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Northshore Mining Company Analysis of Best Available Retrofit 

Technology (BART) 

Table of Contents 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

List of Tables 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

List of Figures 

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

List of Appendices 

Appendix A Control Cost Analysis Spreadsheets 

Appendix B Changes to MPCA BART Modeling Protocol 

Appendix C Visibility Impacts Modeling Report 

Appendix D Applicable and Available Retrofit Technologies for Indurating Furnaces 

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

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

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

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

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

NMC for its taconite processing plant. 

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

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

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

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

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

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

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

the facility subject to BART. 

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

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

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

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

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

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

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

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

the remaining useful life of the source. 

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

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

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

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

achievable control technology (MACT) standard1

. The existing WWESPs adequately control 

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

no additional controls. 

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

. This modeled 

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

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

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

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

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

to reduce their visibility impairment pollutants emission rates. 

 

1

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

and Institutional Boilers and Process Heaters 

2

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

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

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

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

NMC for its taconite processing plant. 

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

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

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

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

CFR part 51, in 300 through 309. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary 

Waters Canoe Area (BWCA)] and BART-eligible units illustrated above. Facilities indicated in yellow are 

future facilities.

(Source MPCA BART-Strategy October 4, 2005) 

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

worst days under natural conditions by 20643. Assuming a uniform rate of progress, the default glide 

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

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

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

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

non-air quality impacts. 

 

3

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

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

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

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

improvement goals. 

2.A BART Eligibility 

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

must meet the following three conditions: 

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

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

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

plants, sulfur recovery plants, etc.); 

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

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

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

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

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

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

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

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

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

requirements. 

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

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

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

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

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

are BART-eligible. 
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2.B BART Determinations 

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

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

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

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

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

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

impacts.4

 The five steps of a BART analysis are: 

Step 1 - Identify all Available Retrofit Control Technologies 

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

generally available for each applicable emission unit. Available retrofit control 

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

Determinations Under the Regional Haze Rule) as follows: 

Available retrofit technologies are those air pollution control technologies 

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

regulated pollutant under evaluation. Air pollution control technologies can 

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

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

are available for BART purposes and must be included as control 

alternatives. The control alternatives can include not only existing controls 

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

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

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

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

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

has not been demonstrated in practice.5

Step 2 - Eliminate Technically Infeasible Options 

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

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

 

4

 40 CFR 51 Appendix Y 

5

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

BART analysis? 

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

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

” 

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

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

dissimilar source type.7

” 

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

is undergoing the BART analysis? 

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

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

type.8

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

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

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

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

applied previously.9” 

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

not technically feasible? 

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

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

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

technology10.” This also involves the identification of “un-resolvable technical 

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

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

technological difficulty evaluated as part of the economic analysis11. 

 

6

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

7

 IBID 

8

 IBID 

9

 IBID 

10 IBID 

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

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

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

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

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

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

analysis and the information from vendor guarantees12

. 

Step 3 - Evaluate Control Effectiveness 

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

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

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

Step 4 - Evaluate Impacts and Document Results 

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

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

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

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

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

quality environmental impacts. 

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

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

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

Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model 

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

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

control cost analysis worksheets as found in Appendix A. 

Step 5 - Evaluate Visibility Impacts 

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

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

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

 

12 IBID 

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

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

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

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

improvement that can be reasonably attributed to each technology. 

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

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

controls should be considered, and specifically states: 

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

of controls would affect the viability of plant operations. 

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

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

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

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

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

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

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

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

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

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

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

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

information is available.14

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

the BART requirements and requires compliance within a reasonable period of time15.” Those limits 

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

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

techniques that ensure compliance on a continuous basis16.” which could include the incorporation of 

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

 

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

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

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

technological or economic limitations make measurement methodology for an emission unit 

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

standard, or combination of these types of standards17.” 

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

the Minnesota SIP. 

 

17 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 
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3. Streamlined BART Analysis 

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

a streamlined approach for BART analyses18. The streamlined approach will allow both states and the 

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

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

the results of the streamlined approach. 

3.A Indurating Furnaces 

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

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

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

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

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

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

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

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

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

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

3.B PM-Only Taconite MACT Emission Units 

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

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

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

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

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

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

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

emissions [FR, December 18, 2002, page 77570]. Therefore, the emissions from the pellet coolers 

are considered to have a negligible impact on visibility impairment, and no control requirements 

under the MACT standard is consistent with the intention of the BART analysis. 

 

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

19 40 CFR 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing 
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Since the MACT standard was established recently and will become effective in 2006, the technology 

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

to be equivalent to MACT according to MPCA guidance. 

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

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

The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonMACT sources are addressed in section 3.D). No equipment that emits fugitive PM has been 

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

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

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

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

They include units such as: 

• Bentonite storage and handling 

• Additive storage and handling 

• Concentrate storage and handling 

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

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

BART. 

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

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

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

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

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

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

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

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

establish BART for these sources. 

3.E Other Combustion Units 

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

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

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

SO2. 

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

analysis is provided in a separate report. 

3.F Visibility Impact Modeling for Negligible Impacts 

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

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

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

modeling. 

 

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

Emission 

Unit # Emission Unit Description 

VisibilityImpairing 

Pollutant 

Applicable 

Limit1 

gr/dscf 

Maximum Daily 

lbs/day2

3.A Indurating Furnaces 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 100 Furnace 11 Hood Exhaust PM 0.01 272 

EU 104 Furnace 11 Waste Gas PM 0.01 255 

EU 104 Furnace 11 Waste Gas PM 0.01 255 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 110 Furnace 12 Hood Exhaust PM 0.01 272 

EU 114 Furnace 12 Waste Gas PM 0.01 255 

EU 114 Furnace 12 Waste Gas PM 0.01 255 

3.B PM-Only Taconite MACT Emission Units 

EU 008 East Car Dump PM 0.008 32 

EU 010 Fine Crusher Bin Storage – East PM 0.008 45 

EU 016 Crushed Ore Conveyors – East PM 0.008 12 

EU 017 Fine Crushing Line 101 PM 0.008 8 

EU 018 Fine Crushing Line 102 PM 0.008 8 

EU 019 Fine Crushing Line 103 PM 0.008 8 

EU 020 Fine Crushing Line 104 PM 0.008 8 

EU 031 Concentrator Transfer Bin – East PM 0.008 8 

EU 044 Concentrator Bin - Section 101 PM 0.008 18 

EU 045 Concentrator Bin - Section 102 PM 0.008 18 

EU 046 Concentrator Bin - Section 103 PM 0.008 18 

EU 047 Concentrator Bin - Section 104 PM 0.008 18 

EU 048 Concentrator Bin - Section 105 PM 0.008 18 

EU 049 Concentrator Bin - Section 106 PM 0.008 18 

EU 050 Concentrator Bin - Section 107 PM 0.008 18 

EU 051 Concentrator Bin - Section 108 PM 0.008 18 

EU 052 Concentrator Bin - Section 109 PM 0.008 18 

EU 053 Concentrator Bin - Section 110 PM 0.008 18 

EU 120 Furnace 11 Discharge PM 0.008 95 

EU 121 Furnace 12 Discharge PM 0.008 95 

EU 122 Furnace 11 Screening PM 0.008 95 

EU 124 Furnace 12 Screening PM 0.008 95 

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

EU 077 Furnace 11 Day Bin Collector PM 0.01 4 

EU 078 Furnace 11 Air Slide Collector PM 0.01 4 

EU 079 Furnace 12 Day Bin Collector PM 0.01 4 

EU 080 Furnace 12 Air Slide Collector PM 0.01 4 

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

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

EU 083 Bentonite Unloading Collector PM 0.01 4 

EU 084 Supplemental Bentonite Unloading Collector PM 0.01 10 

3.E Other Combustion Units lb/mmBtu 

EU 003 Process Boiler #1 PM 0.6 45 

EU 004 Process Boiler #2 PM 0.6 45 

1

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

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

2

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

BART Eligible Units 

As indicated in U.S. EPA’s final BART guidance21, one of the factors to consider when determining 

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

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

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

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

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

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

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

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

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

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

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

approach when assessing visibility impacts. 

In order to estimatedetermine the visibility improvement resulting from the retrofit technology, the 

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

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

the maximum 24-hour actual emissions23

. 

