 

EU 193 Ore Transfer From 020-06-1 to 020-04-1 --- --- Incl with EU190 0.008 SV 094 

EU 194 Ore Transfer From 020-01-1 to Bin 100-31 --- --- 10.6 0.008 SV 095 EU 195 Ore Transfer From 020-01-1 to Bin 100-32 --- --- Incl with EU194 0.008 SV 095 EU 196 Ore Transfer From 020-01-1 to Bin 100-33 --- --- Incl with EU194 0.008 SV 095 EU 197 Ore Transfer From 020-01-1 to Bin 100-34 --- --- Incl with EU194 0.008 SV 095 EU 198 Ore Transfer From 020-01-1 to Bin 100-35 --- --- Incl with EU194 0.008 SV 095 EU 199 Ore Transfer From 021-13-1 to 022-13-1 --- --- Incl with EU194 0.008 SV 095 

EU 200 Ore Transfer From 021-14-1 to 022-14-1 --- --- Incl with EU194 0.008 SV 095 

EU 201 Ore Transfer From 020-01-1 to Bin 100-36 --- --- 10.6 0.008 SV 096 EU 202 Ore Transfer From 020-01-1 to Bin 100-37 --- --- Incl with EU201 0.008 SV 096 EU 203 Ore Transfer From 020-01-1 to Bin 100-38 --- --- Incl with EU201 0.008 SV 096 EU 204 Ore Transfer From 021-15-1 to 022-15-1 --- --- Incl with EU201 0.008 SV 096 

EU 205 Ore Transfer From 021-16-1 to 022-16-1 --- --- Incl with EU201 0.008 SV 096 

EU 206 Ore Transfer From 020-01-1 to Bin 100-39 --- --- Incl with EU201 0.008 SV 096 EU 207 Ore Transfer From 020-01-1 to Bin 100-40 --- --- Incl with EU201 0.008 SV 096 EU 208 Ore Transfer From 020-01-1 to Bin 100-41 --- --- 10.6 0.008 SV 097 EU 209 Ore Transfer From 020-01-1 to Bin 100-42 --- --- Incl with EU208 0.008 SV 097 EU 210 Ore Transfer From 020-01-1 to Bin 100-43 --- --- Incl with EU208 0.008 SV 097 EU 211 Ore Transfer From 020-01-1 to Bin 100-44 --- --- Incl with EU208 0.008 SV 097 EU 212 Ore Transfer From 020-01-1 to Bin 100-45 --- --- Incl with EU208 0.008 SV 097 EU 213 Ore Transfer From 021-17-1 to 022-17-1 --- --- Incl with EU208 0.008 SV 097 

EU 214 Ore Transfer From 021-18-1 to 022-18-1 --- --- Incl with EU208 0.008 SV 097 

EU 221 Traveling Grate --- --- 4.6 0.008 SV 101 

EU 222 Traveling Grate --- --- 9.1 0.008 SV 102 

EU 227 L3 Pellet Cooler --- --- 832.8 0.008 SV 104 

EU 228 L3 Pellet Cooler Dump Zone --- --- 9.4 0.008 SV 105 EU 229 L3 Feeder 041/046 Belts --- --- 912.0 0.008 SV 106 

EU 230 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 --- --- 4.3 0.008 SV 107 EU 231 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 --- --- Incl with EU230 0.008 SV 107 EU 232 Pellet Transfer From 042-01-1 to 043-01-1 --- --- 4.3 0.008 SV 108 

EU 233 Pellet Transfer From 042-01-2 to 043-01-2 --- --- Incl with EU232 0.008 SV 108 

EU 234 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 --- --- 4.3 0.008 SV 109 EU 235 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 --- --- Incl with EU234 0.008 SV 109 EU 257 Traveling Grate --- --- 2.6 0.008 SV 116 

EU 258 Traveling Grate --- --- 722.4 0.008 SV 117 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 263 L4 Pellet Cooler --- --- 304.1 0.008 SV 119 

EU 264 L4 Conv. Trans. Feeder --- --- 912.0 0.008 SV 120 

EU 265 L4 Pellet Cooler Dump Zone --- --- 33.6 0.008 SV 121 

EU 266 Pellet Trnsfr Fr 041-04-1 to 042-01-1 or 042-02-2 --- --- 26.4 0.008 SV 122 

EU 267 Pellet Trnsfr Fr 046-04-1 to 042-01-1 or 042-02-2 --- --- Incl with EU266 0.008 SV 122 EU 278 Traveling Grate --- --- 2.6 0.008 SV 125 

EU 279 Traveling Grate --- --- 705.2 0.008 SV 126 EU 284 L5 Pellet Cooler --- --- 145.7 0.008 SV 128 

EU 285 L5 Conv. Trans. Feeder --- --- 912.0 0.008 SV 129 

EU 286 L5 Pellet Cooler Dump Zone --- --- 33.6 0.008 SV 130 

EU 287 Pellet Trnsfr Fr 041-05-1 to 042-01-1 or 042-02-2 --- --- 43.2 0.008 SV 131 

EU 288 Pellet Trnsfr Fr 046-05-1 to 042-01-1 or 042-02-2 --- --- Incl with EU287 0.008 SV 131 EU 289 Conveyor --- --- 77.8 0.008 SV 132 

EU 290 Conveyor --- --- 77.8 0.008 SV 133 

EU 291 Conveyor --- --- 77.8 0.008 SV 134 

EU 292 Conveyor --- --- 77.8 0.008 SV 135 

EU 293 Conveyor --- --- 77.8 0.008 SV 136 

EU 294 Conveyor --- --- 77.8 0.008 SV 137 

EU 295 Pellet Transfer From 046-06-1 to 042-07-1 --- --- 31.2 0.008 SV 138 

EU 296 Pellet Transfer From 046-06-2 to 042-07-2 --- --- Incl with EU295 0.008 SV 138 

EU 311 Traveling Grate --- --- 2.6 0.008 SV 142 

EU 312 Traveling Grate --- --- 767.4 0.008 SV 143 EU 318 Pellet Trnsfr Fr 041-06-1 to 042-06-1 or 042-06-2 --- --- 48.0 0.008 SV 146 

EU 319 Pellet Trnsfr Fr 046-06-1 to 042-06-1 or 042-06-2 --- --- Incl with EU318 0.008 SV 146 EU 330 Traveling Grate --- --- 2.6 0.008 SV 149 

EU 331 Traveling Grate --- --- 717.0 0.008 SV 150 EU 337 Pellet Trnsfr Fr 041-07-1 to 042-06-1 or 042-06-2 --- --- 384.0 0.008 SV 153 

EU 338 Pellet Trnsfr Fr 046-07-1 to 042-06-1 or 042-06-2 --- --- Incl with EU337 0.008 SV 153 EU 339 Pellet Transfer From 043-03-1 to 044-03-1 --- --- 77.8 0.008 SV 154 

EU 340 Pellet Transfer From 043-03-2 to 044-03-2 --- --- 77.8 0.008 SV 155 

EU 341 Conveyor --- --- 204.4 0.008 SV 156 

EU 342 Conveyor --- --- 204.4 0.008 SV 157 

EU 343 Conveyor --- --- 204.4 0.008 SV 158 

EU 344 Conveyor --- --- 204.4 0.008 SV 159 

EU 345 Conveyor --- --- 204.4 0.008 SV 160 

EU 346 Conveyor --- --- 204.4 0.008 SV 161 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 347 Conveyor --- --- 204.4 0.008 SV 162 

EU 348 Conveyor --- --- 204.4 0.008 SV 163 

EU 349 Conveyor --- --- 204.4 0.008 SV 164 

EU 350 Conveyor --- --- 204.4 0.008 SV 165 

EU 351 Conveyor --- --- 204.4 0.008 SV 166 

EU 352 Conveyor --- --- 204.4 0.008 SV 167 

EU 353 Conveyor --- --- 204.4 0.008 SV 168 

EU 354 Conveyor --- --- 204.4 0.008 SV 169 

EU 355 Conveyor --- --- 204.4 0.008 SV 170 

EU 359 Pellet Transfer From 043-06-1 to 044-06-1 --- --- 204.4 0.008 SV 174 EU 360 Conveyor --- --- 204.4 0.008 SV 175 

EU 361 Pellet Transfer From 043-06-2 to 044-06-2 --- --- 204.4 0.008 SV 176 EU 362 Conveyor --- --- 204.4 0.008 SV 177 

EU 363 Pellet Transfer From 044-06-1 to 044-07-1 --- --- 204.4 0.008 SV 178 EU 364 Pellet Transfer From 044-06-2 to 044-07-2 --- --- 204.4 0.008 SV 179 EU 365 Conveyor --- --- 204.4 0.008 SV 179 

EU 366 Pellet Hopper --- --- 204.4 0.008 SV 180 

EU 397 Line 6 Cooler Vent Stack --- --- 648.0 0.008 SV 196 EU 398 Line 7 Cooler Vent Stack --- --- 616.1 0.008 SV 197 

N/A N/A - Total facility fugitive sources --- --- 5,650.4 --- N/A 

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

EU 148

Limestone Transfer

(formerly Ore Transfer From 020-01-1 to Bin 100-01) --- --- 9.6 --- SV 088 

EU 149

Limestone Transfer 

(formerly Ore Transfer From 020-01-1 to Bin 100-02) --- --- Incl with EU148 --- SV 088 

EU 150

Limestone Transfer 

(formerly Ore Transfer From 020-01-1 to Bin 100-03) --- --- Incl with EU148 --- SV 088 

EU 151

Limestone Transfer 

(formerly Ore Transfer From 021-01-1 to 022-01-1) --- --- Incl with EU148 --- SV 088 

EU 152

Limestone Transfer 

(formerly Ore Transfer From 020-01-1 to Bin 100-04) --- --- Incl with EU148 --- SV 088 

EU 153

Limestone Transfer 

(formerly Ore Transfer From 021-02-1 to 022-02-1) --- --- Incl with EU148 --- SV 088 

EU 154

Limestone Transfer 

(formerly Ore Transfer From 020-01-1 to Bin 100-05) --- --- Incl with EU148 --- SV 088 

EU 217 Pekay Mixer --- --- 2.4 --- SV 100 

3.C. Sources of fugitive PM that are subject to MACT standards 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 218 Pekay Mixer --- --- Incl with EU217 --- SV 100 EU 219 Pekay Mixer --- --- Incl with EU217 --- SV 100 EU 220 Pekay Mixer --- --- Incl with EU217 --- SV 100 EU 236 Bentonite Bin --- --- 3.1 --- SV 110 EU 237 Bentonite Bin --- --- Incl with EU236 --- SV 110 

EU 238 Bentonite Bin --- --- Incl with EU236 --- SV 110 

EU 239 Bentonite Day Bin --- --- 0.3 --- SV 111 EU 240 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 

EU 241 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 

EU 242 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 

EU 243 Bentonite Unloading Hopper --- --- 0.1 --- SV 112 EU 244 Bentonite Storage Bin --- --- 3.1 --- SV 113 

EU 245 Bentonite Storage Bin --- --- Incl with EU244 --- SV 113 EU 246 Bentonite Storage Bin --- --- Incl with EU244 --- SV 113 EU 247 Storage Bin --- --- 0.3 --- SV 114 EU 248 Storage Bin --- --- Incl with EU247 --- SV 114 EU 249 Storage Bin --- --- Incl with EU247 --- SV 114 EU 250 Storage Bin --- --- Incl with EU247 --- SV 114 EU 251 Storage Bin --- --- Incl with EU247 --- SV 114 EU 252 Pekay Mixer --- --- 2.9 --- SV 115 EU 253 Pekay Mixer --- --- Incl with EU252 --- SV 115 EU 254 Pekay Mixer --- --- Incl with EU252 --- SV 115 EU 255 Pekay Mixer --- --- Incl with EU252 --- SV 115 EU 256 Pekay Mixer --- --- Incl with EU252 --- SV 115 EU 268 Storage Bin --- --- 0.3 --- SV 123 EU 269 Storage Bin --- --- Incl with EU268 --- SV 123 EU 270 Storage Bin --- --- Incl with EU268 --- SV 123 EU 271 Storage Bin --- --- Incl with EU268 --- SV 123 EU 272 Storage Bin --- --- Incl with EU268 --- SV 123 EU 273 Pekay Mixer --- --- 2.9 --- SV 124 EU 274 Pekay Mixer --- --- Incl with EU273 --- SV 124 EU 275 Pekay Mixer --- --- Incl with EU273 --- SV 124 EU 276 Pekay Mixer --- --- Incl with EU273 --- SV 124 EU 277 Pekay Mixer --- --- Incl with EU273 --- SV 124 EU 297 Bentonite Storage Bin --- --- 3.1 --- SV 139 

EU 298 Bentonite Storage Bin --- --- Incl with EU297 --- SV 139 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 299 Bentonite Storage Bin --- --- Incl with EU297 --- SV 139 EU 300 Bentonite Unloading Hopper --- --- Incl with EU297 --- SV 139 EU 301 Storage Bin --- --- 0.4 --- SV 140 EU 302 Storage Bin --- --- Incl with EU301 --- SV 140 EU 303 Storage Bin --- --- Incl with EU301 --- SV 140 EU 304 Storage Bin --- --- Incl with EU301 --- SV 140 EU 305 Storage Bin --- --- Incl with EU301 --- SV 140 EU 306 Pekay Mixer --- --- 1.6 --- SV 141 EU 307 Pekay Mixer --- --- Incl with EU306 --- SV 141 EU 308 Pekay Mixer --- --- Incl with EU306 --- SV 141 EU 309 Pekay Mixer --- --- Incl with EU306 --- SV 141 EU 310 Pekay Mixer --- --- Incl with EU306 --- SV 141 EU 320 Storage Bin --- --- 0.4 --- SV 147 EU 321 Storage Bin --- --- Incl with EU320 --- SV 147 EU 322 Storage Bin --- --- Incl with EU320 --- SV 147 EU 323 Storage Bin --- --- Incl with EU320 --- SV 147 EU 324 Storage Bin --- --- Incl with EU320 --- SV 147 EU 325 Pekay Mixer --- --- 1.6 --- SV 148 EU 326 Pekay Mixer --- --- Incl with EU325 --- SV 148 EU 327 Pekay Mixer --- --- Incl with EU325 --- SV 148 EU 328 Pekay Mixer --- --- Incl with EU325 --- SV 148 EU 329 Pekay Mixer --- --- Incl with EU325 --- SV 148 EU 367 Coal Unload Hopper --- --- 0.2 --- SV 181 

EU 368 Coal Hopper Conveyor --- --- Incl with EU367 --- SV 181 EU 369 Coal Conv. Feed --- --- Incl with EU367 --- SV 181 

EU 370 Coal Silo Feed --- --- Incl with EU367 --- SV 181 EU 371 Coal Silo Discharge --- --- Incl with EU367 --- SV 181 EU 372 Coal Silo Transfer --- --- Incl with EU367 --- SV 181 EU 373 Coal Silo --- --- Incl with EU367 --- SV 181 

EU 374 Coal Conv. Discharge --- --- 0.2 --- SV 182 

EU 375 Coal Screen --- --- Incl with EU374 --- SV 182 EU 376 Coal Reversing Belt --- --- Incl with EU374 --- SV 182 EU 377 Day Bin Belt Feed --- --- Incl with EU374 --- SV 182 EU 378 Day Bin Belt Discharge --- --- Incl with EU374 --- SV 182 EU 379 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De MinimEU 380 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De Minim
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 381 Coal Day Bin --- --- Incl with EU374 --- SV 182 De MinimEU 382 Coal Day Bin --- --- Incl with EU374 --- SV 182 De Minim

3.E. Other Combustion Units 

EU 001 Utility Plant Heating Boiler #1 193.5 0.4 5.3 --- SV 001

BAR

De Minimis M

EU 002 Utility Plant Heating Boiler #2 719.8 1.5 19.5 --- SV 002

BAR

De Minimis M

EU 003 Utility Plant Heating Boiler #3 105.6 0.2 2.9 --- SV 003

BAR

De Minimis M

EU 004 Utility Plant Heating Boiler #4 230.8 0.5 6.3 --- SV 004

BAR

De Minimis M

EU 005 Utility Plant Heating Boiler #5 226.5 0.5 6.1 --- SV 005

BAR

De Minimis M

EU 006 Utility Plant Diesel Generator 3.1 0.2 0.2 --- SV 006 

EU 008 Utility Plant Diesel Generator 8.4 0.6 0.6 --- SV 008 

EU 009 Utility Plant Diesel Fire Pump 10.9 0.7 0.7 --- SV 009 

EU 010 Mobile Eqp Shop Heating Boiler #1 6.8 0.0 0.2 --- SV 010 De Minimis 

EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 Incl with EU010 --- SV 011 De Minimis EU 012 Mobile Eqp Shop Diesel Generator 2.3 0.2 0.2 --- SV 012 

EU 028 Coarse Crusher Zinc Furnace 3.3 0.0 0.3 --- SV 019 De Minimis MoEU 032 Coarse Crusher Zinc Furnace 0.5 1.4 0.0 --- SV 020 De Minimis MoEU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 Incl with EU032 --- SV 020 De Minimis Mo

EU 051 Crusher Area Diesel Generator 2.0 0.1 0.1 --- SV 029 

EU 142 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Mo

EU 143 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Mo

EU 215 Concentrator Area Diesel Generator 45.0 3.0 3.1 --- SV 098 EU 383 Diesel Generator 15.4 1.0 1.1 --- SV 183 

EU 384 Diesel Generator 19.2 1.3 1.3 --- SV 184 

EU 385 Diesel Generator 6.1 0.4 0.4 --- SV 185 EU 386 Diesel Generator 7.5 0.5 0.5 --- SV 186 
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis

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 A

EU 387 Air Compressor 171.1 11.3 11.8 --- SV 187 De Minimis Mo

* 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

B

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 

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 

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 

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 

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 17000.0 380 AP-42 Emission Factor EU 002 Utility Plant Heating Boiler #2 1.54 719.83 0.00 19.54 SV 002 527612.1358 5268167.191 67.25 1682 4.50 17000.0 380 AP-42 Emission Factor 

EU 003 Utility Plant Heating Boiler #3 0.23 105.64 0.00 2.87 SV 003 527619.1379 5268168.2 67.25 1682 4.50 20800.0 380 AP-42 Emission Factor 

EU 004 Utility Plant Heating Boiler #4 0.49 230.83 0.00 6.27 SV 004 527626.9988 5268169.38 68.59 1682 4.50 25500.0 380 AP-42 Emission Factor 

EU 005 Utility Plant Heating Boiler #5 0.49 226.49 0.00 6.15 SV 005 527633.9031 5268170.379 68.59 1682 4.50 25500.0 380 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 4100.0 380 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 

EU 028 Coarse Crusher Zinc Furnace 0.00 3.29 0.00 0.31 SV 019 527252.4492 5267524.117 32 1732 1.67 36700.0 700 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

1

Ja

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 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 * AP42 Emission Factor

A

o

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 * AP42 Emission Factor

A

o

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 
Table 3-3 De Minimis Visibility Modeling Results

2002 2003 2004 

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

M

BWCA De Minimis 0.040 0 0.034 0 0.029 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

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 17,000 380 AP-42 Emission Factor 

EU 002 Utility Plant Heating Boiler #2 1.54 720 n/a 19.5 SV 002 527612.1358 5268167.191 67.25 1682 4.5 17,000 380 AP-42 Emission Factor EU 003 Utility Plant Heating Boiler #3 0.23 106 n/a 2.9 SV 003 527619.1379 5268168.2 67.25 1682 4.5 20,800 380 AP-42 Emission Factor 

EU 004 Utility Plant Heating Boiler #4 0.49 231 n/a 6.3 SV 004 527626.9988 5268169.38 68.59 1682 4.5 25,500 380 AP-42 Emission Factor 

EU 005 Utility Plant Heating Boiler #5 0.49 226 n/a 6.1 SV 005 527633.9031 5268170.379 68.59 1682 4.5 25,500 380 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 10.4 322,000 130 Stack Test May 2005 

EU 259 Line 4 3192 29520 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115 Stack Test July 2006 

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 

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 

EU 332 Line 7 2520 26232 n/a 1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109 Stack Test June 2002 

Baseline Conditions - Indurating Furnaces - Solid Fuel Burning in Kiln

EU 223 Line 3 3072 12168 n/a 6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130 Stack Test March 1994 

EU 259 Line 4 3192 27360 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115 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 

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 

EU 332 Line 7 4032 19440 n/a 1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109 Stack Test March 1994 
Table 4-2 Baseline Visibility Modeling Results Table 4-2 Baseline Visibility Modeling Results

2002 2003 2004 

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 d

exceedin

decivie

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 

1

Baseline

Indurating Furnaces 

burning 

Solid Fuels

Baseline

Indurating Furnaces 

burning 

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 

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

Wet Walled Electrostatic Precipitator (WWESP)
Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission R

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % 

SV 103 Line 3 30% 2,150 SV 118 Line 4 --- 3,192 SV 127 Line 5 --- 3,192 SV 144 Line 6 --- 2,520 SV 151 Line 7 --- 2,520 SV 103 Line 3 30% 2,150 SV 118 Line 4 --- 3,192 SV 127 Line 5 --- 3,192 SV 144 Line 6 --- 4,032 SV 151 Line 7 --- 4,032 

2 Current Operations

w/ Line 3 Scrubber

Indurating Furnaces Burning 

Nat Gas

Current Operation

w/ line 6 Burners

Indurating Furances Burning 

Nat Gas

3 Current Operations

w/ Line 3 Scrubber

Indurating Furnaces Burning 

Solid Fuel

Current Operation

w/ line 6 Burners

Indurating Furnaces Burning 

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 d

exceedin

decivie

0 Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 

1 Baseline

Indurating Furnaces 

burning 

Solid Fuels

Baseline

Indurating Furnaces 

burning 

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 

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 

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 

Scenario Control Technology 2004

2002 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 6 n/a n/a n/a n/a

Line 7 n/a n/a n/a n/a

Line 3 n/a n/a n/a n/a

Line 4 $1,474,892 $139,219 $768 -$3,673

Line 5 $1,474,892 $139,219 $765 -$3,657

Line 6 n/a n/a n/a n/a

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

Line 6 n/a n/a n/a n/a

Line 7 n/a n/a n/a n/a

Low-NOx Burners

Ported Kilns

Selective Catalytic Reduction (SCR)

Low-NOx Burners + Ported Kilns
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rate

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % Reductio

SV 103 Line 3 --- 2,150 5% SV 118 Line 4 --- 3,192 5% SV 127 Line 5 --- 3,192 5% SV 144 Line 6 --- 2,520 Ports alread

installed 

SV 151 Line 7 --- 2,520 Ports alread

installed 

SV 103 Line 3 --- 2,150

No NOx 

improvemen

on solid fue

SV 118 Line 4 --- 3,192

No NOx 

improvemen

on solid fue

SV 127 Line 5 --- 3,192

No NOx 

improvemen

on solid fue

SV 144 Line 6 --- 4,032

No NOx 

improvemen

on solid fue

SV 151 Line 7 --- 4,032

No NOx 

improvemen

on solid fue

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
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rate

Scenario Control Technology SO2 

Control 

Scenario SV #

Emission 

Unit SO2 NOx % Reduction

Max 24-hour 

lbs/day % Reductio

4

SV 103 Line 3 --- 2,150 low-NOx N

Available 

SV 118 Line 4 --- 3,192 10% SV 127 Line 5 --- 3,192 10% SV 144 Line 6 --- 2,520

low-NOx 

Already 

Installed

SV 151 Line 7 --- 2,520 10% SV 103 Line 3 --- 2,150 low-NOx N

Available 

SV 118 Line 4 --- 3,192 10% SV 127 Line 5 --- 3,192 10% SV 144 Line 6 --- 4,032

low-NOx 

Already 

Installed

SV 151 Line 7 --- 4,032 10% SV 103 Line 3 --- 2,150 5% SV 118 Line 4 --- 3,192 15% SV 127 Line 5 --- 3,192 15% SV 144 Line 6 --- 2,520 0% SV 151 Line 7 --- 2,520 10% SV 103 Line 3 --- 2,150 0% SV 118 Line 4 --- 3,192 10% SV 127 Line 5 --- 3,192 10% SV 144 Line 6 --- 4,032 0% SV 151 Line 7 --- 4,032 10% 

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 

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)

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

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 d

exceedin

decivie

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 

1

Baseline

Indurating Furnaces 

burning 

Solid Fuels

Baseline

Indurating Furnaces 

burning 

Solid Fuels

BWCA 4.780 173 6.377 162 5.260 155 

2

Current Operationsw/ 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 

3

Current Operationsw/ 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 

4

Current Operationsw/ 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

Current Operationsw/ 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 

2002 2003 2004
Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results

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 d

exceedin

decivie

2002 2003 2004

6

Current Operationsw/ 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 

7

Current Operationsw/ 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 

8

Current Operationsw/ 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 

9

Current Operationsw/ 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 
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

Utility Plant Heater Boiler #2 $1,681,680 $304,052 $24,489

Utility Plant Heater Boiler #4 $1,914,641 $343,518 $25,720

Utility Plant Heater Boiler #5 $1,914,641 $343,518 $27,713

Selective Catalytic Reduction (SCR) 

Utility Plant Heater Boiler #1 $4,488,567 $592,165 $50,632

Utility Plant Heater Boiler #2 $4,488,567 $592,165 $52,345

Utility Plant Heater Boiler #4 $5,234,392 $688,384 $56,028

Utility Plant Heater Boiler #5 $5,234,392 $688,384 $60,211

Low NOX Burner / Flue Gas Recirculation

Utility Plant Heater Boiler #1 $1,384,220 $166,560 $15,558

Utility Plant Heater Boiler #2 $1,384,220 $166,560 $16,098

Utility Plant Heater Boiler #4 $1,745,018 $209,678 $18,839

Utility Plant Heater Boiler #5 $1,745,018 $209,678 $20,299

Regenerative Selective Catalytic Reduction (R-SCR)

Utility Plant Heater Boiler #1 $1,690,961 $238,636 $22,879

Utility Plant Heater Boiler #2 $1,690,961 $238,636 $23,638

Utility Plant Heater Boiler #4 $2,156,692 $316,281 $28,633

Utility Plant Heater Boiler #5 $2,156,692 $316,281 $30,710

Low NOX Burner / Overfire Air (OFA)

Utility Plant Heater Boiler #1 $1,131,149 $136,590 $14,282

Utility Plant Heater Boiler #2 $1,131,149 $136,590 $14,778

Utility Plant Heater Boiler #4 $1,425,985 $171,954 $17,294

Utility Plant Heater Boiler #5 $1,425,985 $171,954 $18,634

Low NOX Burner

Utility Plant Heater Boiler #1 $344,269 $47,480 $6,653

Utility Plant Heater Boiler #2 $344,269 $47,480 $6,883

Utility Plant Heater Boiler #4 $434,003 $59,540 $8,024

Utility Plant Heater Boiler #5 $434,003 $59,540 $8,646

Selective Non-Catalytic Reduction (SNCR)

Utility Plant Heater Boiler #1 $1,084,406 $300,018 $42,037

Utility Plant Heater Boiler #2 $1,084,406 $300,018 $43,495

Utility Plant Heater Boiler #4 $1,277,232 $354,613 $47,792

Utility Plant Heater Boiler #5 $1,277,232 $354,613 $51,494
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

SV 001 EU 001 --- 

SV 002 EU 002 --- SV 004 EU 004 --- SV 005 EU 005 --- SV 001 EU 001 50% 

SV 002 EU 002 50% SV 004 EU 004 50% SV 005 EU 005 50% 

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

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 

10

Baseline

Indurating Furnaces 

burning Natural Gas

Utility Plant Heating 

Boilers

Low-NOx Burners

BWCA 5.486 177 7.178 168 5.957 158 

Scenario Control Technology 2002 2003 2004 
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results

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 d

exceeding 

decivie

0

Baseline

Indurating Furnaces 

burning Natural Gas

Baseline

Indurating Furnaces 

burning Natural Gas

BWCA 5.508 177 7.201 168 5.962 160 

1

Baseline

Indurating Furnaces 

burning 

Solid Fuels

Baseline

Indurating Furnaces 

burning 

Solid Fuels

BWCA 4.78 173 6.377 162 5.26 155 

2

Current Operationsw/ 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 

3

Current Operationsw/ 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 

4

Current Operationsw/ 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

Current Operationsw/ 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 

2002 2003 2004
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results

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 d

exceeding 

decivie

2002 2003 2004

6

Current Operationsw/ 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 

7

Current Operationsw/ 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 

8

Current Operationsw/ 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 

9

Current Operationsw/ 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 

10

Baseline

Indurating Furnaces 

burning Natural Gas

Utility Plant Heating 

Boilers

Low-NOx Burners

BWCA 5.486 177 7.178 168 5.957 158 
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 Technology Control 

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

Line 6 n/a n/a n/a n/a n/a n/a n/a

Line 7 n/a n/a n/a n/a n/a n/a n/a

Low NOX Burners

Line 3 n/a n/a n/a n/a n/a n/a n/a

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 6 n/a n/a n/a n/a n/a n/a n/a

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

Line 6 n/a n/a n/a n/a n/a n/a n/a

Line 7 n/a n/a n/a n/a n/a n/a n/a

SO2 Control Cost Summary 

Control Technology Control 

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)

Wet Walled Electrostatic Precipitator (WWESP)

(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

BART Report - Attachment A: Emission Control Cost AnalysisTable A.2 - Summary of Utility, Chemical and Supply Costs

Operating Unit: Line 3 waste gas Study Year 2006

Emission Unit Number EU 223Stack/Vent Number SV 103

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259

Stack/Vent Number SV 118

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280Stack/Vent Number SV 127

Operating Unit: Line 6 waste gas

Emission Unit Number EU 313Stack/Vent Number SV 144

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332Stack/Vent Number SV 151

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 61 $/hr Per Chrissy Bartovich e-mailMaintenance Labor 61 $/hr Per Chrissy Bartovich e-mailElectricity 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 adjusinflation

Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% infl

3 lists $1.30 - $2.15/1,000 gal

Chemicals & SuppliesLime 91.40 $/ton 91.40 2006 Estimate from Cutler-Magney CompanyOxygen 40.00 $/ton 2006 BOC estimate.Ammonia (29% aqua.) 0.12 $/lb 0.101 2000

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4 Chapter 2, page 2-50

Annual costs for a retrofit SCR system example problem. adjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 cost adju

SCR Catalyst 141.00 $/ft3 Cormetech, Inc.

OtherSales 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 InformationAnnual Op. Hrs 7946 Hours Engineering EstimateUtilization Rate 93%Equipment Life 20 yrs Engineering Estimate

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data 
Standardized Flow Rate

SV 103 268,515 scfm @ 32o F Calculated.

SV 118 556,174 scfm @ 32o F Calculated.

SV 127 556,174 scfm @ 32o F Calculated.

SV 144 518,805 scfm @ 32o F Calculated.

SV 151 518,805 scfm @ 32o F Calculated.

TemperatureSV 103 130 Deg F BART spreadsheet.

SV 118 115 Deg F BART spreadsheet.

SV 127 115 Deg F BART spreadsheet.

SV 144 109 Deg F BART spreadsheet.

SV 151 109 Deg F BART spreadsheet.

Moisture ContentSV 103 10.5% Assumed value.SV 118 10.5% Assumed value.SV 127 10.5% Assumed value.SV 144 10.5% Assumed value.SV 151 10.5% Assumed value.Actual Flow RateSV 103 322,000 acfm BART spreadsheet.

SV 118 650,000 acfm BART spreadsheet.

SV 127 650,000 acfm BART spreadsheet.

SV 144 600,000 acfm Same as line 7

SV 151 600,000 acfm BART spreadsheet.

Standardized Flow RateSV 103 288,163 scfm @ 68o F Calculated.

SV 118 596,870 scfm @ 68o F Calculated.

SV 127 596,870 scfm @ 68o F Calculated.

SV 144 556,766 scfm @ 68o F Calculated.

SV 151 556,766 scfm @ 68o F Calculated.

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data 
Dry Std Flow Rate

SV 103 257,906 dscfm @ 68o F Calculated.

SV 118 534,198 dscfm @ 68o F Calculated.

SV 127 534,198 dscfm @ 68o F Calculated.

SV 144 498,306 dscfm @ 68o F Calculated.

SV 151 498,306 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%.SV 118 1353.0 1,812.0 353 108.0 Based on max stack test plus 10% Based on 2005 AEI plus 10%.

SV 127 1353.0 1,820.0 353 108.5 Based on max stack test plus 10% Based on 2005 AEI plus 10%.

SV 144 1202.3 1,776.0 336 113.5 Based on max stack test plus 10% Based on 2005 AEI plus 10%.

SV 151 1202.3 1,928.0 336 123.2 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 ascrubber.

SV 118 146.3 447.5 27 19.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.

SV 127 146.3 447.5 27 19.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.

SV 144 184.8 544.8 37 25.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.

SV 151 184.8 544.8 37 25.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control CostsUtility Chem$ Data 
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 3 waste gas

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 SCR Line3 SCR 5 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 SCR Line3 SCR 6 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat

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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 288,163

Vol #2 4408.7 ft3

Amount Required 4,409 ft

3

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 dscf/MMBtu 77,372

Method 19 Factor dscf/MMBtu 10,000

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 15% of Operator Costs 18,176

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

Utilities, Supplies, Replacements & Waste Management

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 SCR Line3 SCR 7 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 3 waste gas

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

 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

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 Reheat Line3 Reheat 8 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct 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 NA

Installation Total 215,207

Total Direct Capital Cost, DC 932,563

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 71,736

Construction & field expenses 5% of purchased equip cost (B) 35,868

Contractor 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

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380

Total Capital Investment (TCI) = DC + IC 1,154,944

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,154,944

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

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

Total Annual Direct Operating Costs 7,382,105

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 23,099

Property tax (1% total capital costs) 1% of total capital costs (TCI) 11,549

Insurance (1% total capital costs) 1% of total capital costs (TCI) 11,549

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 109,019

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 Reheat Line3 Reheat 9 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 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

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 4,544 15% of Operator Costs

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

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 Reheat Line3 Reheat 10 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 Reheat Line3 Reheat 11 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 4 waste gas

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 23,050,831

 Purchased Equipment Total SCR Only 24,549,135

SCR + Reheat 25,409,745

Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433

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) 1,353.0 1,812.0 80% 362.4 1,449.6 19,433

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 SCR Line4 SCR 12 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,498,304

Freight 5% of control device cost (A) NA

Purchased Equipment Total 24,549,135

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

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

Project Contingeny (C) 15% of (A + B) 4,078,955

Total Plant Cost (D) A + B + C 31,271,989

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)) 625,440

Inventory Capital Reagent Vol * $/gal 158,329

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758

Retrofit Factor (14) 60% of TCI 19,233,455

Sitework and foundations 1,400,000

Structural steel 4,800,000

Total Capital Investment Retrofit Installed 57,489,212

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 480,836

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079

SCR Catalyst 64.71 Catalyst Replacement 400,504

Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919

Total Annual Direct Operating Costs 5,709,691

Indirect Operating Costs

Overhead 60% of total labor and material costs 91,281

Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115

Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558

Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087

Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 SCR Line4 SCR 13 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat

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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 596,870

Vol #2 9131.8 ft3

Amount Required 9,132 ft

3

Catalyst Cost 1,287,579

Y catalyst life factor 3 Years

Annualized Cost 400,504

Equivalent Duty 3,484 Plant Cap kW A 357,359

Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment

Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49

Annual Operating Hrs 8000 Variable O&M F $624,082.60

Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

Electrical Use

Equivalent Duty 3,484 MMBtu/hr kW

NOx Cont Eff 80% Power 1,409.2

NOx in 0.43 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1409.2

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

1353 lb/hr Neat 623.3 gal/hr

29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost

4666 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.428

Actual dscf/MMBtu 106,840

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 3,484 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 480,836 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 SCR Line4 SCR 14 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259 Stack/Vent Number SV 118 Chemical Engineering

Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 115 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 650,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 708,321

 Purchased Equipment Total (B) 22% of control device cost (A) 860,610

 Installation - Standard Costs 30% of purchased equip cost (B) 258,183

 Installation - Site Specific Costs NA

 Installation Total 258,183

 Total Direct Capital Cost, DC 1,118,793

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789

Total Capital Investment (TCI) = DC + IC 1,385,582

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 Reheat Line4 Reheat 15 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 708,321

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 70,832

MN Sales Taxes 6.5% of control device cost (A) 46,041

Freight 5% of control device cost (A) 35,416

Purchased Equipment Total (B) 22% 860,610

Installation

Foundations & supports 8% of purchased equip cost (B) 68,849

Handling & erection 14% of purchased equip cost (B) 120,485

Electrical 4% of purchased equip cost (B) 34,424

Piping 2% of purchased equip cost (B) 17,212

Insulation 1% of purchased equip cost (B) 8,606

Painting 1% of purchased equip cost (B) 8,606

Installation Subtotal Standard Expenses 30% 258,183

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 258,183

Total Direct Capital Cost, DC 1,118,793

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 86,061

Construction & field expenses 5% of purchased equip cost (B) 43,031

Contractor fees 10% of purchased equip cost (B) 86,061

Start-up 2% of purchased equip cost (B) 17,212

Performance test 1% of purchased equip cost (B) 8,606

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,818

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789

Total Capital Investment (TCI) = DC + IC 1,385,582

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618

Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142

Total Annual Direct Operating Costs 15,416,187

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712

Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856

Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 Reheat Line4 Reheat 16 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2408.3

Reagent Use & Other Operating Costs Oxidizers - NA

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 4,544 15% of Operator Costs

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 Reheat Line4 Reheat 17 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 115 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 560 Deg F - Temperature of waste gas out of heat recovery

Tfo 306 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 596,870 scfm - Flow of waste gas 

Qaf 3,511 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076

Current Cost Using CHE Plant Cost Index $708,321

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 Reheat Line4 Reheat 18 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 23,050,831

 Purchased Equipment Total SCR Only 24,549,135

SCR + Reheat 25,409,745

Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433

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) 1,353.0 1,820.0 80% 364.0 1,456.0 19,347

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 SCR Line5 SCR 19 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,498,304