4.A MPCA Subject-to-BART Modeling 

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

this facility is subject-to-BART. 

4.B Facility Baseline Modeling 

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

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

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

Appendix B. 

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

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

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

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

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

EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

003 

Process 

Boiler #1 402 279 45 SV003 631471.5 5238482.8 131 

EU 

004 

Process 

Boiler #2 402 279 45 SV003 631471.5 5238482.8 131 

EU 

008 

East Car 

Dump NA NA NA NA 32 SV008 631224.7 5238953.7 83 

EU 

010 

Fine 

Crusher 

Bin 

Storage - 

East 

NA NA NA NA 45 SV010 631316.0 5238925.9 101 

EU 

016 

Crushed 

Ore 

Conveyo

rs - East 

NA NA NA NA 12 SV016 631314.1 5238884.6 69 

EU 

017 

Fine 

Crushing 

Line 101 

NA NA NA NA 8 SV017 631322.8 5238896.8 69 

EU 

018 

Fine 

Crushing 

Line 102 

NA NA NA NA 8 SV018 631328.6 5238905.9 69 

EU 

019 

Fine 

Crushing 

Line 103 

NA NA NA NA 8 SV019 631334.4 5238915.1 69 

EU 

020 

Fine 

Crushing 

Line 104 

NA NA NA NA 8 SV020 631341.2 5238924.2 69 

EU 

031 

Concentr

ator 

Transfer 

Bin - 

East 

NA NA NA NA 8 SV031 631455.6 5238785.1 83 

EU 

044 

Concentrator Bin - 

Section 

101 

NA NA NA NA 18 SV044 631473.1 5238808.5 93 

EU 

045 

Concentrator Bin - 

Section 

102 

NA NA NA NA 18 SV045 631486.7 5238828.7 93 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

046 

Concentrator Bin - 

Section 

103 

NA NA NA NA 18 SV046 631501.3 5238849.0 93 

EU 

047 

Concentrator Bin - 

Section 

104 

NA NA NA NA 18 SV047 631514.8 5238870.3 93 

EU 

048 

Concentrator Bin - 

Section 

105 

NA NA NA NA 18 SV048 631529.4 5238890.7 93 

EU 

049 

Concentrator Bin - 

Section 

106 

NA NA NA NA 18 SV049 631544.0 5238911.0 93 

EU 

050 

Concentrator Bin - 

Section 

107 

NA NA NA NA 18 SV050 631557.6 5238932.3 93 

EU 

051 

Concentrator Bin - 

Section 

108 

NA NA NA NA 18 SV051 631572.1 5238952.6 93 

EU 

052 

Concentrator Bin - 

Section 

109 

NA NA NA NA 18 SV276 631590.6 5238980.0 93 

EU 

053 

Concentrator Bin - 

Section 

110 

NA NA NA NA 18 SV053 631605.2 5239000.3 93 

EU 

077 

Furnace 

11 Day 

Bin 

Collector 

NA NA NA NA 4 SV077 631274.7 5238341.3 97 

EU 

078 

Furnace 

11 Air 

Slide 

Collector 

NA NA NA NA 4 SV078 631315.5 5238399.2 97 

EU 

079 

Furnace 

12 Day 

Bin 

Collector 

NA NA NA NA 4 SV079 631276.6 5238344.4 97 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

080 

Furnace 

12 Air 

Slide 

Collector 

NA NA NA NA 4 SV080 631318.4 5238402.2 97 

EU 

081 

East 

Pelletizer 

Bentonite 

Storage - 

Bin 3,4 

NA NA NA NA 4 SV081 631311.2 5238408.2 129 

EU 

082 

East 

Pelletizer 

Bentonite 

Storage - 

Bin 5,6 

NA NA NA NA 4 SV082 631318.0 5238419.3 130 

EU 

083 

Bentonite 

Unloadin

g 

Collector 

NA NA NA NA 4 SV083 631320.9 5238422.4 127 

EU 

084 

Supplem

ental 

Bentonite 

Unloadin

g 

Collector 

NA NA NA NA 10 SV084 631331.9 5238426.5 117 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV101 631339.1 5238341.2 121 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV102 631344.3 5238338.3 121 

EU 

100 

Furnace 

11 Hood 

Exhaust 

284 410 272 SV103 631348.4 5238335.3 121 

EU 

104 

Furnace 

11 Waste 

Gas 

142 1498 255 SV105 631343.4 5238298.9 134 

EU 

104 

Furnace 

11 Waste 

Gas 

142 1498 255 SV104 631334.2 5238298.9 134 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV111 631361.5 5238372.7 121 
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EU # 

EU 

Descriptio

n 

SO2

Maximum 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

SO2 24-

hour 

Actual 

Emission 

NOx

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

NOx 24-

hour 

Actual 

Emission 

PM2.5

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for 

PM2.5 24-

hour 

Actual 

Emission 

PM10

Maximu

m 

24-hr 

Emission 

Rate 

(lbs/day) 

Basis for PM10 24-

hour 

Actual 

Emission SV # 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height of 

Opening 

from 

Ground 

(ft) 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV112 631365.6 5238369.7 121 

EU 

110 

Furnace 

12 Hood 

Exhaust 

284 410 272 SV113 631370.7 5238366.8 121 

EU 

114 

Furnace 

12 Waste 

Gas 

142 1498 255 SV114 631354.5 5238331.4 134 

EU 

114 

Furnace 

12 Waste 

Gas 

142 1498 255 SV115 631362.7 5238325.5 134 

EU 

120 

Furnace 

11 

Discharg

e 

NA NA NA NA 95 SV120 631383.5 5238300.6 91 

EU 

121 

Furnace 

12 

Discharg

e 

NA NA NA NA 95 SV121 631405.9 5238332.1 91 

EU 

122 

Furnace 

11 

Screenin

g 

NA NA NA NA 95 SV122 631387.6 5238297.7 91 

EU 

124 

Furnace 

12 

Screenin

g 

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

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

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

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

methods to assess the expected post-BART visibility improvement: 

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

identifies the Minnesota facilities that are subject to BART25, a source "contributes to 

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

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

protected Class I area receptor. 

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

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

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

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

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

98th percentile of the baseline conditions exceeds the threshold of 0.5 dV However, the results also 

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

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

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

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

analysis in section 6 of this document. 

The full modeling analysis is presented in Appendix C. 

 

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

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

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

Subject-to-BART in the State of Minnesota. 
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Table 4-2 Baseline Visibility Modeling Results 

2002 2003 2004 

2002 – 2004 

Combined 

Class I Area 

with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

BWCA 1.1 34 1.1 34 1.3 38 1.1 106 
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5. Full BART Analysis for BART Eligible Emission 

Units 

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

5.A Indurating Furnace 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

provides excellent control and removal of PM and SO2. 

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

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

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

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

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

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

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

design is not used by any other taconite producer. 

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

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

oil that is one of the permitted fuels. 

5.A.i Sulfur Dioxide Controls 

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

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

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

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

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

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

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

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

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

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

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

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

technology is technically feasible for indurating furnaces. 

Wet Walled Electrostatic Precipitator (WWESP) 

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

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

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

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

rapping and fall into hoppers for collection and removal. 
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A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

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

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

absorber. WWESPs are designed to remove emissions to levels less than 10 parts per million SO2 . 

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

as SO2 flue gas concentration, fuel used, and ore composition. NMC currently employs a WWESP 

designed for removal of particulate matter and SO2. The addition of a secondary WWESP would act 

as a polishing scrubber and would experience reduced control efficiency due to lower SO2 inlet 

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

process specific operating parameters. 

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

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

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

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

Wet Scrubbing (High and Low Efficiency) 

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

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

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

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

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

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

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

packed-bed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet 

scrubber could be as low as 30% control efficiency. A low efficiency SO2 could be a venturi rod 

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

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

emission reduction. 

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

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

reactions are shown in the following equations: 
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CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

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

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

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

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

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

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

follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

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

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

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

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

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

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

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

oxygen of 2-3% is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency 

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

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

oxidation of the pellet. The excess air dilutes the SO2 concentration as well as creates higher flow 

rates to control. Additionally, the varying sulfur concentration within the pellet causes fluctuations of 

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

of the wet scrubber. 

As stated in the beginning of this section, WWESPs are currently in place on the furnace exhausts 

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

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

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

available technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

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

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

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

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

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

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

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

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

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

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

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

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

content and will not be further evaluated in this report. 