Freight 5% of control device cost (A) NA

Purchased Equipment Total 24,549,135

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

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

Project Contingeny (C) 15% of (A + B) 4,078,955

Total Plant Cost (D) A + B + C 31,271,989

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)) 625,440

Inventory Capital Reagent Vol * $/gal 158,329

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758

Retrofit Factor (14) 60% of TCI 19,233,455

Sitework and foundations 1,400,000

Structural steel 4,800,000

Total Capital Investment Retrofit Installed 57,489,212

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 480,836

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079

SCR Catalyst 64.71 Catalyst Replacement 400,504

Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919

Total Annual Direct Operating Costs 5,709,691

Indirect Operating Costs

Overhead 60% of total labor and material costs 91,281

Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115

Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558

Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087

Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 SCR Line5 SCR 20 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat

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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 596,870

Vol #2 9131.8 ft3

Amount Required 9,132 ft

3

Catalyst Cost 1,287,579

Y catalyst life factor 3 Years

Annualized Cost 400,504

Equivalent Duty 3,484 Plant Cap kW A 357,359

Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35

Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066

Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment

Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49

Annual Operating Hrs 8000 Variable O&M F $624,082.60

Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

SCR Capital Cost

Electrical Use

Duty 3,484 MMBtu/hr kW

NOx Cont Eff 80% Power 1,409.2

NOx in 0.43 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1409.2

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

1353 lb/hr Neat 623.3 gal/hr

29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost

4666 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.428

Actual dscf/MMBtu 106,840

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 3,484 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 480,836 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 SCR Line5 SCR 21 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127 Chemical Engineering

Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 115 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 650,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 708,321

 Purchased Equipment Total (B) 22% of control device cost (A) 860,610

 Installation - Standard Costs 30% of purchased equip cost (B) 258,183

 Installation - Site Specific Costs NA

 Installation Total 258,183

 Total Direct Capital Cost, DC 1,118,793

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789

Total Capital Investment (TCI) = DC + IC 1,385,582

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 Reheat Line5 Reheat 22 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 708,321

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 70,832

MN Sales Taxes 6.5% of control device cost (A) 46,041

Freight 5% of control device cost (A) 35,416

Purchased Equipment Total (B) 22% 860,610

Installation

Foundations & supports 8% of purchased equip cost (B) 68,849

Handling & erection 14% of purchased equip cost (B) 120,485

Electrical 4% of purchased equip cost (B) 34,424

Piping 2% of purchased equip cost (B) 17,212

Insulation 1% of purchased equip cost (B) 8,606

Painting 1% of purchased equip cost (B) 8,606

Installation Subtotal Standard Expenses 30% 258,183

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 258,183

Total Direct Capital Cost, DC 1,118,793

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 86,061

Construction & field expenses 5% of purchased equip cost (B) 43,031

Contractor fees 10% of purchased equip cost (B) 86,061

Start-up 2% of purchased equip cost (B) 17,212

Performance test 1% of purchased equip cost (B) 8,606

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,818

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789

Total Capital Investment (TCI) = DC + IC 1,385,582

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618

Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142

Total Annual Direct Operating Costs 15,416,187

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712

Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856

Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 Reheat Line5 Reheat 23 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2408.3

Reagent Use & Other Operating Costs Oxidizers - NA

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 4,544 15% of Operator Costs

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 Reheat Line5 Reheat 24 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 115 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 560 Deg F - Temperature of waste gas out of heat recovery

Tfo 306 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 596,870 scfm - Flow of waste gas 

Qaf 3,511 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076

Current Cost Using CHE Plant Cost Index $708,321

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 Reheat Line5 Reheat 25 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 6 waste gas

Emission Unit Number EU 313 Stack/Vent Number SV 144

Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 22,013,215

 Purchased Equipment Total SCR Only 23,444,074

SCR + Reheat 24,289,858

Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264

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) 1,202.3 1,776.0 80% 355.2 1,420.8 18,595

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 SCR Line6 SCR 26 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,430,859

Freight 5% of control device cost (A) NA

Purchased Equipment Total 23,444,074

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

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

Project Contingeny (C) 15% of (A + B) 3,913,196

Total Plant Cost (D) A + B + C 30,001,168

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)) 600,023

Inventory Capital Reagent Vol * $/gal 140,694

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886

Retrofit Factor (14) 60% of TCI 18,445,131

Sitework and foundations 1,400,000

Structural steel 4,800,000

Total Capital Investment Retrofit Installed 55,387,017

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 461,128

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304

SCR Catalyst 64.71 Catalyst Replacement 373,594

Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801

Total Annual Direct Operating Costs 5,162,181

Indirect Operating Costs

Overhead 60% of total labor and material costs 87,172

Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838

Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419

Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 SCR Line6 SCR 27 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat

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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 556,766

Vol #2 8518.2 ft3

Amount Required 8,518 ft

3

Catalyst Cost 1,201,067

Y catalyst life factor 3 Years

Annualized Cost 373,594

Equivalent Duty 3,250 Plant Cap kW A 333,349

Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 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 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment

Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22

Annual Operating Hrs 8000 Variable O&M F $586,106.42

Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

SCR Capital Cost

Electrical Use

Duty 3,250 MMBtu/hr kW

NOx Cont Eff 80% Power 1,308.9

NOx in 0.41 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1308.9

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

1202 lb/hr Neat 553.8 gal/hr

29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost

4146 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.408

Actual dscf/MMBtu 99,661

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 3,250 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 461,128 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 SCR Line6 SCR 28 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Line 6 waste gas

Emission Unit Number EU 313 Stack/Vent Number SV 144 Chemical Engineering

Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 109 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 600,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 696,118

 Purchased Equipment Total (B) 22% of control device cost (A) 845,784

 Installation - Standard Costs 30% of purchased equip cost (B) 253,735

 Installation - Site Specific Costs NA

 Installation Total 253,735

 Total Direct Capital Cost, DC 1,099,519

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193

Total Capital Investment (TCI) = DC + IC 1,361,712

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 Reheat Line6 Reheat 29 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 696,118

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 69,612

MN Sales Taxes 6.5% of control device cost (A) 45,248

Freight 5% of control device cost (A) 34,806

Purchased Equipment Total (B) 22% 845,784

Installation

Foundations & supports 8% of purchased equip cost (B) 67,663

Handling & erection 14% of purchased equip cost (B) 118,410

Electrical 4% of purchased equip cost (B) 33,831

Piping 2% of purchased equip cost (B) 16,916

Insulation 1% of purchased equip cost (B) 8,458

Painting 1% of purchased equip cost (B) 8,458

Installation Subtotal Standard Expenses 30% 253,735

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 253,735

Total Direct Capital Cost, DC 1,099,519

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 84,578

Construction & field expenses 5% of purchased equip cost (B) 42,289

Contractor fees 10% of purchased equip cost (B) 84,578

Start-up 2% of purchased equip cost (B) 16,916

Performance test 1% of purchased equip cost (B) 8,458

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,374

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193

Total Capital Investment (TCI) = DC + IC 1,361,712

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802

Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605

Total Annual Direct Operating Costs 14,471,833

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234

Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617

Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 Reheat Line6 Reheat 30 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2223.0

Reagent Use & Other Operating Costs Oxidizers - NA

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 4,544 15% of Operator Costs

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 Reheat Line6 Reheat 31 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 109 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 558 Deg F - Temperature of waste gas out of heat recovery

Tfo 301 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 556,766 scfm - Flow of waste gas 

Qaf 3,298 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841

Current Cost Using CHE Plant Cost Index $696,118

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 Reheat Line6 Reheat 32 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332 Stack/Vent Number SV 151

Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment 22,013,215

 Purchased Equipment Total SCR Only 23,444,074

SCR + Reheat 24,289,858

Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264

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) 1,202.3 1,928.0 80% 385.6 1,542.4 17,129

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

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 SCR Line7 SCR 33 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,430,859

Freight 5% of control device cost (A) NA

Purchased Equipment Total 23,444,074

Indirect Installation

General Facilities 0% of purchased equip cost (A) 0

Engineering & Home Office 0% of purchased equip cost (A) 0

Process Contingency 0% of purchased equip cost (A) 0

Site Specific-Other 11% Replacement Power, two weeks 2,643,899

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

Project Contingeny (C) 15% of (A + B) 3,913,196

Total Plant Cost (D) A + B + C 30,001,168

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)) 600,023

Inventory Capital Reagent Vol * $/gal 140,694

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886

Retrofit Factor (14) 60% of TCI 18,445,131

Sitework and foundations 1,400,000

Structural steel 4,800,000

Total Capital Investment Retrofit Installed 55,387,017

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 461,128

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304

SCR Catalyst 64.71 Catalyst Replacement 373,594

Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801

Total Annual Direct Operating Costs 5,162,181

Indirect Operating Costs

Overhead 60% of total labor and material costs 87,172

Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838

Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419

Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990

Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 SCR Line7 SCR 34 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

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 ft3Cormetech, Inc.

FCW 0.3111 Flow #1 scfm 177,000 Cormetech, Inc.

Rep part cost per unit $141 Flow #2 scfm 556,766

Vol #2 8518.2 ft3

Amount Required 8,518 ft

3

Catalyst Cost 1,201,067

Y catalyst life factor 3 Years

Annualized Cost 373,594

Equivalent Duty 3,250 Plant Cap kW A 333,349

Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 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 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment

Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22

Annual Operating Hrs 8000 Variable O&M F $586,106.42

Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

SCR Capital Cost

Electrical Use

Duty 3,250 MMBtu/hr kW

NOx Cont Eff 80% Power 1,308.9

NOx in 0.41 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1308.9

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

1202 lb/hr Neat 553.8 gal/hr

29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost

4146 lb/hr

Design Basis Max Emis Control Eff (%)

lb/MMBtu 80%

Nitrous Oxides (NOx) 0.408

Actual dscf/MMBtu 99,661

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 3,250 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 461,128 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization

SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement

Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 SCR Line7 SCR 35 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332 Stack/Vent Number SV 151 Chemical Engineering

Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 109 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 600,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 696,118

 Purchased Equipment Total (B) 22% of control device cost (A) 845,784

 Installation - Standard Costs 30% of purchased equip cost (B) 253,735

 Installation - Site Specific Costs NA

 Installation Total 253,735

 Total Direct Capital Cost, DC 1,099,519

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193

Total Capital Investment (TCI) = DC + IC 1,361,712

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 Reheat Line7 Reheat 36 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 696,118

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 69,612

MN Sales Taxes 6.5% of control device cost (A) 45,248

Freight 5% of control device cost (A) 34,806

Purchased Equipment Total (B) 22% 845,784

Installation

Foundations & supports 8% of purchased equip cost (B) 67,663

Handling & erection 14% of purchased equip cost (B) 118,410

Electrical 4% of purchased equip cost (B) 33,831

Piping 2% of purchased equip cost (B) 16,916

Insulation 1% of purchased equip cost (B) 8,458

Painting 1% of purchased equip cost (B) 8,458

Installation Subtotal Standard Expenses 30% 253,735

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 253,735

Total Direct Capital Cost, DC 1,099,519

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 84,578

Construction & field expenses 5% of purchased equip cost (B) 42,289

Contractor fees 10% of purchased equip cost (B) 84,578

Start-up 2% of purchased equip cost (B) 16,916

Performance test 1% of purchased equip cost (B) 8,458

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 25,374

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193

Total Capital Investment (TCI) = DC + IC 1,361,712

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802

Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605

Total Annual Direct Operating Costs 14,471,833

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234

Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617

Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 Reheat Line7 Reheat 37 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 3 years

CRF 0.3811

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2223.0

Reagent Use & Other Operating Costs Oxidizers - NA

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 4,544 15% of Operator Costs

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization

Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 Reheat Line7 Reheat 38 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat

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

Auxiliary Fuel Use Equation 3.19 

Twi 109 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 558 Deg F - Temperature of waste gas out of heat recovery

Tfo 301 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 556,766 scfm - Flow of waste gas 

Qaf 3,298 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841

Current Cost Using CHE Plant Cost Index $696,118

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 Reheat Line7 Reheat 39 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.a: NOX Control - Low-NOX Burners

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259 Stack/Vent Number SV 118

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 1,474,892

Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 139,219

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.b: NOX Control - Low-NOX Burners

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 1,474,892

Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 139,219

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

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 1,820.0 10% 1638.0 182.0 765

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 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

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.4.c: NOX Control - Low-NOX Burners

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332 Stack/Vent Number SV 151

Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 1,200,000

Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 113,272

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Capital Recovery Cost 113,272

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) 1,202.3 1,928.0 10% 1735.2 192.8 588

Sulfur Dioxide (SO2) 184.8 544.8 0% NA NA NA

Notes & Assumptions

1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.a: NOX Control - Ported Kilns

Operating Unit: Line 3 waste gas

Emission Unit Number EU 223 Stack/Vent Number SV 103

Standardized Flow Rate 268,515 scfm @ 32o F

Expected Utilization Rate 93% Temperature 130 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68o F

Dry Std Flow Rate 257,906 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Minntac Line 4/5 Budget Estimate = 5,000,000 $ 

Total Capital Investment (TCI) = DC + IC 3,616,464

Minntac Line 4/5 volumetric flow = 650,000 acfm

Operating Costs(2) Minntac Line 3 volumetric flow = 378,824 acfm

Total Annual Cost (Annualized Capital Cost) 341,369

Use "6/10 Rule" to calculate Line 3 Cost = 3,616,464 $ 

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Capital Recovery Cost 341,369

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Control Eff(3) Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,345.0 876.9 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.

2 Total annualized cost is equal to the annualized capital cost.

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.b: NOX Control - Ported Kilns

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259 Stack/Vent Number SV 118

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000 $ 

Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 471,965

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Capital Recovery Cost 471,965

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Control Eff(3) Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

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.

2 Total annualized cost is equal to the annualized capital cost.

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.5.c: NOX Control - Ported Kilns

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

Size 165 mmbtu/hr

CONTROL EQUIPMENT COSTS

Capital Costs(1)

Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000 $ 

Operating Costs(2)

Total Annual Cost (Annualized Capital Cost) 471,965

Capital Recovery Factor

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Capital Recovery Cost 471,965

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Control Eff(3) Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

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.

2 Total annualized cost is equal to the annualized capital cost.

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

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.a: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 3 waste gas

Emission Unit Number EU 223 Stack/Vent Number SV 103

Standardized Flow Rate 268,515 scfm @ 32o F

Expected Utilization Rate 93% Temperature 130 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm

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

 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 Direct Capital Cost, DC 10,133,707

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810

Total Capital Investment (TCI) = DC + IC 27,948,027

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,023,179

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0 - NA

Sulfur Dioxide (SO2) 329.3 98.6 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

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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Line3 WWESP 9/7/2006 Page 46 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 4,994,311

Instrumentation 10% of control device cost (A) 499,431

MN Sales Taxes 6.5% of control device cost (A) 324,630

Freight 5% of control device cost (A) 249,716

Purchased Equipment Total (B) 22% 6,068,088

Installation

Foundations & supports 4% of purchased equip cost (B) 242,724

Handling & erection 50% of purchased equip cost (B) 3,034,044

Electrical 8% of purchased equip cost (B) 485,447

Piping 1% of purchased equip cost (B) 60,681

Insulation 2% of purchased equip cost (B) 121,362

Painting 2% of purchased equip cost (B) 121,362

Installation Subtotal Standard Expenses 67% 4,065,619

Total Direct Capital Cost, DC 10,133,707

Indirect Capital Costs

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

Start-up 1% of purchased equip cost (B) 60,681

Performance test 1% of purchased equip cost (B) 60,681

Model Studies 2% of purchased equip cost (B) 121,362

Contingencies 3% of purchased equip cost (B) 182,043

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810

Total Capital Investment (TCI) = DC + IC 13,592,517

Retrofit multiplier3

60% of TCI 8,155,510

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 27,948,027

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 Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 6,283

Maintenance Materials 1.00 % of Maintenance Labor 49,943

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,765

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 278,556

Total Annual Direct Operating Costs 2,023,179

Indirect Operating Costs

Overhead 60% of total labor and material costs 117,347

Administration (2% total capital costs) 2% of total capital costs (TCI) 271,850

Property tax (1% total capital costs) 1% of total capital costs (TCI) 135,925

Insurance (1% total capital costs) 1% of total capital costs (TCI) 135,925

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,638,096

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 WWESP 9/7/2006 Page 47 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

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

Reagent Use & Other Operating Costs

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

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

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 Management

Electricity 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

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

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line3 WWESP 9/7/2006 Page 48 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.b: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259 Stack/Vent Number SV 118

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 7,612,198

 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821

 Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,196,710

 Total Direct Capital Cost, DC 15,445,530

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828

Total Capital Investment (TCI) = DC + IC 39,347,773

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NA

Sulfur Dioxide (SO2) 146.3 447.5 80% 89.5 358.0 23,597

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 WWESP 9/7/2006 Page 49 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,612,198

Instrumentation 10% of control device cost (A) 761,220

MN Sales Taxes 6.5% of control device cost (A) 494,793

Freight 5% of control device cost (A) 380,610

Purchased Equipment Total (B) 22% 9,248,821

Installation

Foundations & supports 4% of purchased equip cost (B) 369,953

Handling & erection 50% of purchased equip cost (B) 4,624,410

Electrical 8% of purchased equip cost (B) 739,906

Piping 1% of purchased equip cost (B) 92,488

Insulation 2% of purchased equip cost (B) 184,976

Painting 2% of purchased equip cost (B) 184,976

Installation Subtotal Standard Expenses 67% 6,196,710

Total Direct Capital Cost, DC 15,445,530

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,849,764

Construction & field expenses 20% of purchased equip cost (B) 1,849,764

Contractor fees 10% of purchased equip cost (B) 924,882

Start-up 1% of purchased equip cost (B) 92,488

Performance test 1% of purchased equip cost (B) 92,488

Model Studies 2% of purchased equip cost (B) 184,976

Contingencies 3% of purchased equip cost (B) 277,465

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828

Total Capital Investment (TCI) = DC + IC 20,717,358

Retrofit multiplier3

60% of TCI 12,430,415

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 39,347,773

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 Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683

Maintenance Materials 1.00 % of Maintenance Labor 76,122

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873

Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281

WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799

Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481

Total Annual Direct Operating Costs 3,768,592

Indirect Operating Costs

Overhead 60% of total labor and material costs 136,895

Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347

Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174

Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 WWESP 9/7/2006 Page 50 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

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 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,536.0

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 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

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

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line4 WWESP 9/7/2006 Page 51 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.c: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 7,612,198

 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821

 Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,196,710

 Total Direct Capital Cost, DC 15,445,530

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828

Total Capital Investment (TCI) = DC + IC 39,347,773

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0 - NA

Sulfur Dioxide (SO2) 146.3 447.5 80% 89.5 358.0 23,597

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 WWESP 9/7/2006 Page 52 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,612,198