Spray Dryer Absorption (SDA) 

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

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

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

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

desulfurization (FGD) may also be used. 

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

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

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

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

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

be further evaluated in this report. 
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Energy Efficiency Projects 

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

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

emissions. An example of an energy efficiency project could be to preheat incoming make-up air or 

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

and many other variables. 

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

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

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

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

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

projects as they arise. 

Alternate Fuels 

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

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

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

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

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

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

option, not to direct the fuel choice.26 

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

 

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

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

at NMC. 

Step 2 Conclusion 

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

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

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

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

Technical Feasibility 

SO2 Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

Secondary Wet Scrubbing (High 

Efficiency) 

Yes Yes Yes 

Secondary Wet Scrubbing (Low 

Efficiency) 

Yes Yes Yes 

Secondary Wet Walled Electrostatic 

Precipitator (WWESP) 

Yes Yes Yes 

Dry sorbent injection Yes Yes No 

Spray Dryer Absorption (SDA) Yes Yes No 

Alternative Fuels Yes No No 

Energy Efficiency Projects Yes Yes No 

Coal Processing Yes No No 

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

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

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

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

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Secondary Wet Walled Electrostatic Precipitator (WWESP) 80 

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

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

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

impacts to better differentiate as presented below. 

Economic Impacts 

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

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

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

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

following equation: 

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

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

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

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

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

adjusted for the specific flow rates and pollutant concentrations. 

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

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

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

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

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

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

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

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

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

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

 

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

28 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 
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Table 5-3 Indurating Furnace SO2 Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

(MM$) 

Operating Cost

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental

Control 

Cost 

($/ton) 

Secondary Wet Scrubber 

Furnace 11 Hood 

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

Furnace 11 Waste 

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

Furnace 12 Hood 

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

Furnace 12 Waste 

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

Secondary Wet Walled Electrostatic Precipitator (WWESP) 

Furnace 11 Hood 

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

Furnace 11 Waste 

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

Furnace 12 Hood 

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

Furnace 12 Waste 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 
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impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant29. 

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

evaluated for visibility improvement, energy and other impacts. 

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

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

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

Energy and Environmental Impacts 

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

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

this analysis. 

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

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

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

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

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

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

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

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

controls for SO2. 

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

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

5.A.ii Nitrogen Oxide Controls 

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

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

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

combustion. 

 

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

Processing Plant, Fairmont, MN Permit 09100059-002. 
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• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

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

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

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

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

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

minor amounts of NOx are emitted as prompt NOx. 

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

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

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

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

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

much cooler, leading to lower thermal NOx generation. 

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

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

evaluated. See Appendix D for the current status of the availability and applicability of retrofit 

control technologies. 

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

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

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

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

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

the technology is technically feasible for indurating furnaces. 

External Flue Gas Recirculation (EFGR) 

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

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

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

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

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

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

the burner tip. 

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

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

1. The waste gas in an induration furnace typically has near atmospheric oxygen vs. a boiler 

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

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

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

air instead of an inert gas. 

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

F in order to meet 

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

Application of EFGR would reduce flame temperatures. Lower flame temperatures 

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

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

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

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

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

equipment failures. 

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

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

Low- NOx Burners 

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

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

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

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

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

burner. 

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

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

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

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

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

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

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

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

indurating section of any straight grate taconite furnace. 

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

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

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

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

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

feasible option at NMC. 

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

are not yet commercially available. Some incorporate various fuel dilution techniques to reduce 

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

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

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

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

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

the development phase. 

 Induced Flue Gas Recirculation Burners 

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

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

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

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

burners in high temperature applications is 25-50%. 

As noted above, taconite furnaces are required to operate at high oxygen levels.. At these oxygen 

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

combustion because excessive amounts of oxygen would be injected into the flame pattern. In 
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addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be 

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

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

would adversely affect taconite pellet product quality. 

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

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

Energy Efficiency Projects 

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

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

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

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

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

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

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

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

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

projects as they arise. 

Ported Kilns 

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

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

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

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

bed, and closed when it rotates out of position. 

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

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

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

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

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

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

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

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

Reduction of NOx emissions through alternative fuel usage has been achieved at taconite grate kilns 

through the use of solid fuel. In these cases the reduction resulted due to changes from pulverized 

solid fuel dispersal in the kiln that results in lower flame temperature compared to other fuels. 

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

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

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

further evaluated in this report. 

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

option, not to direct the fuel choice.30 

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

fuel usage as the feasibility arises. 

Process Optimization with NOx CEMS or Other Parametric Monitoring 

MPCA guidance lists “NOx CEMS” as a work practice/operational change for controlling NOx

emissions31. Parametric monitoring is a possible derivative of this alternative. 

Based on conversations with MPCA staff, this work practice would include process adjustments, or 

optimization, to minimize NOx emissions. The impact of the process adjustments would be measured 

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

emissions from boilers. 

One taconite plant has installed NOx CEMS to monitor emissions but not to optimize NOx emissions 

through process fine tuning. That plant has experienced some reduction in NOx emissions but these 

encompass multiple variables and are not directly attributed to process fine tuning with the NOx 

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

 

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

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

technically feasible control option for the taconite industry: 

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

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

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

process is different from a boiler. 

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

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

minimize NOx formation. 

• At some operations, the operating parameters which generally influence the rate of NOx

generation such as flame temperature, fuel usage and excess air are relatively constant during 

operation of the furnace, independent of process operation variability. This indicates that NOx

formation may not be dependent upon controllable operating parameters. In the absence of 

controllable parameters, process optimization would not be effective at controlling NOx

emissions. 

Based upon this information, there is no indication that further emission reductions would be 

achieved through the use of the process optimization, using NOx CEMS or other parametric 

monitoring, as a control technology. Therefore, process optimization as a control option will not be 

evaluated further in this report. 

Post Combustion Controls 

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

combustion process. The two main techniques in commercial service include the selective non 

catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a 

number of different process systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below.
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Non-Selective Catalytic Reduction (NSCR) 

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

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

primarily in natural gas combustion applications. 

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

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

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

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

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

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

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

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

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

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

this report. 

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction 

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

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

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

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

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

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

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

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

corrosion problems. 

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

temperature range. However, these catalysts are very expensive. 
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Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

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

low loads because of the low gas temperature. 

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

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

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

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

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

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

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

recovery. 

The benefits of RSCR are: 

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

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

thermal efficiency of 60% to 70%. 

• Application of RSCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

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

indurating furnace: 

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

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

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

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

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

to the erosive nature of the taconite dust; 

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

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

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

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

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

identify mitigation methods if needed. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

BART analysis. 

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

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

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

technically feasible. 

Low Temperature Oxidation (LTO) 

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

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

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

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

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 
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nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

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

Tri-NOx

®

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

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

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

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

®

 is 

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

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

Therefore, Tri-NOx

®

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

BART analysis. 

Low Temperature Oxidation (LoTOx®

) 

BOC Gases’ Lo-TOx®

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

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

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

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

 is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 
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needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be 

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

generation. 

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

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

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

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

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

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

different type of process. 

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

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

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

For example, the current installations of LoTOx®

 are on sources with flue gas flow rates from 150 – 

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

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

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

and could be problematic in maintaining the current removal efficiencies. 

In addition, only two of BOC’s LoTOx®

 installations are fully installed and operational applications. 

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

demonstrated to be an effective technology in widespread application. 

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

indurating furnace: 

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

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

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

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

there can be more than 400 pounds per hour of taconite dust in the flue gas which could 

consume a significant amount of the ozone being generated which may change the reaction 
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kinetics; consequently, this would necessitate either an increase in the amount of ozone 

generated or a decrease in the estimated control efficiency; 

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

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

• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to 

an indurating furnace waste gas could present technical problems which were not 

encountered, or even considered, in the existing LTO applications; 

• An LTO system at a taconite facility would also be a source of nitrate discharge to the 

tailings basin which would change the facility water chemistry which could cause operational 

problems and would likely cause additional problems with National Pollutant Discharge 

Elimination System (NPDES) discharge limits and requirements. 

Application of this technology has not been applied to taconite induration furnaces, to airflows of the 

magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. 