Instrumentation 10% of control device cost (A) 761,220

MN Sales Taxes 6.5% of control device cost (A) 494,793

Freight 5% of control device cost (A) 380,610

Purchased Equipment Total (B) 22% 9,248,821

Installation

Foundations & supports 4% of purchased equip cost (B) 369,953

Handling & erection 50% of purchased equip cost (B) 4,624,410

Electrical 8% of purchased equip cost (B) 739,906

Piping 1% of purchased equip cost (B) 92,488

Insulation 2% of purchased equip cost (B) 184,976

Painting 2% of purchased equip cost (B) 184,976

Installation Subtotal Standard Expenses 67% 6,196,710

Total Direct Capital Cost, DC 15,445,530

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,849,764

Construction & field expenses 20% of purchased equip cost (B) 1,849,764

Contractor fees 10% of purchased equip cost (B) 924,882

Start-up 1% of purchased equip cost (B) 92,488

Performance test 1% of purchased equip cost (B) 92,488

Model Studies 2% of purchased equip cost (B) 184,976

Contingencies 3% of purchased equip cost (B) 277,465

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828

Total Capital Investment (TCI) = DC + IC 20,717,358

Retrofit multiplier3

60% of TCI 12,430,415

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 39,347,773

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 Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683

Maintenance Materials 1.00 % of Maintenance Labor 76,122

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873

Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281

WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799

Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481

Total Annual Direct Operating Costs 3,768,592

Indirect Operating Costs

Overhead 60% of total labor and material costs 136,895

Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347

Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174

Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 WWESP 9/7/2006 Page 53 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

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 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,536.0

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 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

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

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line5 WWESP 9/7/2006 Page 54 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.d: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 6 waste gas

Emission Unit Number EU 313 Stack/Vent Number SV 144

Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 6,928,558

 Purchased Equipment Total (B) 22% of control device cost (A) 8,418,198

 Installation - Standard Costs 67% of purchased equip cost (B) 5,640,193

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,640,193

 Total Direct Capital Cost, DC 14,058,391

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373

Total Capital Investment (TCI) = DC + IC 36,370,821

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,620,521

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0 - NA

Sulfur Dioxide (SO2) 184.8 544.8 80% 109.0 435.9 18,216

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 WWESP 9/7/2006 Page 55 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 6,928,558

Instrumentation 10% of control device cost (A) 692,856

MN Sales Taxes 6.5% of control device cost (A) 450,356

Freight 5% of control device cost (A) 346,428

Purchased Equipment Total (B) 22% 8,418,198

Installation

Foundations & supports 4% of purchased equip cost (B) 336,728

Handling & erection 50% of purchased equip cost (B) 4,209,099

Electrical 8% of purchased equip cost (B) 673,456

Piping 1% of purchased equip cost (B) 84,182

Insulation 2% of purchased equip cost (B) 168,364

Painting 2% of purchased equip cost (B) 168,364

Installation Subtotal Standard Expenses 67% 5,640,193

Total Direct Capital Cost, DC 14,058,391

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,683,640

Construction & field expenses 20% of purchased equip cost (B) 1,683,640

Contractor fees 10% of purchased equip cost (B) 841,820

Start-up 1% of purchased equip cost (B) 84,182

Performance test 1% of purchased equip cost (B) 84,182

Model Studies 2% of purchased equip cost (B) 168,364

Contingencies 3% of purchased equip cost (B) 252,546

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373

Total Capital Investment (TCI) = DC + IC 18,856,763

Retrofit multiplier3

60% of TCI 11,314,058

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 36,370,821

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 Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 10,842

Maintenance Materials 1.00 % of Maintenance Labor 69,286

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization 526,675

Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413

WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661

Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292

Total Annual Direct Operating Costs 3,620,521

Indirect Operating Costs

Overhead 60% of total labor and material costs 131,688

Administration (2% total capital costs) 2% of total capital costs (TCI) 377,135

Property tax (1% total capital costs) 1% of total capital costs (TCI) 188,568

Insurance (1% total capital costs) 1% of total capital costs (TCI) 188,568

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,433,148

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 WWESP 9/7/2006 Page 56 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

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 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 131,418 255.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,397.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 15.0 hr/wk 660 10,842 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 69,286 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1397.5 kW-hr 10,326,966 526,675 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization

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

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line6 WWESP 9/7/2006 Page 57 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.e: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332 Stack/Vent Number SV 151

Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 7,255,257

 Purchased Equipment Total (B) 22% of control device cost (A) 8,815,138

 Installation - Standard Costs 67% of purchased equip cost (B) 5,906,142

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,906,142

 Total Direct Capital Cost, DC 14,721,280

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628

Total Capital Investment (TCI) = DC + IC 37,793,453

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,632,323

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0 - NA

Sulfur Dioxide (SO2) 184.8 544.8 80% 109.0 435.9 18,638

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.

2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm

3 CUECost Workbook Version 1.0, USEPA Document Page 2

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 WWESP 9/7/2006 Page 58 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,255,257

Instrumentation 10% of control device cost (A) 725,526

MN Sales Taxes 6.5% of control device cost (A) 471,592

Freight 5% of control device cost (A) 362,763

Purchased Equipment Total (B) 22% 8,815,138

Installation

Foundations & supports 4% of purchased equip cost (B) 352,606

Handling & erection 50% of purchased equip cost (B) 4,407,569

Electrical 8% of purchased equip cost (B) 705,211

Piping 1% of purchased equip cost (B) 88,151

Insulation 2% of purchased equip cost (B) 176,303

Painting 2% of purchased equip cost (B) 176,303

Installation Subtotal Standard Expenses 67% 5,906,142

Total Direct Capital Cost, DC 14,721,280

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 1,763,028

Construction & field expenses 20% of purchased equip cost (B) 1,763,028

Contractor fees 10% of purchased equip cost (B) 881,514

Start-up 1% of purchased equip cost (B) 88,151

Performance test 1% of purchased equip cost (B) 88,151

Model Studies 2% of purchased equip cost (B) 176,303

Contingencies 3% of purchased equip cost (B) 264,454

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628

Total Capital Investment (TCI) = DC + IC 19,745,908

Retrofit multiplier3

60% of TCI 11,847,545

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific NA

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 37,793,453

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 Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 11,707

Maintenance Materials 1.00 % of Maintenance Labor 72,553

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization 534,344

Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413

WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661

Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292

Total Annual Direct Operating Costs 3,632,323

Indirect Operating Costs

Overhead 60% of total labor and material costs 134,168

Administration (2% total capital costs) 2% of total capital costs (TCI) 394,918

Property tax (1% total capital costs) 1% of total capital costs (TCI) 197,459

Insurance (1% total capital costs) 1% of total capital costs (TCI) 197,459

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,567,435

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439

Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 WWESP 9/7/2006 Page 59 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Parts & Equipment:

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 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 141,907 275.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,417.8

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 7,946

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Supervisor 15% of Op. NA 18,176 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 15.0 hr/wk 660 11,707 $/Hr, 15.0 hr/wk, 7946 hr/yr

Maint Mtls 1 % of Purchase Cost NA 72,553 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1417.8 kW-hr 10,477,342 534,344 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization

Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization

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

See summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs

Line7 WWESP 9/7/2006 Page 60 of 75
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.a: SO2 Control - Wet Scrubber

Operating Unit: Line 3 waste gas

Emission Unit Number EU 223 Stack/Vent Number SV 103

Standardized Flow Rate 268,515 scfm @ 32o F

Expected Utilization Rate 93% Temperature 130 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm

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

 Purchased Equipment (A) 3,453,270

 Purchased Equipment Total (B) 22% of control device cost (A) 4,195,723

 Installation - Standard Costs 85% of purchased equip cost (B) 3,566,365

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,566,365

 Total Direct Capital Cost, DC 7,762,088

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358

Total Capital Investment (TCI) = DC + IC 19,626,314

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 570,934

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

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.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

Line3 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.a: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,453,270

Instrumentation 10% of control device cost (A) 345,327

MN Sales Taxes 6.5% of control device cost (A) 224,463

Freight 5% of control device cost (A) 172,663

Purchased Equipment Total (B) 22% 4,195,723

Installation

Foundations & supports 12% of purchased equip cost (B) 503,487

Handling & erection 40% of purchased equip cost (B) 1,678,289

Electrical 1% of purchased equip cost (B) 41,957

Piping 30% of purchased equip cost (B) 1,258,717

Insulation 1% of purchased equip cost (B) 41,957

Painting 1% of purchased equip cost (B) 41,957

Installation Subtotal Standard Expenses 85% 3,566,365

Total Direct Capital Cost, DC 7,762,088

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 209,786

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 209,786

Start-up 1% of purchased equip cost (B) 41,957

Performance test 1% of purchased equip cost (B) 41,957

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 125,872

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358

Total Capital Investment (TCI) = DC + IC 8,391,446

Retrofit multiplier560% of TCI 5,034,868

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 19,626,314

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization 249,567

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 32,037

Total Annual Direct Operating Costs 570,934

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 167,829

Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,914

Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,914

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,852,585

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433

See Summary page for notes and assumptions

Line3 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.a: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing 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 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, 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 kW

Circ 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

Reagent Use & Other Operating Costs

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 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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

Line3 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.b: SO2 Control - Wet Scrubber

Operating Unit: Line 4 waste gas

Emission Unit Number EU 259 Stack/Vent Number SV 118

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,263,384

 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011

 Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,435,759

 Total Direct Capital Cost, DC 11,830,771

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252

Total Capital Investment (TCI) = DC + IC 26,664,036

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NA

Sulfur Dioxide (SO2) 146.3 447.5 60% 179.0 268.5 15,358

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

Line4 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.b: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384

Instrumentation 10% of control device cost (A) 526,338

MN Sales Taxes 7% of control device cost (A) 342,120

Freight 5% of control device cost (A) 263,169

Purchased Equipment Total (B) 22% 6,395,011

Installation

Foundations & supports 12% of purchased equip cost (B) 767,401

Handling & erection 40% of purchased equip cost (B) 2,558,004

Electrical 1% of purchased equip cost (B) 63,950

Piping 30% of purchased equip cost (B) 1,918,503

Insulation 1% of purchased equip cost (B) 63,950

Painting 1% of purchased equip cost (B) 63,950

Installation Subtotal Standard Expenses 85% 5,435,759

Total Direct Capital Cost, DC 11,830,771

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 319,751

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 319,751

Start-up 1% of purchased equip cost (B) 63,950

Performance test 1% of purchased equip cost (B) 63,950

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 191,850

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252

Total Capital Investment (TCI) = DC + IC 12,790,022

Retrofit multiplier560% of TCI 7,674,013

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 26,664,036

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785

Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634

WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785

Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555

Total Annual Direct Operating Costs 1,038,186

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800

Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900

Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

See Summary page for notes and assumptions

Line4 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.b: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing 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 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 650,000 8.55 0.7 - 928.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 24,700 gpm 1 60 0.7 - 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 610 gpm 1 60 0.7 - 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1336.7

Reagent Use & Other Operating Costs

Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic

Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 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

24,700 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 610 gpm

Evaporation Loss4

 = 115.90 gpm

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization

Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line4 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.c: SO2 Control - Wet Scrubber

Operating Unit: Line 5 waste gas

Emission Unit Number EU 280 Stack/Vent Number SV 127

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

Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68o F

Dry Std Flow Rate 534,198 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,263,384

 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011

 Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,435,759

 Total Direct Capital Cost, DC 11,830,771

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252

Total Capital Investment (TCI) = DC + IC 26,664,036

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0 - NA

Sulfur Dioxide (SO2) 146.3 447.5 60% 179.0 268.5 15,358

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

Line5 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.c: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384

Instrumentation 10% of control device cost (A) 526,338

MN Sales Taxes 7% of control device cost (A) 342,120

Freight 5% of control device cost (A) 263,169

Purchased Equipment Total (B) 22% 6,395,011

Installation

Foundations & supports 12% of purchased equip cost (B) 767,401

Handling & erection 40% of purchased equip cost (B) 2,558,004

Electrical 1% of purchased equip cost (B) 63,950

Piping 30% of purchased equip cost (B) 1,918,503

Insulation 1% of purchased equip cost (B) 63,950

Painting 1% of purchased equip cost (B) 63,950

Installation Subtotal Standard Expenses 85% 5,435,759

Total Direct Capital Cost, DC 11,830,771

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 319,751

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 319,751

Start-up 1% of purchased equip cost (B) 63,950

Performance test 1% of purchased equip cost (B) 63,950

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 191,850

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252

Total Capital Investment (TCI) = DC + IC 12,790,022

Retrofit multiplier560% of TCI 7,674,013

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 26,664,036

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785

Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634

WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785

Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555

Total Annual Direct Operating Costs 1,038,186

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800

Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900

Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939

See Summary page for notes and assumptions

Line5 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.c: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing 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 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 650,000 8.55 0.7 - 928.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 24,700 gpm 1 60 0.7 - 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 610 gpm 1 60 0.7 - 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1336.7

Reagent Use & Other Operating Costs

Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic

Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 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

24,700 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 610 gpm

Evaporation Loss4

 = 115.90 gpm

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization

Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line5 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.d: SO2 Control - Wet Scrubber

Operating Unit: Line 6 waste gas

Emission Unit Number EU 313 Stack/Vent Number SV 144

Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,016,580

 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145

 Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,180,873

 Total Direct Capital Cost, DC 11,276,018

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272

Total Capital Investment (TCI) = DC + IC 25,704,464

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0 - NA

Sulfur Dioxide (SO2) 184.8 544.8 60% 217.9 326.9 12,093

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

Line6 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.d: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580

Instrumentation 10% of control device cost (A) 501,658

MN Sales Taxes 7% of control device cost (A) 326,078

Freight 5% of control device cost (A) 250,829

Purchased Equipment Total (B) 22% 6,095,145

Installation

Foundations & supports 12% of purchased equip cost (B) 731,417

Handling & erection 40% of purchased equip cost (B) 2,438,058

Electrical 1% of purchased equip cost (B) 60,951

Piping 30% of purchased equip cost (B) 1,828,543

Insulation 1% of purchased equip cost (B) 60,951

Painting 1% of purchased equip cost (B) 60,951

Installation Subtotal Standard Expenses 85% 5,180,873

Total Direct Capital Cost, DC 11,276,018

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 304,757

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 304,757

Start-up 1% of purchased equip cost (B) 60,951

Performance test 1% of purchased equip cost (B) 60,951

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 182,854

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272

Total Capital Investment (TCI) = DC + IC 12,190,290

Retrofit multiplier560% of TCI 7,314,174

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 25,704,464

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032

Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970

WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340

Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069

Total Annual Direct Operating Costs 981,838

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806

Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903

Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

See Summary page for notes and assumptions

Line6 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.d: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing 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 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 600,000 8.55 0.7 - 857.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 22,800 gpm 1 60 0.7 - 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 563 gpm 1 60 0.7 - 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1233.9

Reagent Use & Other Operating Costs

Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic

Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 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

22,800 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 563 gpm

Evaporation Loss4

 = 106.99 gpm

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization

Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line6 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.e: SO2 Control - Wet Scrubber

Operating Unit: Line 7 waste gas

Emission Unit Number EU 332 Stack/Vent Number SV 151

Standardized Flow Rate 518,805 scfm @ 32o F

Expected Utilization Rate 93% Temperature 109 Deg F

Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%

Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68o F

Dry Std Flow Rate 498,306 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,016,580

 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145

 Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873

 Installation - Site Specific Costs 6,200,000

 Installation Total 5,180,873

 Total Direct Capital Cost, DC 11,276,018

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272

Total Capital Investment (TCI) = DC + IC 25,704,464

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

Actual

Emission Control Cost Calculation Emis

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0 - NA

Sulfur Dioxide (SO2) 184.8 544.8 60% 217.9 326.9 12,093

Notes & Assumptions

1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 

2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf

3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate

4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.

5 CUECost Workbook Version 1.0, USEPA Document Page 2

Line7 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.e: SO2 Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580

Instrumentation 10% of control device cost (A) 501,658

MN Sales Taxes 7% of control device cost (A) 326,078

Freight 5% of control device cost (A) 250,829

Purchased Equipment Total (B) 22% 6,095,145

Installation

Foundations & supports 12% of purchased equip cost (B) 731,417

Handling & erection 40% of purchased equip cost (B) 2,438,058

Electrical 1% of purchased equip cost (B) 60,951

Piping 30% of purchased equip cost (B) 1,828,543

Insulation 1% of purchased equip cost (B) 60,951

Painting 1% of purchased equip cost (B) 60,951

Installation Subtotal Standard Expenses 85% 5,180,873

Total Direct Capital Cost, DC 11,276,018

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 304,757

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 304,757

Start-up 1% of purchased equip cost (B) 60,951

Performance test 1% of purchased equip cost (B) 60,951

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 182,854

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272

Total Capital Investment (TCI) = DC + IC 12,190,290

Retrofit multiplier560% of TCI 7,314,174

Sitework and foundations Site Specific 1,400,000

Structural steel Site Specific 4,800,000

Site Specific - Other Site Specific 0

Total Site Specific Costs 6,200,000

Total Capital Investment (TCI) Retrofit Installed 25,704,464

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Supervisor 15% 15% of Operator Costs 4,544

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294

Maintenance Materials 100% of maintenance labor costs 30,294

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032

Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970

WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340

Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069

Total Annual Direct Operating Costs 981,838

Indirect Operating Costs

Overhead 60% of total labor and material costs 57,256

Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806

Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903

Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025

See Summary page for notes and assumptions

Line7 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost Analysis

Table A.7.e: SO2 Control - Wet Scrubber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 20 years

CRF 0.0000

Rep part cost per unit 0 $/ft3

Amount Required 0 ft3

Packing 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 0.00 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 600,000 8.55 0.7 - 857.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 22,800 gpm 1 60 0.7 - 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 563 gpm 1 60 0.7 - 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1233.9

Reagent Use & Other Operating Costs

Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic

Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 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

22,800 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 563 gpm

Evaporation Loss4

 = 106.99 gpm

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 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 4,544

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization

Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization

WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization

Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization

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

See Summary page for notes and assumptions

Line7 Wet Scrubber
US Steel - Minntac

BART Report - Attachment A: Emission Control Cost AnalysisTable A.8: Utility Plant Heater Boilers Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/to

Low Temperature Oxidation (LoTOx)Utility Plant Heater Boiler #1 90% 1.43 12.85 $1,681,680 $304,052 $23,668Utility Plant Heater Boiler #2 90% 1.38 12.42 $1,681,680 $304,052 $24,489Utility Plant Heater Boiler #4 90% 1.48 13.36 $1,914,641 $343,518 $25,720Utility Plant Heater Boiler #5 90% 1.38 12.40 $1,914,641 $343,518 $27,713

Selective Catalytic Reduction (SCR) Utility Plant Heater Boiler #1 80% 2.92 11.70 $4,488,567 $592,165 $50,632

Utility Plant Heater Boiler #2 80% 2.83 11.31 $4,488,567 $592,165 $52,345Utility Plant Heater Boiler #4 80% 3.07 12.29 $5,234,392 $688,384 $56,028Utility Plant Heater Boiler #5 80% 2.86 11.43 $5,234,392 $688,384 $60,211

Low NOX Burner / Flue Gas Recirculation

Utility Plant Heater Boiler #1 75% 3.57 10.71 $1,384,220 $166,560 $15,558

Utility Plant Heater Boiler #2 75% 3.45 10.35 $1,384,220 $166,560 $16,098Utility Plant Heater Boiler #4 75% 3.71 11.13 $1,745,018 $209,678 $18,839Utility Plant Heater Boiler #5 75% 3.44 10.33 $1,745,018 $209,678 $20,299

Regenerative Selective Catalytic Reduction (R-SCR)Utility Plant Heater Boiler #1 70% 4.47 10.43 $1,690,961 $238,636 $22,879