Using LTO at a taconite plant would require research, test runs, and extended trials to identify 

potential issues related to design for high airflows and impacts on plant systems, including the 

furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 

performance would be forthcoming in advance of a demonstration project. The timeline required to 

perform such a demonstration project would likely be two years to develop and agree on the test 

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs 

for a reasonable study period, and evaluate and report on the results. The results would not be 

available within the time window for establishing emission limits to be incorporated in the state 

implementation plan (SIP) by December 2007. 

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

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

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

Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for 

this application and will not be evaluated further. 
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Step 2 Conclusion 

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

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

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

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

Technical Feasibility 

NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas 

Recirculation (EFGR) Yes Yes No 

Low- NOx Burners Yes Yes No 

Induced Flue Gas 

Recirculation Burners Yes Yes No 

Energy Efficiency Projects Yes Yes No 

Ported Kilns Yes No No 

Alternative Fuels Yes Yes No 

Process Optimization using 

NOx CEMS Yes No No 

Non-Selective Catalytic 

Reduction (NSCR) Yes No No 

Selective Catalytic 

Reduction (SCR) with 

conventional reheat 

Yes Yes Yes 

Regenerative SCR Yes No No 

Selective Non-Catalytic 

Reduction (SNCR) Yes No No 

Low Temperature Oxidation 

(LTO) Yes No No 

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

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

control options as identified in Step 2. 

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness 

NOx Pollution Control 

Technology 

Approximate Control 

Efficiency 

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

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

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

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

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

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

adjusted to reflect site specific flow rates and pollutant concentrations. 

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

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

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

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

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

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

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

in Appendix A. 

Table 5-6 Indurating Furnace NOx Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Total Annual 

Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

Selective Catalytic 

Reduction (SCR) 

With Reheat 

 

Furnace 11 Hood 

Exhaust 

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

Furnace 11 Waste 

Gas 

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

Furnace 12 Hood 

Exhaust 

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

Furnace 12 Waste 

Gas 

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

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

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

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

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

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

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

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

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

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

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

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

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

threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are 

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant32

. 

Therefore, all air pollution controls with annualized costs less than this screening threshold will be 

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost column in Table 5-6 is intended to present the incremental value of each 

technology as compared to the technology with the next most effective alternative. Since none of the 

NOx reduction technologies are cost effective, the incremental cost is not applicable. 

Energy and Environmental Impacts 

Because the cost of NOx controls for NMC furnaces is so high and does not meet a reasonable 

definition of cost effective technology, this technology is removed from further consideration in this 

analysis. 

5.A.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. The economic impacts of controls for NOx are not reasonably cost effective, so visibility 

impacts were not modeled for NOx controls. Refer to Table 4-2 for a summary of the modeled 24-

hour maximum emission rates and their computational basis for the existing controls for NOx. 

 

32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 
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Visibility impacts with SO2 controls are presented in section 6. Table 6-1 provides a summary of the 

SO2, NOx, and PM10 emissions for each modeling scenario, 
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5.B External Combustion Sources 

Two natural gas and fuel oil fired process boilers require BART analysis. These boilers are back-up 

boilers to the main NMC Power House boilers to provide steam required to operate the taconite plant 

during Power House outages. These boilers are only permitted to use gas and distillate oil for fuel. 

5.B.i Sulfur Dioxide controls 

Sulfur in the fuel is the only source of SO2 emissions from these boilers. The boilers only have low 

emissions of SO2 due to the low sulfur content of the permitted fuels. 

5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies 

See Appendix F for a comprehensive list of all potential retrofit control technologies that were 

evaluated. 

5.B.i.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for SO2 emission reduction. Within 

Step 2, the technical feasibility of the control option is discussed and determined. The following 

section describes retrofit SO2 control technologies that were identified as available and applicable 

and discusses aspects of those technologies that determine whether or not the technology is 

technically feasible for the process boilers. 

Wet Walled Electrostatic Precipitator (WWESP) 

An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the 

flue gas stream. The suspended particles are given an electrical charge by passing through a high 

voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and 

collected on oppositely charged collector plates. Particles on the collector plates are released by 

rapping and fall into hoppers for collection and removal. 

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry 

ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal, 

caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2

absorber. 

The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such 

as SO2 flue gas concentration and fuel used. Based on the definitions contained within this report, a 

WWESP is considered an available technology for SO2 reduction for this BART analysis. 
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Wet Scrubbing (High and Low Efficiency) 

Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD). 

FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting 

liquid, to remove SO2 in the waste gas. Crushed limestone, lime or Caustic is used as scrubbing 

agents. 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The 

overall reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2

CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a 

more reactive reagent than limestone. The reactions for lime scrubbing are as follows: 

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

When that caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are 

as follows: 

Na+ + OH- + SO2 + → Na2SO3

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or 

limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional 

equipment will be needed for preparing the lime/limestone slurry and collecting and concentrating 

the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land 

filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air 

injection blower is needed to supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers on coal fired utility boilers is 80% to 90% 

for low efficiency scrubbers and 90% and more for high efficiency scrubbers. The highest control 

efficiencies can be achieved when SO2 concentrations are the highest. The process boiler exhaust 

would not have a high SO2 concentration, so the low end of the efficiency range would be expected. 
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Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

Dry sorbent injection involves the injection of a lime or limestone powder into the exhaust gas 

stream. The stream is then passed through a baghouse or ESP to remove the sorbent and entrained 

SO2. The process was developed as a lower cost FGD option because the mixing occurs directly in 

the exhaust gas stream instead of in a separate tower. Depending on the residence time and gas 

stream temperature, sorbent injection control efficiency is approximately 55%. Therefore DSI is 

technically feasible. 

Spray Dryer Absorption (SDA) 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the 

gas and collected with a fabric filter. The normal SO2 control efficiency range for SDA is up to 90%. 

Based on the information contained with this report, SDA is considered an available technology for 

SO2 reduction for this BART analysis. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption, 

which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution 

emissions. Due to the increased price of fuel, the facilities have already implemented energy 

efficiency projects. Each project carries its own fuel usage reductions and potentially emission 

reductions. It would be impossible to assign a general potential emission reduction for the energy 

efficient category. Due to the uncertainty and generalization of this category, this will not be further 

evaluated in this report. However, it should be noted that facilities will continue to evaluate and 

implement energy efficiency projects as they arise. 
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Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has pushed companies 

to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To 

achieve reduction of SO2 emissions through alternative fuel usage, the source must use fuels with 

lower sulfur content. NMC has the capability to only burn low sulfur fuels, natural gas and distillate 

oil, in these process boilers. Therefore this option is not applicable to the process boilers. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.33

 

Therefore, due to the limited fuel burning capabilities of the boilers and the fact that BART is not 

intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be 

further evaluated in this report. 

However, similar to energy efficiency, facilities will continue to evaluate and implement alternate 

fuel usage as the feasibility arises. 

Coal Processing 

Since NMC process boilers are not capable of burning solid fuel, this option is not applicable for SO2

reductions at NMC. 

STEP 2 Conclusion 

Based upon the determination within Step 2, the remaining SO2 control technologies that are 

available and applicable to the process boilers are identified in Table 5-7. The technical feasibility as 

determined in Step 2 is also included in Table 5-7. 

 

33 Federal Register 70, no. 128 (July 6, 2005): 39164
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Table 5-7 Backup Process Boiler SO2 Control Technology – Availability, Applicability, and 

Technical Feasibility 

SO2 Pollution Control 

Technology Available? Applicable? Technically Feasible? 

WWESP Yes Yes Yes 

Wet Scrubber Yes Yes Yes 

Spray Dry Absorption (SDA) Yes Yes Yes 

Dry Sorbent Injection (DSI) Yes Yes Yes 

Energy Efficiency Projects Yes Yes No 

Alternative Fuels Yes Yes No 

5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-8 describes the expected control efficiency from each of the remaining feasible control 

options when burning liquid fuels. 

Table 5-8 Backup Process Boiler SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80% 

Wet Scrubbing (High Efficiency) 80% 

Dry Sorbent Injection 55% 

Spray Dryer Absorption 90% 

5.B.i.d STEP 4 – Evaluate Impacts and Document the Results 

As illustrated in Table 5-8 above, the technically feasible control remaining provide varying levels of 

emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental 

impacts to better differentiate as presented below. 

Economic Impacts 

Table 5-9 details the expected costs associated with installation of a WWESP, wet scrubber, DSI and 

SDA on each stack. Equipment design was based on the maximum 24-hour emissions, vendor 

estimates, and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The 
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cost for that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the 

following equation: 

 Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6

Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. 

EPA models and factors. Operating costs were based on 93% utilization and 7650 operating hours 

per year, which is very conservative, considering these are backup boilers. Operating costs of 

consumable materials, such as electricity, water, and chemicals were established based on the U.S. 

EPA control cost manual34 and engineering experience, and were adjusted for the specific flow rates 

and pollutant concentrations. 

See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix 

A. 

Table 5-9 Backup Process Boiler SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

($) 

Total 

Annual Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental 

Control Cost 

($/ton) 

Wet ESP $11,808,857 $2,247,725 $36,558 NA 

Wet Scrubber $13,618,522 $1,869,933 $31,845 NA 

Dry Sorbent Injection and 

Baghouse $4,890,063 $1,409,010 $22,917 NA 

Spray Dryer and Baghouse $16,134,577 $2,751,525 $44,752 NA 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 

effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

 

34 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 
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business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are 

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant35

. 

Therefore, all air pollution controls with annualized costs less than this screening threshold will be 

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost column in Table 5-9 is intended to present the incremental value of each 

technology as compared to the next most effective alternative. Since none of the technologies are 

cost effective, the incremental control cost is not applicable. 

Energy and Environmental Impacts 

Because the cost of SO2 controls for the NMC process boilers is so high and does not meet a 

reasonable definition of cost effective technology, these technologies are removed from further 

consideration in this analysis. 

5.B.i.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. The economic impacts of controls for SO2 are not reasonably cost effective, so visibility 

impacts were not modeled for SO2 controls. Refer to Table 4-2 for a summary of the modeled 24-

hour maximum emission rates and their computational basis for the existing controls for SO2. 

Visibility impacts with NOx controls are presented in Section 6. Table 6-1 provides a summary of 

the SO2, NOx, and PM10 emissions for each modeling scenario.

 

35 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 
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5.B.ii Nitrogen Oxide Controls 

To be able to control NOx it is important to understand how NOx is formed. There are three 

mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. 

• Fuel bound NOx is formed as nitrogen compounds in the fuel is oxidized in the combustion 

process. 

• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen 

molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen. 

Thermal NOx production is a function of the residence time, free oxygen, and temperature. 

• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the 

result of reactions between nitrogen and carbon radicals generated during combustion. Only 

minor amounts of NOx are emitted as prompt NOx. 

The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the heater. 

5.B.ii.a STEP 1 – Identify All Available Retrofit Control Technologies 

With the understanding of how NOx is formed, available and applicable control technologies were 

evaluated. See Appendix F for the current status of the availability and applicability of retrofit 

control technologies. 

5.B.ii.b STEP 2 – Eliminate Technically Infeasible Options 

Step 1 identified the available and applicable technologies for NOx emission reduction. Within 

Step 2, the technical feasibility of the control option was discussed and determined. The following 

describes retrofit NOx control technologies that were identified as available and applicable and 

discusses aspects of those technologies that determine whether or not the technology is technically 

feasible for the process boilers. 

External Flue Gas Recirculation (EFGR) 

External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures 

thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is 

collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is 

mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas 

reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen 

level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 
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this technology to be effective, the combustion conditions must have the ability to be controlled at 

the burner tip. Process boilers 1 and 2 do not have the capability of control at the burner tip. 

Therefore, this option is not technically feasible and will not be further evaluated in this report. 

Low NOx Burners (LNB) 

Low- NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation 

through the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged 

combustion process that is designed to split fuel combustion into two zones. In the primary zone, 

NOx formation is limited by either one of two methods. Under staged air rich (high fuel) condition, 

low oxygen levels limit flame temperatures resulting in less NOx formation. The primary zone is 

then followed by a secondary zone in which the incomplete combustion products formed in the 

primary zone act as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, 

excess air will reduce flame temperature to reduce NOx formation. In the secondary zone, 

combustion products formed in the primary zone act to lower the local oxygen concentration, 

resulting in a decrease in NOx formation. Low NOx burners typically achieve NOx emission 

reductions of 25% - 50% for process boilers. 

Overfire Air (OFA) 

Overfire air diverts a portion of the total combustion air from the burners and injects it through 

separate air ports above the top level of burners. OFA is a NOx control technology typically used in 

boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates an initial 

fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of 

thermal NOx by lowering combustion temperature and limiting the availability of oxygen in the 

combustion zone where NOx is most likely to be formed. OFA is considered compatible with the 

LNB and is a technically feasible option for further NOx reduction. However, due to the small size 

and number of burners, OFA is not desirable alternative for NMC process boilers and will not be 

considered for further BART analysis. 

Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low- NOx burners, combine the benefits of 

flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue 

gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel 

combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR 

burners in high temperature applications is 50-75%. 
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Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a company to reduce their fuel consumption. 

Typically reduced fuel usage translates into reduced pollution emissions. An energy efficiency 

project could be preheat incoming make-up air or pellet feed. Each project is very dependent upon 

the fuel usage, process equipment, type of product and so many other variables. 

Due to the increased price of fuel, the facilities have already implemented energy efficiency projects. 

Each project carries its own fuel usage reductions and potentially emission reductions. It would be 

impossible to assign a general potential emission reduction for the energy efficient category. Due to 

the uncertainty and generalization of this category, this will not be further evaluated in this report. 

However, it should be noted that facilities will continue to evaluate and implement energy efficiency 

projects as they arise. 

Alternate Fuels 

As described within the energy efficiency description, increased price of fuel has pushed companies 

to evaluate alternate fuel sources. These fuel sources come in all forms – solid, liquid and gas. To 

achieve reduction of NOx emissions through alternative fuel usage, the source must be currently 

burning a high NOx emitting fuel relative to other fuels. The boilers are only capable of burning 

natural gas and distillate oil. Therefore the use of alternate fuels is not a viable option for the process 

boilers and will not be considered further in this analysis. 

It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their 

option, not to direct the fuel choice.36

 

Therefore, due to the limited boiler fuel capabilities and the fact that BART is not intended to 

mandate a fuel switch, alternative fuels as an air pollution control technology will not be further 

evaluated in this report 

However, similar to energy efficiency, facilities will continue to evaluate and implement alternate 

fuel usage as the feasibility arises. 

 

36 Federal Register 70, no. 128 (July 6, 2005): 39164
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Post Combustion Controls 

NOx can be controlled using add-on systems located downstream of the combustion process. The 

two main techniques in commercial service include the selective non catalytic reduction (SNCR) 

process and the selective catalytic reduction (SCR) process. There are a number of different process 

systems in each of these categories of control techniques. 

In addition to these treatment systems, there are a large number of other processes being developed 

and tested on the market. These approaches involve innovative techniques of chemically reducing, 

absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives 

are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these 

alternatives is described below. 

Non-Selective Catalytic Reduction (NSCR) 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied 

primarily in natural gas combustion applications. 

NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx, 

unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx

emission reductions of 90 percent. In order to operate properly, the combustion process must be near 

stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO, 

resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal 

are: 

2CO + 2NO → 2CO2 + N2 (1) 

[UBH] + NO → N2 + CO2 + H2O (2) 

NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part 

to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to 

liquid fuels. Therefore, this technology will not be further evaluated in this report. 

Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction 

SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction: 
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4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1) 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2) 

A catalyst bed containing metals in the platinum family is used to lower the activation energy 

required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a 

normal catalyst. At temperature exceeding approximately 670oF, the oxidation of ammonia begins to 

become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and 

corrosion problems. 

A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F 

temperature range. However, these catalysts are very expensive. 

Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia 

increases during load changes due to the instability of the temperature in the catalyst bed as well as at 

low loads because of the low gas temperature. 

Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) 

control process as described below with a preheat process step to reheat the flue gas stream up to 

SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink 

(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR 

and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the 

preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow 

alternates between vessels. Each of the vessels alternates between preheating/treating and heat 

recovery. 

The benefits of RSCR are: 

• Its high energy efficiency allows it to be used after SO2 and particulate controls. 

• RSCR has a thermal efficiency of 90% - 95% vs. standard heat exchangers which have a 

thermal efficiency of 60% to 70%. 