Utility Plant Heater Boiler #2 70% 4.33 10.10 $1,690,961 $238,636 $23,638Utility Plant Heater Boiler #4 70% 4.73 11.05 $2,156,692 $316,281 $28,633Utility Plant Heater Boiler #5 70% 4.41 10.30 $2,156,692 $316,281 $30,710

Low NOX Burner / Overfire Air (OFA)

Utility Plant Heater Boiler #1 67% 4.71 9.56 $1,131,149 $136,590 $14,282

Utility Plant Heater Boiler #2 67% 4.55 9.24 $1,131,149 $136,590 $14,778Utility Plant Heater Boiler #4 67% 4.90 9.94 $1,425,985 $171,954 $17,294Utility Plant Heater Boiler #5 67% 4.55 9.23 $1,425,985 $171,954 $18,634

Low NOX Burner

Utility Plant Heater Boiler #1 50% 7.14 7.14 $344,269 $47,480 $6,653

Utility Plant Heater Boiler #2 50% 6.90 6.90 $344,269 $47,480 $6,883Utility Plant Heater Boiler #4 50% 7.42 7.42 $434,003 $59,540 $8,024Utility Plant Heater Boiler #5 50% 6.89 6.89 $434,003 $59,540 $8,646Selective Non-Catalytic Reduction (SNCR)Utility Plant Heater Boiler #1 50% 7.14 7.14 $1,084,406 $300,018 $42,037Utility Plant Heater Boiler #2 50% 6.90 6.90 $1,084,406 $300,018 $43,495Utility Plant Heater Boiler #4 50% 7.42 7.42 $1,277,232 $354,613 $47,792Utility Plant Heater Boiler #5 50% 6.89 6.89 $1,277,232 $354,613 $51,494

P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Cost Summary Cost Summary 
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

Emission Unit Number EU 001

Stack/Vent Number SV 001

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002

Stack/Vent Number SV 002

Operating Unit: Utility Plant Heater Boiler #3

Emission Unit Number EU 003

Stack/Vent Number SV 003

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004

Stack/Vent Number SV 004

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005

Stack/Vent Number SV 005

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

EPA Air Pollution Control Cost Manual 6th Ed 

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

EPA Air Pollution Control Cost Manual 6th Ed 

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

EPA Air Pollution Control Cost Manual 6th Ed 

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

EPA Air Pollution Control Cost Manual 6th Ed 

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 

SCR Catalyst 141.00 $/ft3 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

Utility Plant Heater Boiler #2 3,156 Hours

Utility Plant Heater Boiler #3 3,156 Hours

Utility Plant Heater Boiler #4 3,156 Hours

Utility Plant Heater Boiler #5 3,156 Hours

Utilization Rate

Utility Plant Heater Boiler #1 28%

Average actual utilization rate based on 2004 

and 2005 emission inventories

Utility Plant Heater Boiler #2 28%

Utility Plant Heater Boiler #3 28%

Utility Plant Heater Boiler #4 28%

Utility Plant Heater Boiler #5 28%

Equipment Life 20 yrs Engineering Estimate

Desgin Capacity

Utility Plant Heater Boiler #1 104 MMBtu/hr

Utility Plant Heater Boiler #2 104 MMBtu/hr

Utility Plant Heater Boiler #3 125 MMBtu/hr

Utility Plant Heater Boiler #4 153 MMBtu/hr

Utility Plant Heater Boiler #5 153 MMBtu/hr

Standardized Flow Rate

Utility Plant Heater Boiler #1 11,005 scfm @ 32o F

Utility Plant Heater Boiler #2 11,005 scfm @ 32o F

Utility Plant Heater Boiler #3 13,465 scfm @ 32o F

Utility Plant Heater Boiler #4 16,508 scfm @ 32o F

Utility Plant Heater Boiler #5 16,508 scfm @ 32o F

Temperature

Utility Plant Heater Boiler #1 380 Deg F

Utility Plant Heater Boiler #2 380 Deg F

Utility Plant Heater Boiler #3 380 Deg F

Utility Plant Heater Boiler #4 380 Deg F

Utility Plant Heater Boiler #5 380 Deg F

Moisture Content

Utility Plant Heater Boiler #1 13.3%

Utility Plant Heater Boiler #2 13.3%

Utility Plant Heater Boiler #3 13.3%

Utility Plant Heater Boiler #4 13.3%

Utility Plant Heater Boiler #5 13.3%

Actual Flow Rate

Utility Plant Heater Boiler #1 17,000 acfm

Utility Plant Heater Boiler #2 17,000 acfm

Utility Plant Heater Boiler #3 20,800 acfm

Utility Plant Heater Boiler #4 25,500 acfm

Utility Plant Heater Boiler #5 25,500 acfm

Standardized Flow Rate

Utility Plant Heater Boiler #1 11,811 scfm @ 68o F

Utility Plant Heater Boiler #2 11,811 scfm @ 68o F

Utility Plant Heater Boiler #3 14,451 scfm @ 68o F

Utility Plant Heater Boiler #4 17,716 scfm @ 68o F

Utility Plant Heater Boiler #5 17,716 scfm @ 68o F

Dry Std Flow Rate

Utility Plant Heater Boiler #1 10,240 dscfm @ 68o F

Utility Plant Heater Boiler #2 10,240 dscfm @ 68o F

Utility Plant Heater Boiler #3 12,529 dscfm @ 68o F

Utility Plant Heater Boiler #4 15,360 dscfm @ 68o F

Utility Plant Heater Boiler #5 15,360 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

Utility Plant Heater Boiler #2 13.8 0.03 29.2 0.28

Utility Plant Heater Boiler #3 1.7 0.00 34.9 0.28

Utility Plant Heater Boiler #4 14.8 0.02 42.9 0.28

Utility Plant Heater Boiler #5 13.8 0.02 42.9 0.28

Max emissions based on limited potential 

emissions as reported in the BART 

spreadsheet. Baseline emissions are based 

on 2005 emission inventory.

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

Utility Chem$ Data Utility Chem$ Data 2 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 768,944

 Purchased Equipment Total (B) 22% of control device cost (A) 934,267

 Installation - Standard Costs 45% of purchased equip cost (B) 420,420

 Total Direct Capital Cost, DC 1,354,687

 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

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.

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 LoTOx #1 LoTOx 3 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS

Direct 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

MN Sales Taxes 6.5% of control device cost (A) 49,981

Freight 5% of control device cost (A) 38,447

Purchased Equipment Total (B) 22% 934,267

Installation

Foundations & supports 12% of purchased equip cost (B) 112,112

Handling & erection(2) 0% of purchased equip cost (B) 0

Electrical 1% of purchased equip cost (B) 9,343

Piping 30% of purchased equip cost (B) 280,280

Insulation 1% of purchased equip cost (B) 9,343

Painting 1% of purchased equip cost (B) 9,343

Installation Subtotal Standard Expenses 45% 420,420

Total Direct Capital Cost, DC 1,354,687

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 93,427

Construction & field expenses 10% of purchased equip cost (B) 93,427

Contractor fees 10% of purchased equip cost (B) 93,427

Start-up 1% of purchased equip cost (B) 9,343

Performance test 1% of purchased equip cost (B) 9,343

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 28,028

Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534

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

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634

Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817

Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

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 LoTOx #1 LoTOx 4 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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

Reagent Use & Other Operating Costs

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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

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 LoTOx #1 LoTOx 5 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 768,944

 Purchased Equipment Total (B) 22% of control device cost (A) 934,267

 Installation - Standard Costs 45% of purchased equip cost (B) 420,420

 Total Direct Capital Cost, DC 1,354,687

 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 13.8 90% 1.4 12.4 24,489

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.

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

#2 LoTOx #2 LoTOx 6 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS

Direct 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

MN Sales Taxes 6.5% of control device cost (A) 49,981

Freight 5% of control device cost (A) 38,447

Purchased Equipment Total (B) 22% 934,267

Installation

Foundations & supports 12% of purchased equip cost (B) 112,112

Handling & erection(2) 0% of purchased equip cost (B) 0

Electrical 1% of purchased equip cost (B) 9,343

Piping 30% of purchased equip cost (B) 280,280

Insulation 1% of purchased equip cost (B) 9,343

Painting 1% of purchased equip cost (B) 9,343

Installation Subtotal Standard Expenses 45% 420,420

Installation Total

Total Direct Capital Cost, DC 1,354,687

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 93,427

Construction & field expenses 10% of purchased equip cost (B) 93,427

Contractor fees 10% of purchased equip cost (B) 93,427

Start-up 1% of purchased equip cost (B) 9,343

Performance test 1% of purchased equip cost (B) 9,343

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 28,028

Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993

Total Capital Investment (TCI) = DC + IC 1,681,680

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534

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

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634

Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817

Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747

Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052

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

#2 LoTOx #2 LoTOx 7 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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

Reagent Use & Other Operating Costs

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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

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

#2 LoTOx #2 LoTOx 8 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 875,464

 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689

 Installation - Standard Costs 45% of purchased equip cost (B) 478,660

 Total Direct Capital Cost, DC 1,542,349

 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 14.8 90% 1.5 13.4 25,720

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.

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

#4 LoTOx #4 LoTOx 9 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)(1)

Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464

Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546

MN Sales Taxes 6.5% of control device cost (A) 56,905

Freight 5% of control device cost (A) 43,773

Purchased Equipment Total (B) 22% 1,063,689

Installation

Foundations & supports 12% of purchased equip cost (B) 127,643

Handling & erection(2) 0% of purchased equip cost (B) 0

Electrical 1% of purchased equip cost (B) 10,637

Piping 30% of purchased equip cost (B) 319,107

Insulation 1% of purchased equip cost (B) 10,637

Painting 1% of purchased equip cost (B) 10,637

Installation Subtotal Standard Expenses 45% 478,660

Total Direct Capital Cost, DC 1,542,349

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 106,369

Construction & field expenses 10% of purchased equip cost (B) 106,369

Contractor fees 10% of purchased equip cost (B) 106,369

Start-up 1% of purchased equip cost (B) 10,637

Performance test 1% of purchased equip cost (B) 10,637

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 31,911

Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535

Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737

Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289

Total Annual Direct Operating Costs 63,463

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293

Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146

Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

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

#4 LoTOx #4 LoTOx 10 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 25,500 No extra load on blower

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 189 gpm No extra load on circulation pump

H2O WW Disch 3 gpm No extra load on discharge pump

kW-hr

LoTOx Electric Use 4 kW/lb O3 278 per estimate from PCI Wedeco

Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2

Total 278

Reagent Use & Other Operating Costs

Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC

Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2

Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco

Circulating Water Rate 189.4 gpm

Water Makeup Rate 8.7 gpm

WW Discharge (blowdown) 3.2 gpm

Nitrate loading (as NaNO3) in scrubber water 71 lb/hr NaNO3

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization

Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization

Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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

#4 LoTOx #4 LoTOx 11 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 875,464

 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689

 Installation - Standard Costs 45% of purchased equip cost (B) 478,660

 Total Direct Capital Cost, DC 1,542,349

 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 13.8 90% 1.4 12.4 27,713

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.

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

#5 LoTOx #5 LoTOx 12 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)(1)

Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464

Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546

MN Sales Taxes 6.5% of control device cost (A) 56,905

Freight 5% of control device cost (A) 43,773

Purchased Equipment Total (B) 22% 1,063,689

Installation

Foundations & supports 12% of purchased equip cost (B) 127,643

Handling & erection(2) 0% of purchased equip cost (B) 0

Electrical 1% of purchased equip cost (B) 10,637

Piping 30% of purchased equip cost (B) 319,107

Insulation 1% of purchased equip cost (B) 10,637

Painting 1% of purchased equip cost (B) 10,637

Installation Subtotal Standard Expenses 45% 478,660

Total Direct Capital Cost, DC 1,542,349

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 106,369

Construction & field expenses 10% of purchased equip cost (B) 106,369

Contractor fees 10% of purchased equip cost (B) 106,369

Start-up 1% of purchased equip cost (B) 10,637

Performance test 1% of purchased equip cost (B) 10,637

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 31,911

Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291

Total Capital Investment (TCI) = DC + IC 1,914,641

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535

Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737

Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289

Total Annual Direct Operating Costs 63,463

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293

Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146

Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055

Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518

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

#5 LoTOx #5 LoTOx 13 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Scrubber 25,500 No extra load on blower

Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

Circ Pump 189 gpm No extra load on circulation pump

H2O WW Disch 3 gpm No extra load on discharge pump

kW-hr

LoTOx Electric Use 4 kW/lb O3 278 per estimate from PCI Wedeco

Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2

Total 278

Reagent Use & Other Operating Costs

Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC

Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2

Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco

Circulating Water Rate 189.4 gpm

Water Makeup Rate 8.7 gpm

WW Discharge (blowdown) 3.2 gpm

Nitrate loading (as NaNO3) in scrubber water 71 lb/hr NaNO3

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization

Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization

Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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

#5 LoTOx #5 LoTOx 14 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

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

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

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

Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567

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

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 14.6 80% 2.92 11.7 50,632

Notes & Assumptions

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

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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 SCR #1 SCR 15 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117

Instrumentation 0% of control device cost (A) NA

ND Sales Taxes 0.0% of control device cost (A) NA

Freight 0% of control device cost (A) NA

Purchased Equipment Total (A) 0% 2,585,117

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 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

Total Plant Cost (D) A + B + C 3,888,299

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)) 77,766

Inventory Capital Reagent Vol * $/gal 3,420

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 59,542

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565

Cat. Replacement 346.28 Catalyst Replacement 2,705

Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739

Total Annual Direct Operating Costs 76,551

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691

Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242

See Summary page for notes and assumptions

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 SCR #1 SCR 16 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 24,000 hours

FCW 0.0975

Rep part cost per unit 141 $/ft3# of Layers 10

Replacement Factor 8Layers replaced per year = 3.3

Amount Required 197 ft3

Catalyst Cost 27,753

Y catalyst life factor 8 Years

Annualized Cost 2,705

SCR Capital Cost per EPRI Method 2,173,722

Duty 104 MMBtu/hr Catalyst Area 50 ft

2

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 ft3New/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/MMBtu

n catalyst layers 11 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 79.1

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

29 lb/hr Neat 13.5 gal/hr

29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost

101 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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#1 SCR #1 SCR 17 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 265,359

 Purchased Equipment Total (B) 22% of control device cost (A) 322,412

 Installation - Standard Costs 30% of purchased equip cost (B) 96,724

 Installation - Site Specific Costs NA

 Installation Total 96,724

 Total Direct Capital Cost, DC 419,135

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948

Total Capital Investment (TCI) = DC + IC 519,083

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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#1 Reheat for SCR #1 Reheat for SCR 18 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 265,359

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 26,536

ND Sales Taxes 6.5% of control device cost (A) 17,248

Freight 5% of control device cost (A) 13,268

Purchased Equipment Total (B) 22% 322,412

Installation

Foundations & supports 8% of purchased equip cost (B) 25,793

Handling & erection 14% of purchased equip cost (B) 45,138

Electrical 4% of purchased equip cost (B) 12,896

Piping 2% of purchased equip cost (B) 6,448

Insulation 1% of purchased equip cost (B) 3,224

Painting 1% of purchased equip cost (B) 3,224

Installation Subtotal Standard Expenses 30% 96,724

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 96,724

Total Direct Capital Cost, DC 419,135

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 32,241

Construction & field expenses 5% of purchased equip cost (B) 16,121

Contractor fees 10% of purchased equip cost (B) 32,241

Start-up 2% of purchased equip cost (B) 6,448

Performance test 1% of purchased equip cost (B) 3,224

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 9,672

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948

Total Capital Investment (TCI) = DC + IC 519,083

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839

Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681

Total Annual Direct Operating Costs 48,421

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

See Summary page for notes and assumptions

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#1 Reheat for SCR #1 Reheat for SCR 19 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 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

Oxidizer Type thermal (catalytic or thermal) 63.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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#1 Reheat for SCR #1 Reheat for SCR 20 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 380 Deg F - Temperature of waste gas into heat recovery

Tfi 450 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 429 Deg F - Temperature of waste gas out of heat recovery

Tfo 401 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 11,811 scfm - Flow of waste gas 

Qaf 16 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560

Current Cost Using CHE Plant Cost Index $265,359

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

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

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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#1 Reheat for SCR #1 Reheat for SCR 21 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

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

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

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

Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567

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

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 14.1 80% 2.83 11.3 52,345

Notes & Assumptions

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

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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#2 SCR #2 SCR 22 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117

Instrumentation 0% of control device cost (A) NA

ND Sales Taxes 0.0% of control device cost (A) NA

Freight 0% of control device cost (A) NA

Purchased Equipment Total (A) 0% 2,585,117

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 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

Total Plant Cost (D) A + B + C 3,888,299

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)) 77,766

Inventory Capital Reagent Vol * $/gal 3,420

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 59,542

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565

Cat. Replacement 346.28 Catalyst Replacement 2,705

Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739

Total Annual Direct Operating Costs 76,551

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691

Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242

See Summary page for notes and assumptions

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

#2 SCR #2 SCR 23 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 24,000 hours

FCW 0.0975

Rep part cost per unit 141 $/ft3# of Layers 10

Replacement Factor 8Layers replaced per year = 3.3

Amount Required 197 ft3

Catalyst Cost 27,753

Y catalyst life factor 8 Years

Annualized Cost 2,705

SCR Capital Cost per EPRI Method 2,173,722

Duty 104 MMBtu/hr Catalyst Area 50 ft

2

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 ft3New/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/MMBtu

n catalyst layers 11 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 79.1

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

29 lb/hr Neat 13.5 gal/hr

29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost

101 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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#2 SCR #2 SCR 24 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 265,359

 Purchased Equipment Total (B) 22% of control device cost (A) 322,412

 Installation - Standard Costs 30% of purchased equip cost (B) 96,724

 Installation - Site Specific Costs NA

 Installation Total 96,724

 Total Direct Capital Cost, DC 419,135

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948

Total Capital Investment (TCI) = DC + IC 519,083

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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#2 Reheat for SCR #2 Reheat for SCR 25 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 265,359

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 26,536

ND Sales Taxes 6.5% of control device cost (A) 17,248

Freight 5% of control device cost (A) 13,268

Purchased Equipment Total (B) 22% 322,412

Installation

Foundations & supports 8% of purchased equip cost (B) 25,793

Handling & erection 14% of purchased equip cost (B) 45,138

Electrical 4% of purchased equip cost (B) 12,896

Piping 2% of purchased equip cost (B) 6,448

Insulation 1% of purchased equip cost (B) 3,224

Painting 1% of purchased equip cost (B) 3,224

Installation Subtotal Standard Expenses 30% 96,724

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 96,724

Total Direct Capital Cost, DC 419,135

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 32,241

Construction & field expenses 5% of purchased equip cost (B) 16,121

Contractor fees 10% of purchased equip cost (B) 32,241

Start-up 2% of purchased equip cost (B) 6,448

Performance test 1% of purchased equip cost (B) 3,224

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 9,672

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948

Total Capital Investment (TCI) = DC + IC 519,083

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839

Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681

Total Annual Direct Operating Costs 48,421

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502

Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923

See Summary page for notes and assumptions

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#2 Reheat for SCR #2 Reheat for SCR 26 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 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