• Application of RSCR after SO2 and PM controls significantly reduces the potential for 

problems associated with plugging and catalyst poisoning and deactivation. 

To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not 

been applied to liquid and natural gas fired boilers. Using RSCR would require research, test runs, 
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and extended trials to identify potential issues related to catalyst selection, and impacts on plant 

systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming 

in advance of a demonstration project. The timeline required to perform such a demonstration project 

would likely be two years to develop and agree on the test plan, obtain permits for the trial, 

commission the equipment for the test runs, perform the test runs for a reasonable study period, and 

evaluate and report on the results. The results would not be available within the time window for 

establishing emission limits to be incorporated in the state implementation plan (SIP) by December 

2007. 

Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as 

mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to 

learn how to apply a control technology to a completely new and significantly different source type. 

Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this 

BART analysis. 

Selective Non-Catalytic Reduction (SNCR) 

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F, 

reaction (2) will dominate. This control option is considered feasible. 

Low Temperature Oxidation (LTO) 

The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 

NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2, 

and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas 

(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The 

nitrates are removed from the scrubbing system and discharged to an appropriate water treatment 

system. Commercially available LTO systems include Tri-NOx® and LoTOx®. 
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NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®

) 

This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a 

primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The 

reactions are as follows: 

O3 + NO → O2 + NO2

(1)

2NaOH + 2NO2 + 1⁄2 O2 → 2NaNO3 + H2O (2)

Tri-NOx

®

 is a multi-staged wet scrubbing process in industrial use. Several process columns, each 

assigned a separate processing stage, are involved. In the first stage, the incoming material is 

quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent 

stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx

®

 is 

typically applied at small to medium sized sources with high NOx concentration in the exhaust gas 

(1,000 ppm NOx). 

Low Temperature Oxidation (LoTOx®) 

BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same 

scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a 

scrubber, and is removed with lime or caustic. Ozone for LoTOx®

 is generated on site with an 

electrically powered ozone generator. The ozone generation rate is controlled to match the amount 

needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx®

 to be 

economically feasible, a source of low cost oxygen must be available from a pipeline or on site 

generation. 
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In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications. 

Therefore, although this is an emerging technology, the limited application means that it has not been 

demonstrated to be an effective technology in widespread application. Consequently, the technical 

feasibility of LTO as technically infeasible for this application and will not be evaluated further. 

Step 2 Conclusion 

Based upon the determination within Step 2, the remaining NOx control technologies that are 

available and applicable to the process boilers are identified in Table 5-10. The technical feasibility 

as determined in Step 2 is also included in Table 5-10.

Table 5-10 Backup Process Boiler NOx Control Technology – Availability, Applicability and 

Technical Feasibility 

NOx Pollution Control Technology Available? Applicable?

Technically 

Feasible? 

External Flue Gas Recirculation (EFGR) Yes Yes No 

Low-NOx Burners Yes Yes Yes 

Overfired Air Yes Yes No 

Induced Flue Gas Recirculation (IFGR) Yes Yes Yes 

Energy Efficiency Projects Yes Yes No 

Alternative Fuels Yes Yes Not required 

Non-Selective Catalytic Reduction (NSCR) Yes Yes No 

Selective Catalytic Reduction (SCR) Yes Yes Yes 

Regenerative SCR Yes Yes No 

Selective Non-Catalytic Reduction (SNCR) Yes Yes Yes 

Low Temperature Oxidation (LTO) Yes No No 

5.B.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

Table 5-11 describes the expected control efficiency from each of the remaining technically feasible 

control options as identified in Step 2. 

Table 5-11 Backup Process Boiler NOx Control Technology Effectiveness 

NOx Pollution Control Technology 

Approximate Control 

Efficiency 

Low-NOx Burners 50% 

Low-NOx Burners with IFGR 75% 

SCR 90% 

Selective Non-Catalytic Reduction (SNCR) 50% 
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5.B.ii.d STEP 4 – Evaluate Impacts and Document the Results 

Table 5-12 details the expected costs associated with installation of NOx controls. Capital costs were 

calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. 

Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate 

using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% 

utilization and 7650 operating hours per year, which is extremely conservative, since they are backup 

boilers. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant 

concentrations. 

After a tour of the facility and discussions with facility management, it was determined the space 

surrounding the boilers is congested and the area surrounding the building supports vehicle and rail 

traffic to transport materials to and from the building. A site-specific estimate for site-work, 

foundations, and structural steel was added based upon the facility site to arrive at the total retrofit 

installed cost of the control technology. See Appendix C for a site plan of the facility. Additionally, 

the structural design of the existing building would not support additional equipment on the roof. The 

detailed cost analysis is provided in Appendix A. 

Table 5-12 Backup Process Boiler NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Operating Cost

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental

Control 

Cost 

($/ton) 

Low NOx Burner $90,775 $14,915 $723 NA 

Low NOx Burner / 

IFGR $518,713 $330,367 $10,675 $30,626 

Selective Catalytic 

Reduction (SCR) $5,563,529 $1,120,061 $30,160 NA 

Selective NonCatalytic Reduction 

(SNCR) 

$925,876 $250,181 $12,126 NA 

Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory 

bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective 

air pollution controls in the electric utility industry for large power plants are in the range $1,000 to 

$1,300 per ton removed as illustrated in Appendix E. This cost-effective threshold is also an indirect 

measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost 
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effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not 

afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the 

electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater 

business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for 

proposing BART in lieu of developing industry and site specific data. 

The annualized pollution control cost value was used to determine whether or not additional impacts 

analyses would be conducted for the technology. If the control cost was less than a screening 

threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are 

evaluated. MPCA set the screening level to eliminate technologies from requiring the additional 

impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant37

. 

Therefore, all air pollution controls with annualized costs less than this screening threshold will be 

evaluated for visibility improvement, energy and other impacts. 

The incremental control cost listed in Table 5-12 represents the incremental value of each technology 

as compared to the technology with the next highest level of control. 

Energy and Environmental Impacts 

The energy and non-air quality impacts for LNB and LNB with IFGR are presented in Table 5-13. 

Because the cost of the remaining NOx control technologies for the NMC process boilers is so high 

and does not meet a reasonable definition of cost effective technology, these technologies are 

removed from further consideration in this analysis. 

Table 5-13 Backup Process Boiler NOx Control Technology – Other Impacts Assessment 

Control 

Option Energy Impacts Other Impacts 

LNB - Minimal energy impacts - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame 

IFGR/LNB - Minimal energy impacts. - Increase in CO emissions 

- Potential for steam tube wastage due to 

longer combustion flame. 

 

37 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean 

Processing Plant, Fairmont, MN Permit 09100059-002. 
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5.B.ii.e STEP 5 – Evaluate Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality impacts, when determining BART for an individual 

source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this 

document. This section of the report evaluates the visibility impacts of BART NOX control and the 

resulting degree of visibility improvement. 

Predicted 24-Hour Maximum Emission Rates 

Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts, 

the post-BART emissions to be used for the visibility impacts analysis should also reflect a 

maximum 24-hour average project emission rate. In the visibility impacts NOX modeling analysis, 

the emissions from the sources undergoing a full BART NOX analysis were adjusted to reflect the 

projected 24-hour maximum NOX emission rate when applying the control technologies that met the 

threshold requirements of steps 1 – 4. The emissions from all other Subject-to-BART sources were 

not changed. Table 5-14 provides a summary of the modeled 24-hour maximum emission rates and 

their computational basis for the evaluated NOX control technologies. Table 5-15 provides a 

summary of the SO2, NOX, and PM10 emissions for each modeling scenario, and Table 5-16 provides 

a summary of the modeling input data. 

Table 5-14 Backup Process Boiler NOx Post- BART Emission Rates for Emission Unit EU003 

and EU004 

Control 

Scenario SV # 

Emission Unit 

Description 

NOx

Control 

Technology 

% NOx

Reduction 

NOx

Annual 

Emission 

Rate 

(tons/year) 

NOx

24-hour 

Maximum 

Emission 

Rate (lb/day) 

 1 SV003 Process Boiler 1 Low Nox 

Burners 50% 25.5 279 

 1 SV003 Process Boiler 2 Low Nox 

Burners 50% 25.5 279 
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Table 5-15 Backup Process Boiler Post-BART Modeling Scenarios 

Scenario Control Scenario Technology Modeling Emission Rate Input 

SO2 NOx PM2.5/PM10 

SO2 NOx PM 

% 

Reduced 

24-hr Max 

lb/hr 

% 

Reduced 

24-hr Max 

lb/hr 

% 

Reduced 

PM2.5 24-

hr Max. 

lb/hr 

% 

Reduc

0 Base Base Base 

 SV003 

Process 

Boilers 

1 & 2 

 0 33.5 0 23.3 0 0 

1 Base

LNB 

with 

IFGR

Base 

 SV003 

Process 

Boilers 

1 & 2 

 0.0% 33.5 50.0% 11.6 0 0 
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Table 5-16 Backup process Boiler Post-BART NOx Modeling Scenarios - Modeling Input Data 

Control 

Scenario SV # Emission Unit

Stack Easting 

LCC 

(km) 

Stack Northing 

LCC 

(km) 

Height of 

Opening 

from Ground 

(m) 

Base 

Elevation 

of Ground 

(m) 

Stack 

Diameter 

(m) 

Flow Rate 

at exit 

(acfm) 

Exit 

Temp 

(

oF) 

 1 SV003 Process 

Boilers 1 & 2 631471.5 5238482.8 131 611 6.5 59900 450 

Post-BART Visibility Impacts Modeling Results 

Results of the post-BART visibility impacts modeling for NOX for the process boilers are presented 

in Table 5-17. The results summarize 98th percentile dV value and the number of days the facility 

contributes more than a 0.5 dV of visibility impairment at each of the Class I areas. The comparison 

of the post-BART modeling scenarios to the baseline conditions is presented in Table 5-18. 

Visibility impacts with SO2 controls are presented in section 6. 

Table 5-17 Backup Process Boiler Post-BART NOx Modeling Scenarios - Visibility Modeling 

Results 

2002 2003 2004 

2002 – 2004 

Combined 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 deciview 

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 

1 BWCA 1.1 33 1.1 34 1.3 38 1.1 105 

Table 5-18 Backup Process Boiler Post-BART NOx Modeling Scenarios – Comparison of 

Visibility Modeling Results to Baseline Modeling Results 

2002 2003 2004 

2002 – 2004 

Combined 

Scenario # 

Class I 

Area with 

Greatest 

Impact 

Improved 

Modeled 

98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of 

days 

exceeding 

0.5 

deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

Improved 

Modeled 98th

Percentile 

Value 

(∆-dV) 

Decreased 

No. of days 

exceeding 

0.5 deciview 

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 106 

1 BWCA 0.0 1 0.0 0 0.0 0 0.0 1 
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6. Visibility Impacts 

As previously stated in section 4 of this document, states are required to consider the degree of 

visibility improvement resulting from the retrofit technology, in combination with other factors such 

as economic, energy and other non-air quality, when determining BART for an individual source. 

The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. 

The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this 

document. This section of the report evaluates the various BART control scenarios utilizing both 

SO2 and NOx controls, and estimates the resulting degree of visibility improvement. 

6.A Post-BART Modeling Scenarios 

Steps 1-4 of the BART analysis identified the control technologies that were: 

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that 

met the requirements of the screening analysis of steps 1-4. 

However, because there are limited control options available that meet the above criteria, there are 

limited available control combinations, or control scenarios, that must be considered. Additionally, 

the interactions between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part 

in predicting impairment. It is therefore important to take a multi-pollutant approach when assessing 

visibility impacts. Accordingly, this visibility improvement analysis evaluates several operating 

control scenarios that account for the various combinations of available SO2 and NOx controls. In 

addition, two site-specific scenarios were developed so that the evaluation includes other operating 

scenarios and conditions that would improve visibility impairment. The post-BART modeling 

scenarios, including those presented in Step 5 of section 5, are presented in Table 6-1. 

6.B Post-BART Modeling Results 

Results of the post-BART modeling scenarios are presented in Table 6-2. The results summarize 

98th percentile dV value and the number of days the facility contributes more than a 0.5 dV of 
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68

visibility impairment at each of the Class I areas. The comparison of the post-BART modeling 

scenarios to the baseline conditions is presented in Table 6-3. 

While the cost per ton of low NOx burners is $723, and is below the threshold of $1,000 to $1,300 per 

ton, they result in essentially no visibility improvement to the Class I areas. In the three years, 

additional controls would result in only one fewer day with a visibility impact of greater than 0.5 dV 

and the change in the modeled worst day (98th percentile) is 0.007 deciviews, which is less than 1% 

of the total modeled BART impact. The cost of this marginal improvement is $4.3 million per 

deciview, considering the capital cost of $91,000 and the total annual cost of $15,000. 
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69

Table 6-1 Post-BART Modeling Scenarios 

Scenario Control Technology SO2 NOx 

Control 

Scenario SV # Emission Unit SO2 NOx

% 

Reduction 

Max 

24-hour lbs/hr % Reduction 

Max 

24-hour 

lbs/hr 

M

0 

Base 

(existing 

design) 

Base 

(existing 

design) 

 SV101 Furnace 11 Hood Exh --- 11.8 --- 17.1  SV102 Furnace 11 Hood Exh 11.8 17.1  SV103 Furnace 11 Hood Exh 11.8 17.1  SV104 Furnace 11 Waste Gas --- 5.9 --- 62.4  SV105 Furnace 11 Waste Gas 5.9 62.4  SV111 Furnace 12 Hood Exh --- 11.8 --- 17.1  SV112 Furnace 12 Hood Exh 11.8 17.1  SV113 Furnace 12 Hood Exh 11.8 17.1  SV114 Furnace 12 Waste Gas --- 5.9 --- 62.4  SV115 Furnace 12 Waste Gas 5.9 62.4  SV003 Process Boilers 1 & 2 33.5 23.3 

1 Base 

Base on 

indurating 

furnace and 

Low NOx

Burners on the backup 

process 

boilers 

 SV101 Furnace 11 Hood Exh 11.8 --- 17.1  SV102 Furnace 11 Hood Exh 11.8 17.1  SV103 Furnace 11 Hood Exh 11.8 17.1  SV104 Furnace 11 Waste Gas 5.9 --- 62.4  SV105 Furnace 11 Waste Gas 5.9 62.4  SV111 Furnace 12 Hood Exh 11.8 --- 17.1  SV112 Furnace 12 Hood Exh 11.8 17.1  SV113 Furnace 12 Hood Exh 11.8 17.1  SV114 Furnace 12 Waste Gas 5.9 --- 62.4  SV115 Furnace 12 Waste Gas 5.9 62.4  SV003 Process Boilers 1 & 2 33.5 50.0% 11.6 
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70

Table 6-2 Post-BART Modeling Scenarios - Visibility Modeling Results 

2002 2003 2004 

2

Scenario # 

Class I Area 

with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 

0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 98th

Percentile 

Value 

(deciview) 

No. of days 

exceeding 0.5 

deciview 

Modeled 9

Percentil

Value 

(deciview

0 BWCA 1.1 34 1.1 34 1.3 38 1.1 1 BWCA 1.1 33 1.1 34 1.3 38 1.1 

Table 6-3 Post-BART Modeling Scenarios – Comparison of Visibility Modeling Results to Baseline Mo

Modeling Results 

0 2002 2003 2004 

Scenario Limiting Class I Area 

Improved 

Modeled 

98th 

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 0.5 

dV 

Improved 

Modeled 98th 

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Improved 

Modeled 98th 

Percentile 

Value 

(∆-dV) 

Decreased 

No. of Days 

exceeding 

0.5 dV 

Imp

Mod

98

Perc

Va

(∆-

0 BWCA 1.1 34 1.1 34 1.3 38 11 BWCA 0.0 1 0.0 0 0.0 0 0
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71

7. Select BART 

BART for NMC is proposed to be as follows: 

Indurating Furnaces

For SO2, polishing add-on controls are not cost effective. Therefore, BART is proposed to be 

existing controls. The corresponding SO2 emissions limit would be 2.0 lbs/mmBtu, which equates to 

300 lb/hr per furnace based upon each furnace heat input rating of 150 mmBtu. 

For NOx, add on control are not cost effective. Therefore, BART is proposed to be the existing 

furnace design and permitted fuels. The corresponding NOx limit would be 176 lb/hr for each 

furnace. 