Oxidizer Type thermal (catalytic or thermal) 63.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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#2 Reheat for SCR #2 Reheat for SCR 27 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 380 Deg F - Temperature of waste gas into heat recovery

Tfi 450 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 429 Deg F - Temperature of waste gas out of heat recovery

Tfo 401 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 11,811 scfm - Flow of waste gas 

Qaf 16 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560

Current Cost Using CHE Plant Cost Index $265,359

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

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

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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#2 Reheat for SCR #2 Reheat for SCR 28 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs 2000 2,667,517

 Purchased Equipment (A) 2005 3,172,367

 Purchased Equipment Total (B) SCR + Reheat 3,529,175

Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 15.4 80% 3.1 12.3 56,028

Notes & Assumptions

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

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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#4 SCR #4 SCR 29 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367

Instrumentation 0% of control device cost (A) NA

ND Sales Taxes 0.0% of control device cost (A) NA

Freight 0% of control device cost (A) NA

Purchased Equipment Total (A) 0% 3,172,367

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 25% Replacement Power, two weeks 796,012

Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 595,257

Total Plant Cost (D) A + B + C 4,563,637

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)) 91,273

Inventory Capital Reagent Vol * $/gal 5,023

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 69,899

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244

Cat. Replacement 346.28 Catalyst Replacement 3,979

Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773

Total Annual Direct Operating Costs 94,895

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865

Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760

See Summary page for notes and assumptions

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#4 SCR #4 SCR 30 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 24,000 hours

FCW 0.0975

Rep part cost per unit 141 $/ft3# of Layers 10

Replacement Factor 8Layers replaced per year = 3.3

Amount Required 290 ft3

Catalyst Cost 40,823

Y catalyst life factor 8 Years

Annualized Cost 3,979

SCR Capital Cost per EPRI Method 2,667,517

Duty 153 MMBtu/hr Catalyst Area 74 ft

2

308 f (h SCR)

Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 9.2 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 532,728 f (vol catalyst)

Temperature 380 Deg F h SCR 81 ft f (h SCR)

Catalyst Volume 2,220 ft3New/Retrofit R N or R 

Electrical Use

Duty 153 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 116.4

NOx in 0.28 lb/MMBtu

n catalyst layers 11 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 116.4

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

43 lb/hr Neat 19.8 gal/hr

29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost

148 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization

Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement

Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 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

See Summary page for notes and assumptions

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#4 SCR #4 SCR 31 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 293,668

 Purchased Equipment Total (B) 22% of control device cost (A) 356,807

 Installation - Standard Costs 30% of purchased equip cost (B) 107,042

 Installation - Site Specific Costs NA

 Installation Total 107,042

 Total Direct Capital Cost, DC 463,849

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610

Total Capital Investment (TCI) = DC + IC 574,460

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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#4 Reheat for SCR #4 Reheat for SCR 32 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 293,668

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 29,367

ND Sales Taxes 6.5% of control device cost (A) 19,088

Freight 5% of control device cost (A) 14,683

Purchased Equipment Total (B) 22% 356,807

Installation

Foundations & supports 8% of purchased equip cost (B) 28,545

Handling & erection 14% of purchased equip cost (B) 49,953

Electrical 4% of purchased equip cost (B) 14,272

Piping 2% of purchased equip cost (B) 7,136

Insulation 1% of purchased equip cost (B) 3,568

Painting 1% of purchased equip cost (B) 3,568

Installation Subtotal Standard Expenses 30% 107,042

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 107,042

Total Direct Capital Cost, DC 463,849

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 35,681

Construction & field expenses 5% of purchased equip cost (B) 17,840

Contractor fees 10% of purchased equip cost (B) 35,681

Start-up 2% of purchased equip cost (B) 7,136

Performance test 1% of purchased equip cost (B) 3,568

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 10,704

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610

Total Capital Investment (TCI) = DC + IC 574,460

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258

Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521

Total Annual Direct Operating Costs 53,680

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

See Summary page for notes and assumptions

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#4 Reheat for SCR #4 Reheat for SCR 33 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 94.5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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#4 Reheat for SCR #4 Reheat for SCR 34 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 380 Deg F - Temperature of waste gas into heat recovery

Tfi 450 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 429 Deg F - Temperature of waste gas out of heat recovery

Tfo 401 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 17,716 scfm - Flow of waste gas 

Qaf 23 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303

Current Cost Using CHE Plant Cost Index $293,668

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

NOx Due to Duct Burner

1,408 scf/hr Flow of natural gas required

1.5 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

0.518 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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#4 Reheat for SCR #4 Reheat for SCR 35 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs 2000 2,667,517

 Purchased Equipment (A) 2005 3,172,367

 Purchased Equipment Total (B) SCR + Reheat 3,529,175

Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384

Emission Control Cost Calculation

Max Emis Annual Control EffControlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 14.3 80% 2.9 11.4 60,211

Notes & Assumptions

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

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

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#5 SCR #5 SCR 36 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367

Instrumentation 0% of control device cost (A) NA

ND Sales Taxes 0.0% of control device cost (A) NA

Freight 0% of control device cost (A) NA

Purchased Equipment Total (A) 0% 3,172,367

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 25% Replacement Power, two weeks 796,012

Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012

Project Contingeny (C) 15% of (A + B) 595,257

Total Plant Cost (D) A + B + C 4,563,637

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)) 91,273

Inventory Capital Reagent Vol * $/gal 5,023

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 69,899

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244

Cat. Replacement 346.28 Catalyst Replacement 3,979

Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773

Total Annual Direct Operating Costs 94,895

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865

Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760

See Summary page for notes and assumptions

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#5 SCR #5 SCR 37 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 24,000 hours

FCW 0.0975

Rep part cost per unit 141 $/ft3# of Layers 10

Replacement Factor 8Layers replaced per year = 3.3

Amount Required 290 ft3

Catalyst Cost 40,823

Y catalyst life factor 8 Years

Annualized Cost 3,979

SCR Capital Cost per EPRI Method 2,667,517

Duty 153 MMBtu/hr Catalyst Area 74 ft

2

308 f (h SCR)

Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 9.2 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 532,728 f (vol catalyst)

Temperature 380 Deg F h SCR 81 ft f (h SCR)

Catalyst Volume 2,220 ft3New/Retrofit R N or R 

Electrical Use

Duty 153 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 116.4

NOx in 0.28 lb/MMBtu

n catalyst layers 11 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 116.4

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

43 lb/hr Neat 19.8 gal/hr

29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost

148 lb/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization

Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement

Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 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

See Summary page for notes and assumptions

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Draft BART Emission Control Cost Analysis

Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 293,668

 Purchased Equipment Total (B) 22% of control device cost (A) 356,807

 Installation - Standard Costs 30% of purchased equip cost (B) 107,042

 Installation - Site Specific Costs NA

 Installation Total 107,042

 Total Direct Capital Cost, DC 463,849

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610

Total Capital Investment (TCI) = DC + IC 574,460

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

Notes & Assumptions

1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

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#5 Reheat for SCR #5 Reheat for SCR 39 of 106
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Draft BART Emission Control Cost Analysis

Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 293,668

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 29,367

ND Sales Taxes 6.5% of control device cost (A) 19,088

Freight 5% of control device cost (A) 14,683

Purchased Equipment Total (B) 22% 356,807

Installation

Foundations & supports 8% of purchased equip cost (B) 28,545

Handling & erection 14% of purchased equip cost (B) 49,953

Electrical 4% of purchased equip cost (B) 14,272

Piping 2% of purchased equip cost (B) 7,136

Insulation 1% of purchased equip cost (B) 3,568

Painting 1% of purchased equip cost (B) 3,568

Installation Subtotal Standard Expenses 30% 107,042

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 107,042

Total Direct Capital Cost, DC 463,849

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 35,681

Construction & field expenses 5% of purchased equip cost (B) 17,840

Contractor fees 10% of purchased equip cost (B) 35,681

Start-up 2% of purchased equip cost (B) 7,136

Performance test 1% of purchased equip cost (B) 3,568

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 10,704

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610

Total Capital Investment (TCI) = DC + IC 574,460

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Supervisor 15% 15% of Operator Costs 1,805

Maintenance

Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032

Maintenance Materials 100% of maintenance labor costs 12,032

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258

Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521

Total Annual Direct Operating Costs 53,680

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,741

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625

See Summary page for notes and assumptions

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#5 Reheat for SCR #5 Reheat for SCR 40 of 106
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Draft BART Emission Control Cost Analysis

Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $/ft3

Amount Required 39 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 94.5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Supervisor 15% of Op. NA 1,805 15% of Operator Costs

Maintenance

Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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Draft BART Emission Control Cost Analysis

Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)

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

Auxiliary Fuel Use Equation 3.19 

Twi 380 Deg F - Temperature of waste gas into heat recovery

Tfi 450 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 429 Deg F - Temperature of waste gas out of heat recovery

Tfo 401 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 17,716 scfm - Flow of waste gas 

Qaf 23 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303

Current Cost Using CHE Plant Cost Index $293,668

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

NOx Due to Duct Burner

1,408 scf/hr Flow of natural gas required

1.5 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

0.518 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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#5 Reheat for SCR #5 Reheat for SCR 42 of 106
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Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 442,265

 Purchased Equipment Total (B) 22% of control device cost (A) 537,352

 Installation - Standard Costs 30% of purchased equip cost (B) 161,206

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 698,558

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579

Total Capital Investment (TCI) = DC + IC 1,384,220

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

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) 29.2 14.3 75% 3.6 10.7 15,558

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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#1 LNB FGR 1/8/2008 Page 43 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 442,265

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 44,227

MN Sales Taxes 6.5% of control device cost (A) 28,747

Freight 5% of control device cost (A) 22,113

Purchased Equipment Total (B) 22% 537,352

Installation

Foundations & supports 8% of purchased equip cost (B) 42,988

Handling & erection 14% of purchased equip cost (B) 75,229

Electrical 4% of purchased equip cost (B) 21,494

Piping 2% of purchased equip cost (B) 10,747

Insulation 1% of purchased equip cost (B) 5,374

Painting 1% of purchased equip cost (B) 5,374

Installation Subtotal Standard Expenses 30% 161,206

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/a

Installation Total n/a

Total Direct Capital Cost, DC 698,558

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 53,735

Construction & field expenses 5% of purchased equip cost (B) 26,868

Contractor fees 10% of purchased equip cost (B) 53,735

Start-up 2% of purchased equip cost (B) 10,747

Performance test 1% of purchased equip cost (B) 5,374

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 16,121

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579

Total Capital Investment (TCI) = DC + IC 865,137

Retrofit Factor(3) 60% of TCI 519,082

TCI Retrofit Installed 1,384,220

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81

Total Annual Direct Operating Costs 840

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303

Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651

Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

See Summary page for notes and assumptions

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#1 LNB FGR 1/8/2008 Page 44 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow 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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization

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

See Summary page for notes and assumptions

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#1 LNB FGR 1/8/2008 Page 45 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 442,265

 Purchased Equipment Total (B) 22% of control device cost (A) 537,352

 Installation - Standard Costs 30% of purchased equip cost (B) 161,206

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 698,558

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579

Total Capital Investment (TCI) = DC + IC 1,384,220

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

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) 29.2 13.8 75% 3.4 10.3 16,098

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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#2 LNB FGR 1/8/2008 Page 46 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 442,265

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 44,227

MN Sales Taxes 6.5% of control device cost (A) 28,747

Freight 5% of control device cost (A) 22,113

Purchased Equipment Total (B) 22% 537,352

Installation

Foundations & supports 8% of purchased equip cost (B) 42,988

Handling & erection 14% of purchased equip cost (B) 75,229

Electrical 4% of purchased equip cost (B) 21,494

Piping 2% of purchased equip cost (B) 10,747

Insulation 1% of purchased equip cost (B) 5,374

Painting 1% of purchased equip cost (B) 5,374

Installation Subtotal Standard Expenses 30% 161,206

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/a

Installation Total n/a

Total Direct Capital Cost, DC 698,558

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 53,735

Construction & field expenses 5% of purchased equip cost (B) 26,868

Contractor fees 10% of purchased equip cost (B) 53,735

Start-up 2% of purchased equip cost (B) 10,747

Performance test 1% of purchased equip cost (B) 5,374

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 16,121

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579

Total Capital Investment (TCI) = DC + IC 865,137

Retrofit Factor(3) 60% of TCI 519,082

TCI Retrofit Installed 1,384,220

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81

Total Annual Direct Operating Costs 840

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303

Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651

Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721

Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560

See Summary page for notes and assumptions

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#2 LNB FGR 1/8/2008 Page 47 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow 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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization

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

See Summary page for notes and assumptions

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#2 LNB FGR 1/8/2008 Page 48 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 557,542

 Purchased Equipment Total (B) 22% of control device cost (A) 677,414

 Installation - Standard Costs 30% of purchased equip cost (B) 203,224

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 880,638

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998

Total Capital Investment (TCI) = DC + IC 1,745,018

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

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) 42.9 14.8 75% 3.7 11.1 18,839

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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#4 LNB FGR 1/8/2008 Page 49 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 557,542

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 55,754

MN Sales Taxes 6.5% of control device cost (A) 36,240

Freight 5% of control device cost (A) 27,877

Purchased Equipment Total (B) 22% 677,414

Installation

Foundations & supports 8% of purchased equip cost (B) 54,193

Handling & erection 14% of purchased equip cost (B) 94,838

Electrical 4% of purchased equip cost (B) 27,097

Piping 2% of purchased equip cost (B) 13,548

Insulation 1% of purchased equip cost (B) 6,774

Painting 1% of purchased equip cost (B) 6,774

Installation Subtotal Standard Expenses 30% 203,224

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/a

Installation Total n/a

Total Direct Capital Cost, DC 880,638

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 67,741

Construction & field expenses 5% of purchased equip cost (B) 33,871

Contractor fees 10% of purchased equip cost (B) 67,741

Start-up 2% of purchased equip cost (B) 13,548

Performance test 1% of purchased equip cost (B) 6,774

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 20,322

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998

Total Capital Investment (TCI) = DC + IC 1,090,636

Retrofit Factor(3) 60% of TCI 654,382

TCI Retrofit Installed 1,745,018

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122

Total Annual Direct Operating Costs 880

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

See Summary page for notes and assumptions

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#4 LNB FGR 1/8/2008 Page 50 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization

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

See Summary page for notes and assumptions

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#4 LNB FGR 1/8/2008 Page 51 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 557,542

 Purchased Equipment Total (B) 22% of control device cost (A) 677,414

 Installation - Standard Costs 30% of purchased equip cost (B) 203,224

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 880,638

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998

Total Capital Investment (TCI) = DC + IC 1,745,018

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

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) 42.9 13.8 75% 3.4 10.3 20,299

Notes & Assumptions

1 Purchased equipment cost based on estimate from Coen Burner.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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#5 LNB FGR 1/8/2008 Page 52 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 557,542

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 55,754

MN Sales Taxes 6.5% of control device cost (A) 36,240

Freight 5% of control device cost (A) 27,877

Purchased Equipment Total (B) 22% 677,414

Installation

Foundations & supports 8% of purchased equip cost (B) 54,193

Handling & erection 14% of purchased equip cost (B) 94,838

Electrical 4% of purchased equip cost (B) 27,097

Piping 2% of purchased equip cost (B) 13,548

Insulation 1% of purchased equip cost (B) 6,774

Painting 1% of purchased equip cost (B) 6,774

Installation Subtotal Standard Expenses 30% 203,224

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/a

Installation Total n/a

Total Direct Capital Cost, DC 880,638

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 67,741

Construction & field expenses 5% of purchased equip cost (B) 33,871

Contractor fees 10% of purchased equip cost (B) 67,741

Start-up 2% of purchased equip cost (B) 13,548

Performance test 1% of purchased equip cost (B) 6,774

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 20,322

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998

Total Capital Investment (TCI) = DC + IC 1,090,636

Retrofit Factor(3) 60% of TCI 654,382

TCI Retrofit Installed 1,745,018

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122

Total Annual Direct Operating Costs 880

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798

Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678

See Summary page for notes and assumptions

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#5 LNB FGR 1/8/2008 Page 53 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 5% of flue gas is recirculated)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization

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

See Summary page for notes and assumptions

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#5 LNB FGR 1/8/2008 Page 54 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 1,201,308

 Total Direct Capital Cost, DC 1,201,308

Total Capital Investment (TCI) = DC + IC 1,690,961

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 14.9 70% 4.5 10.4 22,879

Notes & Assumptions

1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

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 

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS2

Direct Capital Costs

Purchased Equipment1 (A)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 1,201,308

Indirect Installation

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

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262

Project Contingeny (C) 15% of (A + B) 216,235

Total Plant Cost (D) A + B + C 1,657,804

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)) 33,156

Inventory Capital Reagent Vol * $/gal 0

Intial Catalyst and Chemicals 0 for SCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961

OPERATING COSTS2

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 25,364

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321

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

Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173

SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204

Total Annual Direct Operating Costs 79,021

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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

Annualized Cost 33,204

Electrical Use

Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 51.5

Reagent Use & Other Operating Costs

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

Auxiliary Fuel Use Equation 3.19 

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 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

Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization

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

Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization

SCR Catalyst 0.00 $/ft30 ft30 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction

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

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 713 Deg F - Temperature of waste gas out of heat recovery

Tfo 417 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 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 11,811 scfm - Flow of waste gas 

Qaf 28 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

1,703 scf/hr Flow of natural gas required

1.8 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

0.6 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 1,201,308

 Total Direct Capital Cost, DC 1,201,308

Total Capital Investment (TCI) = DC + IC 1,690,961

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 14.4 70% 4.3 10.1 23,638

Notes & Assumptions

1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

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 

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS2

Direct Capital Costs

Purchased Equipment1 (A)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 1,201,308

Indirect Installation

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

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262

Project Contingeny (C) 15% of (A + B) 216,235

Total Plant Cost (D) A + B + C 1,657,804

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)) 33,156

Inventory Capital Reagent Vol * $/gal 0

Intial Catalyst and Chemicals 0 for SCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961

OPERATING COSTS2

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 25,364

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321

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

Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173

SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204

Total Annual Direct Operating Costs 79,021

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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

Annualized Cost 33,204

Electrical Use

Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 51.5

Reagent Use & Other Operating Costs

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

Auxiliary Fuel Use Equation 3.19 

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 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

Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization

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

Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization

SCR Catalyst 0.00 $/ft30 ft30 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction

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

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 713 Deg F - Temperature of waste gas out of heat recovery

Tfo 417 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 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 11,811 scfm - Flow of waste gas 

Qaf 28 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

1,703 scf/hr Flow of natural gas required

1.8 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

0.6 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 1,532,177

 Total Direct Capital Cost, DC 1,532,177

Total Capital Investment (TCI) = DC + IC 2,156,692

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 15.8 70% 4.7 11.0 28,633

Notes & Assumptions

1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

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 

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS2

Direct Capital Costs

Purchased Equipment1 (A)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 1,532,177

Indirect Installation

General Facilities 5% of purchased equip cost (A) 76,609

Engineerin & Home Office 10% of purchased equip cost (A) 153,218

Process Contingency 5% of purchased equip cost (A) 76,609

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435

Project Contingeny (C) 15% of (A + B) 275,792

Total Plant Cost (D) A + B + C 2,114,404

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)) 42,288

Inventory Capital Reagent Vol * $/gal 0

Intial Catalyst and Chemicals 0 for SCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692

OPERATING COSTS2

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 32,350

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481

Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899

Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38

Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130

SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807

Total Annual Direct Operating Costs 112,705

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 3 Years

CRF 0.3811

Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 130,708

Annualized Cost 49,807

Electrical Use

Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 77.2

Reagent Use & Other Operating Costs

Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5

Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 

Chapter 3 Thermal & Catalytic Incinerators

Auxiliary Fuel Use Equation 3.19 

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 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

Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization

Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization

Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization

SCR Catalyst 0.00 $/ft30 ft30 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction

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

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 713 Deg F - Temperature of waste gas out of heat recovery

Tfo 417 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 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 17,716 scfm - Flow of waste gas 

Qaf 43 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

2,555 scf/hr Flow of natural gas required

2.7 mmbtu/hr Heat required, assuming 1050 btu/scf

0.08 lb/mmbtu NOx emission factor for natural gas combustion

0.2 lb/hr Additional NOx from duct burners

0.9 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F

Expected Utiliztion Rate 28% Temperature 380 Deg F

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 1,532,177

 Total Direct Capital Cost, DC 1,532,177

Total Capital Investment (TCI) = DC + IC 2,156,692

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 14.7 70% 4.4 10.3 30,710

Notes & Assumptions

1

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

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 

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

CAPITAL COSTS2

Direct Capital Costs

Purchased Equipment1 (A)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 1,532,177

Indirect Installation

General Facilities 5% of purchased equip cost (A) 76,609

Engineerin & Home Office 10% of purchased equip cost (A) 153,218

Process Contingency 5% of purchased equip cost (A) 76,609

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435

Project Contingeny (C) 15% of (A + B) 275,792

Total Plant Cost (D) A + B + C 2,114,404

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)) 42,288

Inventory Capital Reagent Vol * $/gal 0

Intial Catalyst and Chemicals 0 for SCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692

OPERATING COSTS2

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 32,350

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481

Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899

Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38

Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130

SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807

Total Annual Direct Operating Costs 112,705

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577

Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catayst

Equipment Life 3 Years

CRF 0.3811

Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total cost 130,708

Annualized Cost 49,807

Electrical Use

Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Total 77.2

Reagent Use & Other Operating Costs

Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5

Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.

Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 

Chapter 3 Thermal & Catalytic Incinerators

Auxiliary Fuel Use Equation 3.19 

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 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

Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization

Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization

Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization

Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization

SCR Catalyst 0.00 $/ft30 ft30 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization

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

See Summary page for notes and assumptions

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction

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

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 90% Factional Heat Recovery % Heat recovery section efficiency

Two 713 Deg F - Temperature of waste gas out of heat recovery

Tfo 417 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 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist 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 17,716 scfm - Flow of waste gas 

Qaf 43 scfm - Flow of auxiliary fuel

NOx Due to Duct Burner

2,555 scf/hr Flow of natural gas required

2.7 mmbtu/hr Heat required, assuming 1050 btu/scf

0.08 lb/mmbtu NOx emission factor for natural gas combustion

0.2 lb/hr Additional NOx from duct burners

0.9 tpy Additional NOx from duct burners

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 361,408

 Purchased Equipment Total (B) 22% of control device cost (A) 439,111

 Installation - Standard Costs 30% of purchased equip cost (B) 131,733

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 570,844

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124

Total Capital Investment (TCI) = DC + IC 1,131,149

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

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) 29.2 14.3 67% 4.7 9.6 14,282

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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#1 LNB OFA 1/8/2008 Page 71 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 361,408

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 36,141

MN Sales Taxes 6.5% of control device cost (A) 23,492

Freight 5% of control device cost (A) 18,070

Purchased Equipment Total (B) 22% 439,111

Installation

Foundations & supports 8% of purchased equip cost (B) 35,129

Handling & erection 14% of purchased equip cost (B) 61,476

Electrical 4% of purchased equip cost (B) 17,564

Piping 2% of purchased equip cost (B) 8,782

Insulation 1% of purchased equip cost (B) 4,391

Painting 1% of purchased equip cost (B) 4,391

Installation Subtotal Standard Expenses 30% 131,733

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/a

Installation Total n/a

Total Direct Capital Cost, DC 570,844

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 43,911

Construction & field expenses 5% of purchased equip cost (B) 21,956

Contractor fees 10% of purchased equip cost (B) 43,911

Start-up 2% of purchased equip cost (B) 8,782

Performance test 1% of purchased equip cost (B) 4,391

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 13,173

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124

Total Capital Investment (TCI) = DC + IC 706,968

Retrofit Factor(3) 60% of TCI 424,181

TCI Retrofit Installed 1,131,149

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326

Total Annual Direct Operating Costs 1,084

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139

Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070

Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

See Summary page for notes and assumptions

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 LNB OFA 1/8/2008 Page 72 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr

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

See Summary page for notes and assumptions

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 LNB OFA 1/8/2008 Page 73 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 361,408

 Purchased Equipment Total (B) 22% of control device cost (A) 439,111

 Installation - Standard Costs 30% of purchased equip cost (B) 131,733

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 570,844

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124

Total Capital Investment (TCI) = DC + IC 1,131,149

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

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) 29.2 13.8 67% 4.6 9.2 14,778

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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

#2 LNB OFA 1/8/2008 Page 74 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 361,408

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 36,141

MN Sales Taxes 6.5% of control device cost (A) 23,492

Freight 5% of control device cost (A) 18,070

Purchased Equipment Total (B) 22% 439,111

Installation

Foundations & supports 8% of purchased equip cost (B) 35,129

Handling & erection 14% of purchased equip cost (B) 61,476

Electrical 4% of purchased equip cost (B) 17,564

Piping 2% of purchased equip cost (B) 8,782

Insulation 1% of purchased equip cost (B) 4,391

Painting 1% of purchased equip cost (B) 4,391

Installation Subtotal Standard Expenses 30% 131,733

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/a

Installation Total n/a

Total Direct Capital Cost, DC 570,844

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 43,911

Construction & field expenses 5% of purchased equip cost (B) 21,956

Contractor fees 10% of purchased equip cost (B) 43,911

Start-up 2% of purchased equip cost (B) 8,782

Performance test 1% of purchased equip cost (B) 4,391

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 13,173

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124

Total Capital Investment (TCI) = DC + IC 706,968

Retrofit Factor(3) 60% of TCI 424,181

TCI Retrofit Installed 1,131,149

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326

Total Annual Direct Operating Costs 1,084

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139

Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070

Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590

See Summary page for notes and assumptions

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

#2 LNB OFA 1/8/2008 Page 75 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr

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

See Summary page for notes and assumptions

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

#2 LNB OFA 1/8/2008 Page 76 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 455,609

 Purchased Equipment Total (B) 22% of control device cost (A) 553,565

 Installation - Standard Costs 30% of purchased equip cost (B) 166,070

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 719,635

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605

Total Capital Investment (TCI) = DC + IC 1,425,985

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

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) 42.9 14.8 67% 4.9 9.9 17,294

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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

#4 LNB OFA 1/8/2008 Page 77 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 455,609

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 45,561

MN Sales Taxes 6.5% of control device cost (A) 29,615

Freight 5% of control device cost (A) 22,780

Purchased Equipment Total (B) 22% 553,565

Installation

Foundations & supports 8% of purchased equip cost (B) 44,285

Handling & erection 14% of purchased equip cost (B) 77,499

Electrical 4% of purchased equip cost (B) 22,143

Piping 2% of purchased equip cost (B) 11,071

Insulation 1% of purchased equip cost (B) 5,536

Painting 1% of purchased equip cost (B) 5,536

Installation Subtotal Standard Expenses 30% 166,070

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/a

Installation Total n/a

Total Direct Capital Cost, DC 719,635

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 55,357

Construction & field expenses 5% of purchased equip cost (B) 27,678

Contractor fees 10% of purchased equip cost (B) 55,357

Start-up 2% of purchased equip cost (B) 11,071

Performance test 1% of purchased equip cost (B) 5,536

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 16,607

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605

Total Capital Investment (TCI) = DC + IC 891,240

Retrofit Factor(3) 60% of TCI 534,744

TCI Retrofit Installed 1,425,985

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489

Total Annual Direct Operating Costs 1,247

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825

Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912

Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

See Summary page for notes and assumptions

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

#4 LNB OFA 1/8/2008 Page 78 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr

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

See Summary page for notes and assumptions

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

#4 LNB OFA 1/8/2008 Page 79 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 455,609

 Purchased Equipment Total (B) 22% of control device cost (A) 553,565

 Installation - Standard Costs 30% of purchased equip cost (B) 166,070

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 719,635

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605

Total Capital Investment (TCI) = DC + IC 1,425,985

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

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) 42.9 13.8 67% 4.5 9.2 18,634

Notes & Assumptions

1 Price based on installation of LNB with OFA in a similar application.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

3 CUECost Workbook Version 1.0, USEPA Document Page 2

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

#5 LNB OFA 1/8/2008 Page 80 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 455,609

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 45,561

MN Sales Taxes 6.5% of control device cost (A) 29,615

Freight 5% of control device cost (A) 22,780

Purchased Equipment Total (B) 22% 553,565

Installation

Foundations & supports 8% of purchased equip cost (B) 44,285

Handling & erection 14% of purchased equip cost (B) 77,499

Electrical 4% of purchased equip cost (B) 22,143

Piping 2% of purchased equip cost (B) 11,071

Insulation 1% of purchased equip cost (B) 5,536

Painting 1% of purchased equip cost (B) 5,536

Installation Subtotal Standard Expenses 30% 166,070

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/a

Installation Total n/a

Total Direct Capital Cost, DC 719,635

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 55,357

Construction & field expenses 5% of purchased equip cost (B) 27,678

Contractor fees 10% of purchased equip cost (B) 55,357

Start-up 2% of purchased equip cost (B) 11,071

Performance test 1% of purchased equip cost (B) 5,536

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 16,607

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605

Total Capital Investment (TCI) = DC + IC 891,240

Retrofit Factor(3) 60% of TCI 534,744

TCI Retrofit Installed 1,425,985

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489

Total Annual Direct Operating Costs 1,247

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825

Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912

Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954

See Summary page for notes and assumptions

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

#5 LNB OFA 1/8/2008 Page 81 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

(assume 20% of flue gas used for OFA)

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr

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

See Summary page for notes and assumptions

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

#5 LNB OFA 1/8/2008 Page 82 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 175,993

 Purchased Equipment Total (B) 22% of control device cost (A) 213,832

 Installation - Standard Costs 30% of purchased equip cost (B) 64,150

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 277,981

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288

Total Capital Investment (TCI) = DC + IC 344,269

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

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) 29.2 14.3 50% 7.1 7.1 6,653

Notes & Assumptions

1 Equipment cost based on estimate from John Zink

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

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 LNB 1/8/2008 Page 83 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 175,993

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 17,599

MN Sales Taxes 6.5% of control device cost (A) 11,440

Freight 5% of control device cost (A) 8,800

Purchased Equipment Total (B) 22% 213,832

Installation

Foundations & supports 8% of purchased equip cost (B) 17,107

Handling & erection 14% of purchased equip cost (B) 29,936

Electrical 4% of purchased equip cost (B) 8,553

Piping 2% of purchased equip cost (B) 4,277

Insulation 1% of purchased equip cost (B) 2,138

Painting 1% of purchased equip cost (B) 2,138

Installation Subtotal Standard Expenses 30% 64,150

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/a

Installation Total n/a

Total Direct Capital Cost, DC 277,981

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 21,383

Construction & field expenses 5% of purchased equip cost (B) 10,692

Contractor fees 10% of purchased equip cost (B) 21,383

Start-up 2% of purchased equip cost (B) 4,277

Performance test 1% of purchased equip cost (B) 2,138

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 6,415

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288

Total Capital Investment (TCI) = DC + IC 344,269

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885

Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443

Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

See Summary page for notes and assumptions

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#1 LNB 1/8/2008 Page 84 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

See Summary page for notes and assumptions

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#1 LNB 1/8/2008 Page 85 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

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 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 175,993

 Purchased Equipment Total (B) 22% of control device cost (A) 213,832

 Installation - Standard Costs 30% of purchased equip cost (B) 64,150

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 277,981

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288

Total Capital Investment (TCI) = DC + IC 344,269

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

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) 29.2 13.8 50% 6.9 6.9 6,883

Notes & Assumptions

1 Equipment cost based on estimate from John Zink

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

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#2 LNB 1/8/2008 Page 86 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 175,993

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 17,599

MN Sales Taxes 6.5% of control device cost (A) 11,440

Freight 5% of control device cost (A) 8,800

Purchased Equipment Total (B) 22% 213,832

Installation

Foundations & supports 8% of purchased equip cost (B) 17,107

Handling & erection 14% of purchased equip cost (B) 29,936

Electrical 4% of purchased equip cost (B) 8,553

Piping 2% of purchased equip cost (B) 4,277

Insulation 1% of purchased equip cost (B) 2,138

Painting 1% of purchased equip cost (B) 2,138

Installation Subtotal Standard Expenses 30% 64,150

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/a

Installation Total n/a

Total Direct Capital Cost, DC 277,981

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 21,383

Construction & field expenses 5% of purchased equip cost (B) 10,692

Contractor fees 10% of purchased equip cost (B) 21,383

Start-up 2% of purchased equip cost (B) 4,277

Performance test 1% of purchased equip cost (B) 2,138

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 6,415

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288

Total Capital Investment (TCI) = DC + IC 344,269

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885

Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443

Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722

Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480

See Summary page for notes and assumptions

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#2 LNB 1/8/2008 Page 87 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

See Summary page for notes and assumptions

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#2 LNB 1/8/2008 Page 88 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 221,866

 Purchased Equipment Total (B) 22% of control device cost (A) 269,567

 Installation - Standard Costs 30% of purchased equip cost (B) 80,870

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 350,437

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566

Total Capital Investment (TCI) = DC + IC 434,003

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

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) 42.9 14.8 50% 7.4 7.4 8,024

Notes & Assumptions

1 Equipment cost based on estimate from John Zink

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

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#4 LNB 1/8/2008 Page 89 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 221,866

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 22,187

MN Sales Taxes 6.5% of control device cost (A) 14,421

Freight 5% of control device cost (A) 11,093

Purchased Equipment Total (B) 22% 269,567

Installation

Foundations & supports 8% of purchased equip cost (B) 21,565

Handling & erection 14% of purchased equip cost (B) 37,739

Electrical 4% of purchased equip cost (B) 10,783

Piping 2% of purchased equip cost (B) 5,391

Insulation 1% of purchased equip cost (B) 2,696

Painting 1% of purchased equip cost (B) 2,696

Installation Subtotal Standard Expenses 30% 80,870

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/a

Installation Total n/a

Total Direct Capital Cost, DC 350,437

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,957

Construction & field expenses 5% of purchased equip cost (B) 13,478

Contractor fees 10% of purchased equip cost (B) 26,957

Start-up 2% of purchased equip cost (B) 5,391

Performance test 1% of purchased equip cost (B) 2,696

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 8,087

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566

Total Capital Investment (TCI) = DC + IC 434,003

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680

Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340

Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

See Summary page for notes and assumptions

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#4 LNB 1/8/2008 Page 90 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

See Summary page for notes and assumptions

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#4 LNB 1/8/2008 Page 91 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 221,866

 Purchased Equipment Total (B) 22% of control device cost (A) 269,567

 Installation - Standard Costs 30% of purchased equip cost (B) 80,870

 Installation - Site Specific Costs n/a

 Installation Total n/a

 Total Direct Capital Cost, DC 350,437

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566

Total Capital Investment (TCI) = DC + IC 434,003

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

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) 42.9 13.8 50% 6.9 6.9 8,646

Notes & Assumptions

1 Equipment cost based on estimate from John Zink

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost

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#5 LNB 1/8/2008 Page 92 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 221,866

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 22,187

MN Sales Taxes 6.5% of control device cost (A) 14,421

Freight 5% of control device cost (A) 11,093

Purchased Equipment Total (B) 22% 269,567

Installation

Foundations & supports 8% of purchased equip cost (B) 21,565

Handling & erection 14% of purchased equip cost (B) 37,739

Electrical 4% of purchased equip cost (B) 10,783

Piping 2% of purchased equip cost (B) 5,391

Insulation 1% of purchased equip cost (B) 2,696

Painting 1% of purchased equip cost (B) 2,696

Installation Subtotal Standard Expenses 30% 80,870

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/a

Installation Total n/a

Total Direct Capital Cost, DC 350,437

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,957

Construction & field expenses 5% of purchased equip cost (B) 13,478

Contractor fees 10% of purchased equip cost (B) 26,957

Start-up 2% of purchased equip cost (B) 5,391

Performance test 1% of purchased equip cost (B) 2,696

Model Studies 0% of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 8,087

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566

Total Capital Investment (TCI) = DC + IC 434,003

OPERATING COSTS

Direct Annual Operating Costs, DC

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

Utilities, Supplies, Replacements & Waste Management

Total Annual Direct Operating Costs 758

Indirect Operating Costs

Overhead 60% of total labor and material costs 455

Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680

Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340

Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782

Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540

See Summary page for notes and assumptions

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#5 LNB 1/8/2008 Page 93 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr

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

Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

See Summary page for notes and assumptions

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#5 LNB 1/8/2008 Page 94 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #1

Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 769,260

 Purchased Equipment Total (B) 0% of control device cost (A) 769,260

 Installation - Standard Costs 15% of purchased equip cost (B) 138,467

Total Capital Investment (TCI) = DC + IC 1,084,406

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 14.3 50% 7.1 7.1 42,037

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

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US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 769,260

Indirect Installation [1]

General Facilities 5% of purchased equip cost (A) 38,463

Engineerin & Home Office 10% of purchased equip cost (A) 76,926

Process Contingency 5% of purchased equip cost (A) 38,463

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852

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

Pre Production Costs (G) 2% of (D+E)) 21,232

Inventory Capital Reagent Vol * $/gal 1,596

Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406

Retrofit Installation Factor 30% 325,322

Total Capital Investment, Retrofit Installed 1,409,728

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 162,661

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

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

Total Annual Direct Operating Costs 166,949

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

See Summary page for notes and assumptions

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 SNCR #1 SNCR 96 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

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 SNCR #1 SNCR 97 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #2

Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering

Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32o F Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18

Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68o F

Dry Std Flow Rate 10,240 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 769,260

 Purchased Equipment Total (B) 0% of control device cost (A) 769,260

 Installation - Standard Costs 15% of purchased equip cost (B) 138,467

Total Capital Investment (TCI) = DC + IC 1,084,406

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 29.2 13.8 50% 6.9 6.9 43,495

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

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

#2 SNCR #2 SNCR 98 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 769,260

Indirect Installation [1]

General Facilities 5% of purchased equip cost (A) 38,463

Engineerin & Home Office 10% of purchased equip cost (A) 76,926

Process Contingency 5% of purchased equip cost (A) 38,463

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852

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

Pre Production Costs (G) 2% of (D+E)) 21,232

Inventory Capital Reagent Vol * $/gal 1,596

Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406

Retrofit Installation Factor 30% 325,322

Total Capital Investment, Retrofit Installed 1,409,728

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 162,661

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

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

Total Annual Direct Operating Costs 166,949

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068

Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018

See Summary page for notes and assumptions

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

#2 SNCR #2 SNCR 99 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

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 Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

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

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

See Summary page for notes and assumptions

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

#2 SNCR #2 SNCR 100 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #4

Emission Unit Number EU 004 Stack/Vent Number 0 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 905,717

 Purchased Equipment Total (B) 0% of control device cost (A) 905,717

 Installation - Standard Costs 15% of purchased equip cost (B) 163,029

Total Capital Investment (TCI) = DC + IC 1,277,232

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 14.8 50% 7.4 7.4 47,792

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

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

#4 SNCR #4 SNCR 101 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 905,717

Indirect Installation [1]

General Facilities 5% of purchased equip cost (A) 45,286

Engineerin & Home Office 10% of purchased equip cost (A) 90,572

Process Contingency 5% of purchased equip cost (A) 45,286

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143

Project Contingeny ( C) 15% of (A + B) 163,029

Total Plant Cost D A + B + C 1,249,889

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 24,998

Inventory Capital Reagent Vol * $/gal 2,345

Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232

Retrofit Installation Factor 30% 383,169

Total Capital Investment, Retrofit Installed 1,660,401

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 191,585

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131

Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1

Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166

Total Annual Direct Operating Costs 197,883

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

See Summary page for notes and assumptions

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

#4 SNCR #4 SNCR 102 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

NOx in 0.28 lb/MMBtu kW

NSR 1.37 equation 1.14

Power 2.9

Total 2.9

Reagent Use & Other Operating Costs Urea Use

17.23 lb/hr Neat equation 1.15

50% solution 71.0 lb/ft3 Density 50% Solution

34.46 lb/hr 3.6 gal/hr

1,220 gal $2,345 Inventory Cost

Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization

Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization

Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/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

See Summary page for notes and assumptions

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

#4 SNCR #4 SNCR 103 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Operating Unit: Utility Plant Heater Boiler #5

Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering

Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32o F Plant Cost Index

Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394

Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18

Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68o F

Dry Std Flow Rate 15,360 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 905,717

 Purchased Equipment Total (B) 0% of control device cost (A) 905,717

 Installation - Standard Costs 15% of purchased equip cost (B) 163,029

Total Capital Investment (TCI) = DC + IC 1,277,232

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

Emission Control Cost Calculation

Max Emis Annual Control Eff Controlled Emis Reduction Control Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 42.9 13.8 50% 6.9 6.9 51,494

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

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

#5 SNCR #5 SNCR 104 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 905,717

Indirect Installation [1]

General Facilities 5% of purchased equip cost (A) 45,286

Engineerin & Home Office 10% of purchased equip cost (A) 90,572

Process Contingency 5% of purchased equip cost (A) 45,286

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143

Project Contingeny ( C) 15% of (A + B) 163,029

Total Plant Cost D A + B + C 1,249,889

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 24,998

Inventory Capital Reagent Vol * $/gal 2,345

Intial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232

Retrofit Installation Factor 30% 383,169

Total Capital Investment, Retrofit Installed 1,660,401

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 191,585

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131

Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1

Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166

Total Annual Direct Operating Costs 197,883

Indirect Operating Costs

Overhead NA of total labor and material costs NA

Administration (2% total capital costs) NA of total capital costs (TCI) NA

Property tax (1% total capital costs) NA of total capital costs (TCI) NA

Insurance (1% total capital costs) NA of total capital costs (TCI) NA

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730

Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613

See Summary page for notes and assumptions

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

#5 SNCR #5 SNCR 105 of 106
US Steel - Minntac

Draft BART Emission Control Cost Analysis

Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Electrical Use

NOx in 0.28 lb/MMBtu kW

NSR 1.37 equation 1.14

Power 2.9

Total 2.9

Reagent Use & Other Operating Costs Urea Use

17.23 lb/hr Neat equation 1.15

50% solution 71.0 lb/ft3 Density 50% Solution

34.46 lb/hr 3.6 gal/hr

1,220 gal $2,345 Inventory Cost

Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 3,156

Utilization Rate: 28%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

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

Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization

Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization

Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/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

See Summary page for notes and assumptions

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

#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 

askoglund@barr.com 

Barr Engineering Company Appendix B 

4700 West 77th Street • Minneapolis, MN 55435-4803 

Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer

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

N

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

0 100

Kilometers

MODELING DOMAIN

Taconite BART Modeling

Taconite Industry Group

Minnesota

0 100

Miles

Legend

Modeling Domain

Class I Area

BWCA

Voyageurs
TERREL

Variable Description Value Default Comments

GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CTGPROC

Variable Description Value Default Comments

XREFKM Reference point coordinates for grid 168 n/aYREFKM Reference point coordinates for grid 720 n/a

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

CALMET

Variable Description Value Default Comments

NUSTA Number of upper air stations 4 14898, 14918, 94983, 4837

NX Number of X grid cells 40 n/a

NY Number of Y grid cells 30 n/a

XORIGKM Reference point coordinates for grid 168 n/a

YORIGKM Reference point coordinates for grid 720 n/a

NOOBS No Observation Mode 0 Y Include Surface, Upper Air and 

NSSTA Number of Surface Stations 74 n/a 74 surface weather stationsNPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations

RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with ObservatioRMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observatio

R1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with ObservatioR2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observatio

ISURFT Surface met. Stations to use for the surface temperature - n/a Hibbing Met station

IUPT Upper air station to use for the domain scale lapse rate - n/a International Falls Upper Air sta

ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper 

TRADKM Radius of influence for temperature interpolation 500 Y Similar to PSD with Observatio

JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 5

SIGMAP Radius of influence (km) 100 Y Precipitation Observations are 

Input Group 0bInput Group 2Input Group 2Input Group 2Input Group 4Input Group 5Input Group 6
CALPUFF

Variable Description Value Default Comments

NX Number of X grid cells in met grid 40 n/a

NY Number of Y grid cells in met grid 30 n/a

XORIGKM Reference point coordinates for met grid 168 n/a

YORIGKM Reference point coordinates for met grid 720 n/a

IBCOMP X index of LL corner 1 n/a

JBCOMP Y index of LL corner 1 n/a

IECOMP X index of UR corner 40 n/a

JECOMP Y index of UR corner 30 n/a

MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, an

NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyage

Input Group 11Input Group 17Input Group 4
Appendix C 

1. CALPUFF Modeling System 

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

from sources. This model was used in accordance with the guidelines found in the Best Available 

Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of 

Minnesota, Final1, with the modifications found in Appendix B. 

The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a 

number of pre-processing programs. These pre-processing programs are designed to prepare available 

meteorological and geophysical data for input into CALMET. Each of these modeling components are 

described below: 

• CALMET is a meteorological model that develops hourly wind and temperature fields on a threedimensional gridded modeling domain. Associated two-dimensional fields such as mixing 

heights, terrain elevations, land use categories and dispersion properties are also included in the 

file produced by CALMET. 

• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from 

one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical 

transformations as each puff moves away from the source, using the multi-dimensional grids 

generated by CALMET. 

• CALPUFF produces an output file containing hourly concentrations of pollutants which are 

processed by CALPOST to yield estimates of ambient air extinction coefficients and related 

measures of visibility impairment at selected averaging times and locations. 

Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate 

system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets 

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

 

1

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

Subject to BART in the State of Minnesota. 
CALMET 

Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data, 

precipitation data, and upper air data were used to generate the CALMET data set for use in the 

CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells 

(north-south) with a grid spacing of 12 km. This grid encompasses 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 Subjectto-Bart in the State of Minnesota. 

4

 40 CFR 51, Appendix Y. 

5

 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 
De minimis Modeling 

As a part of the streamlined BART approach, a method for removing insignificant sources from 

further BART evaluation was developed, with guidance from MPCA. Sources meeting a de 

minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV 

was used in this analysis. 

For this facility, 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 preBART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should 

reflect a maximum 24-hour average basis. 

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, 

respectively. 

Modeled Results 

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for 

the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 

0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are 

included in Table 6-3. 
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 threedimensional gridded modeling domain. Associated two-dimensional fields such as mixing 

heights, terrain elevations, land use categories and dispersion properties are also included in the 

file produced by CALMET. 

• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from 

one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical 

transformations as each puff moves away from the source, using the multi-dimensional grids 

generated by CALMET. 

• CALPUFF produces an output file containing hourly concentrations of pollutants which are 

processed by CALPOST to yield estimates of ambient air extinction coefficients and related 

measures of visibility impairment at selected averaging times and locations. 

Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate 

system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets 

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

 

1

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

Subject to BART in the State of Minnesota. 
CALMET 

Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data, 

precipitation data, and upper air data were used to generate the CALMET data set for use in the 

CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells 

(north-south) with a grid spacing of 12 km. This grid encompasses 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 Subjectto-Bart in the State of Minnesota. 

4

 40 CFR 51, Appendix Y. 

5

 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota. 
De minimis Modeling 

As a part of the streamlined BART approach, a method for removing insignificant sources from 

further BART evaluation was developed, with guidance from MPCA. Sources meeting a de 

minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV 

was used in this analysis. 

For this facility, 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 preBART visibility impacts, the post-BART emissions to be used for the visibility impacts analysis should 

reflect a maximum 24-hour average basis. 

Table 4-1 & Table 6-2 within this report describe the pre and post-BART model input parameters, 

respectively. 

Modeled Results 

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for 

the predicted post-BART emission scenario(s). Results for the 98th percentile and number of days above 

0.5 dV at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are 

included in Table 6-3. 
N

Barr Footer: Date: 7/5/2006 1:27:58 PM File: I:\projects\23\00\Minntac.mxd User: ams

100 0 100 200

Meters

Minntac Aerial Photo

100 0 100 200

Meters





















Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

Combustion Controls

1 Overfire Air (OFA) Y N --- --- --- x NOx formation front is not stationary in an indurating furnace Combustion air is separated into p

achieve complete burnout and to e

than NOx

2 External Flue Gas Recirculation (EFGR) Y Y N --- --- x x Mixes flue gas with combustion ai

therefore reduces flame temperatu

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 Noxygen, flame temperature, and/o

4 Induced Flue Gas Recirculation Burners Y Y N --- --- x x x Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in 5 Low Excess Air Y N --- --- --- x Need high O2 for process requirements and product quality Reduces oxygen content in flue g

6 Burners out of Service (BOOS) Y N --- --- --- x Need capacity of all burners for worst case scenario Shut off the fuel flow from one bur

lean zones

7 Fuel Biasing Y N --- --- --- x Power plant technology

Combustion is staged by diverting lower ones or from the center to th

fuel-lean zones 

8 Reburning Y N --- --- --- x Kiln configuration not correct for this technology.

Part of the total fuel heat input is iabove the primary (main burners) (re-burn zone), where hydrocarbo

elemental nitrogen

9 Load Reduction N --- --- --- --- x Power plant technology -product demand side solution This is a strategy to reduce load o

electrical demand throught efficien

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 

11 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burn

required to be burned. Specific e

12

Coal Addition to Pellets with 

Low Excess Air in the 

Induration Furnace

N --- --- --- --- x Check on status of research Reduce flame temperature and en

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 pe

energy use of the kiln 

14 Combustion Zone Cooling Y N --- --- --- x Boiler technology Cooling of the primary flame zone 

surfaces

15 Alternate Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Site-specific x x

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with soliNOx by using a fuel with less nitro

16 Oxygen Enhanced Combustion N --- --- --- --- x Research level A small fraction of the combustion 
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

17 Preheat Combustion N --- --- --- --- x Research level

Pulverized coal preheated and vocompounds are released in a contnitrogen compounds are reduced 

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. W

utilizes high velocity overfire air. A

with ammonia injection (Rotamix)

19 NOx CEMS Y N --- --- --- x x Optimization of combustion

20 Parametric Monitoring Y N --- --- --- x x Optimization of combustion

38 Catalyst Injection (EPS Technologies) N --- --- --- --- x Research Level A combustion catalyst is directly in

delivered to the combustion site, i

the dynamics of the flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Y N --- --- --- x x For clean services. Too much stuff in flue gas would poison catalyst Under near stoichiometric conditio

reduced by CO, resulting in nitrog

22 Low Temperature Oxidation (LTO) - Tri-NOx® Y N --- --- --- x x Used for higher flue gas concentrations Utilizes an oxidizing agent such a

including NOx

23 Low Temperature Oxidation (LTO) - LoTOx Y 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 a

including NOx

24 Selective 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 

catalyst to convert NOx into N2 an

25 Regenerative SCR Y N --- --- --- x Clean side only

26 Selective 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 chemical

convert NO to molecular nitrogen, 

27 Adsorption N --- --- --- --- x Still in research stages. Use of char (activated carbon) to 

28 Absorption Y N --- --- --- x Similar to TriNOx

Use of water, hydroxide and carbosolutions, molten alkali carbonate

nitrogen.

29 Oxidizer Y N --- --- --- x Redundant to regenerative SCR

Gas stream is sent through the re

direct fired oxidizer where pollutandestroyed.
Taconite BART Analysis

NOx Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Taconite distributed without the full text onot taken out of context.

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other

2

Comments Bas

30 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. 

passes through a novel glass-tube 

hydrated to H2SO4 vapor and then 

sulfuric acid (H2SO4).

31 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated Dry sorbent injection upstream of 

ammonia injection upstream of a z(SCR) catalyst incorporated in the 

32 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pr

conversion of sulfur and nitrogen easily collected by conventional m

33 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

thermal plasma.On recent project, the vender was applications.

34 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept 

tests).

Uses a regenerable sorbent to sim

flue gas from coal-fired utility and SO2 is converted to a saleable su

sulfur, or sulfuric acid) and the NO

35 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with cop

of alumina, to form copper sulfatebefore the absorption reactor and reaction occurs that reduces the nregeneration step, the copper sulfreducing agent, such as natural gSO2.

36 Cold Plasma N --- --- --- --- x Research Level

37 Biofilters Y N --- --- --- x Not applicable to furnaces.

Gas stream is passed through a fiPollutants are adsorbed and degr

the products carbon dioxide and w

38 Pahlman Process N --- --- --- --- x Research Level

Gas stream is passed through a fideveloped, small-particle, high-subeen deployed. Pollutants are rem

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

1 Wet Scrubbing (High Efficiency) Y Y Y Y 90-95% x x x Absorption and reaction using an al2 Wet Scrubbing (Low Efficiency) Y Y Y Y <50% x x x Absorption and reaction using an al3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y 80% x x Suspended particles are separated f

collected in hoppers

4 Dry sorbent injection Y Y Y N --- x x x

Pulverized lime or limestone is dire

filter. Dry sorption of SO2 onto the 

particles are collected with a fabric 

5 Spray Dryer Absorption (SDA) Y Y Y N --- x x Lime slurry is sprayed into an absor

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 conten

7 Load Reduction N --- --- --- --- x Power plant technology This is a strategy to reduce load on 

demand throught efficiency project

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 

9 Coal Drying Y N --- --- --- x Applies only to facilities that burn coal Dry coal will increase the as-burned 

to be burned. Specific energy effici

10 Bio Filters N --- --- --- --- x Research level

Gas stream passes through a packe

supports the growth of active bacte

biodegraded or biotransformed into water, chloride ion in water, sulfate 

11 CANSOLV Regenerable SO2 N --- --- --- --- x Research level

An aqueous solution of proprietary 

countercurrent absorption tower. Tstripping, giving a byproduct of pur

recycling to the absorber.

12 Pahlman Process N --- --- --- --- x Research level

Gas stream is passed through a filteparticle, high-surface area metal oxremoved from the gases by adsorpt

13 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated

Dry sorbent injection upstream of tinjection upstream of a zeolitic seleincorporated in the baghouse to red

14 Electron (E-Beam) Process N --- --- --- --- x No operating commercial applications on coal Electron beam irradiation in the pre

conversion of sulfur and nitrogen ocollected by conventional methods 
Taconite BART Analysis

SO2 Control

Indurating Furnaces

Available and Applicable Review

Step 1 Step 2 Reference(s)

This table is part of the Tacondistributed without the full texnot taken out of context.

Reference No.1 SO2 Pollution Control Technology

Is this a generally 

available control 

technology?

Is the control technology 

available to indurating 

furnaces?

Is the control technology 

applicable to this specific 

source?

Is it technically feasible 

for this source? Approximate Control Efficiency

MPCA Taconite BART 

Report

MPCA BART Guidance 

(Attachment 2)

Other2 Comments B

15 Electrocatalytic Oxidation N --- --- --- --- x Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NO

dioxide (NO2), sulfuric acid, and m

plasma.On recent project, the vender was d

16 NOXSO N --- --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simul

from coal-fired utility and industria

a saleable sulfur by-product (liquid 

NOx is converted to nitrogen and o

17 Copper-Oxide N --- --- --- --- x Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copp

alumina, to form copper sulfate. Amabsorption reactor and a selective c

reduces the nitric oxides in the flue 

is reduced in a regenerator with a rconcentrated stream of SO2.

18 SNOX N --- --- --- --- x Early commercial development stage

Catalytic reduction of NOx in the p

catalytic oxidation of SO2 to SO3. T

through a novel glass-tube condens

and then condensed to a concentrat

19 Cold Plasma N --- --- --- --- x Research level

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.

2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
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 "thin commenting on the need to exceed Munreasonableness. 

70 FR 25210 CAIR CAIR 1300 Estimated Marginal cost 2009 

BART(proposed rule) 200-1000 

BART proposed lists this as values for which is still assumed, or .1 to .15 lb/Mfinal to give states flexibility to require 

FR Notice 5MAY04 Proposed Rule bypasses aren't BART, only 100% scru

BART(proposed rule) 

0.2 lb/MMBtu for NOx is assumed reasome sources may need SCR to get thidiscretion of the cost vs. visibility valu

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 (Techn

Updating Model) to develop the margi

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 

did consider incremental value. Section

WRAP 3000 WRAP Trading Program 

Methodology EPA - Referenced by 

Wrap 

References EPA-600S\7-90-018. Low $500-3000/ton, High is over $3000/ton 

The dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory 

and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BAR

support an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,0SO2 removed. The BART presumptive limits were set based on cost effective controls that were on average less tha

example, the presumptive SO2 limit was established based on an average cost effectiveness of less than $1,000/ton. 

extends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and di

ease of comparison, the federally established ranges for NOx and SO2 were used as a BART cost threshold basis. 
Taconite BART Analysis

NOX Control

Process Boilers

Available and Applicable Review

Step 1 Step 2

Reference No.

1

NOx Pollution Control 

Technology

Is this a generally available control technology?Is the control technology available to process boilers?Is the control technology applicable to this specific source?Is it technically feasible for this source?

Approximate Control 

Efficiency

Combustion Controls

1

External 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%

4

Induced Flue Gas 

Recirculation Burners Y 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

Post Combustion Controls

21 Non-Selective Catalytic 

Reduction (NSCR) Y N --- --- ---

22 Low Temperature Oxidation 

(LTO) - Tri-NOx® Y N --- --- ---

23 Low Temperature Oxidation 

(LTO) - LoTOx Y Y Y Y 90%

24 Selective Catalytic 

Reduction (SCR) Y Y Y Y 80%

25 Regenerative SCR Y Y Y Y 70%

26 Selective Non-Catalytic 

Reduction (SNCR) Y Y Y Y 50%

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