For PM, requirements compelled by the upcoming MACT standard constitute BART. The 

corresponding emissions limit would be 0.01 grains per dscf for the furnaces. 

Process Boilers

The process boilers are backup boilers for steam production normally supplied to the taconite plant 

from the power boilers. For SO2, add-on controls are not cost effective. Therefore, BART is 

proposed to be existing design and permitted fuels. The corresponding SO2 emissions limit would be 

0.6 lb/mmBtu for each boiler. 

For NOx, add-on controls would not accomplish a meaningful improvement in visibility. Therefore, 

BART is proposed to be existing design and permitted fuels. The corresponding NOx limit would be 

0.17 lb/mmBtu for each boiler. 

Other Taconite Sources 

For PM, requirements compelled by the upcoming MACT standard constitute BART. The 

corresponding emissions limit would be equivalent to the MACT limit. 

The schedule for implementation of these limits is within the 5-year time-frame required for BART 

implementation. 
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost AnalysisTable 1: Cost Summary

NOx Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton

Furnace 11 Hood Exhaust 80% 5.7 106.7 $46,019,283 $11,628,024 $108,969 

Furnace 11 Waste Gas 80% 17.8 255.9 $43,197,692 $8,239,261 $32,199 Furnace 12 Hood Exhaust 80% 5.6 104.4 $46,284,809 $11,688,411 $112,008 Furnace 12 Waste Gas 80% 17.4 250.3 $43,455,895 $10,383,373 $41,488 

SO2 Control Cost Summary 

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton

Wet Walled Electrostatic Precipitator (WWESP)Furnace 11 Hood Exhaust 80% 5.7 22.9 $23,617,556 $4,188,875 $182,993Furnace 11 Waste Gas 80% 1.9 7.6 $21,846,389 $3,799,211 $496,949Furnace 12 Hood Exhaust 80% 5.3 21.0 $23,617,556 $4,294,171 $204,058Furnace 12 Waste Gas 80% 1.8 7.0 $21,846,389 $3,764,113 $535,575Wet ScrubberFurnace 11 Hood Exhaust 60% 11.4 17.2 $16,952,864 $2,401,349 $139,872Furnace 11 Waste Gas 60% 3.8 5.7 $15,859,420 $2,201,975 $384,034Furnace 12 Hood Exhaust 60% 10.5 15.8 $16,952,864 $2,401,349 $152,149Furnace 12 Waste Gas 60% 3.5 5.3 $15,859,420 $2,201,975 $417,742Selective Catalytic Reduction with Reheat

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsCost Summary 
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost AnalysisTable 2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Furnace 11 Hood Exhaust Study Year 2006

Emission Unit Number EU 100Stack/Vent Number SV 101, 102, & 103

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104Stack/Vent Number SV 104 & 105

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110Stack/Vent Number SV 111, 112, & 113

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114Stack/Vent Number SV 114 & 115

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 50 $/hr 2006 Site Specific - Northshore Mining .

Maintenance Labor 60 $/hr 2006 Site Specific - Northshore Mining . Construction Labor Rate.

Electricity 0.060 $/kwh 2006 Site Specific - Northshore Mining. Purchased.Natural Gas 10.0204 $/mscf 2006 Site Specific - Northshore Mining . $9.40/MMBtu @ 1066 Btu/scf.

Water 0.28 $/mgal 0.20 1995

EPA Air Pollution Control Cost Manual, 6th Ed 2002, Section 5 Ch 1, page 1-40.

Annual Costs for Packed Tower Absorber Exampadjusted for 3% inflation.

Cooling Water 0.28 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1.

Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg 3% inflation.

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 coinflation.

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 lists $1.30 - $2.15/1,000 gal.

Chemicals & SuppliesLime 88.98 $/ton 88.98 2006 Estimate from Cutler-Magney Company.Oxygen 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 5 Chapter 2, page 2-50.

Annual costs for a retrofit SCR system example padjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 c

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 8339.1 Hours 2006 Site Specific - Northshore Mining . Maximum hours of operation 2004-2005 with a 10

Utilization Rate 93%Equipment Life 20 yrs Engineering Estimate.Standardized Flow RateSV 101, 102, & 103 181,762 scfm @ 32o F Calculated.SV 104 & 105 152,520 scfm @ 32o F Calculated.SV 111, 112, & 113 181,762 scfm @ 32o F Calculated.SV 114 & 115 152,520 scfm @ 32o F Calculated.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsUtility Chem$ Data 
Reference

Item Unit Cost Units Cost Year Data Source Notes

TemperatureSV 101, 102, & 103 142 Deg F BART spreadsheet.

SV 104 & 105 140 Deg F BART spreadsheet.SV 111, 112, & 113 142 Deg F BART spreadsheet.SV 114 & 115 140 Deg F BART spreadsheet.Moisture ContentSV 101, 102, & 103 11.3% 2006

Y:\23\38\126 NSM 2006 Stack Testing\WK4 Fce 11+\Data. Average from test results in:Test 1-3 Fce 11 HE 

SV 104 & 105 18.3% 2006

Y:\23\38\126 NSM 2006 Stack Testing\WK4 Fce 11+\Data. Average from test results in: Test 4-5 Fce 11 WG 

SV 111, 112, & 113 9.5% 2006

Y:\23\38\126 NSM 2006 Stack Testing\WK2 Fce 12\Data. Average from test results in: Fce 12 HE 1201-120

SV 114 & 115 16.4% 2006

Y:\23\38\126 NSM 2006 Stack Testing\WK2 Fce 12\Data. Average from test results in: Fce 12 WG 1204-12

Actual Flow RateSV 101, 102, & 103 222,400 acfm BART spreadsheet.

SV 104 & 105 186,000 acfm BART spreadsheet.SV 111, 112, & 113 222,400 acfm BART spreadsheet.SV 114 & 115 186,000 acfm BART spreadsheet.Standardized Flow RateSV 101, 102, & 103 195,062 scfm @ 68o F Calculated.SV 104 & 105 163,680 scfm @ 68o F Calculated.SV 111, 112, & 113 195,062 scfm @ 68o F Calculated.SV 114 & 115 163,680 scfm @ 68o F Calculated.Dry Std Flow RateSV 101, 102, & 103 172,951 dscfm @ 68o F Calculated.SV 104 & 105 133,792 dscfm @ 68o F Calculated.SV 111, 112, & 113 176,529 dscfm @ 68o F Calculated.SV 114 & 115 136,902 dscfm @ 68o F Calculated.

Max Emis Actual Emissions lb/hr ton/year

Pollutant Lb/Hr Ton/year ('04&'05 Max) ppmv ppmvNitrous Oxides (NOx)SV 101, 102, & 103 51.3 112.4 41 20.7 2005 plus 10%SV 104 & 105 124.8 273.7 130 65.1 2004 plus 10%SV 111, 112, & 113 51.3 109.9 40 19.8 2004 plus 10%SV 114 & 115 124.8 267.7 127 62.3 2004 plus 10%Sulfur Dioxides (SO2)SV 101, 102, & 103 35.5 28.6 21 3.8 2004 plus 10%

SV 104 & 105 11.8 9.6 9 1.6 2004 plus 10%SV 111, 112, & 113 35.5 26.3 20 3.4 2004 plus 10%

SV 114 & 115 11.8 8.8 9 1.5 2004 plus 10%guesscalculated valueknown or assumed datarequired data

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsUtility Chem$ Data 
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 3: SOx

 Control - Wet Scrubber

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103

Standardized Flow Rate 181,762 scfm @ 32o F

Expected Utilization Rate 93% Temperature 142 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3%

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,765,654

 Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270

 Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,856,229

 Total Direct Capital Cost, DC 6,216,499

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040

Total Capital Investment (TCI) = DC + IC 16,952,864

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

Actual

Emission Control Cost Calculation Emis Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA

Sulfur Dioxide (SO2

) 28.6 35.5 60% 11.4 17.2 139,872 

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.

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EU100 Wet Scrubber 9/6/2006 Page 4 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 3: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654

Instrumentation 10% of control device cost (A) 276,565

MN Sales Taxes 7% of control device cost (A) 179,768

Freight 5% of control device cost (A) 138,283

Purchased Equipment Total (B) 22% 3,360,270

Installation

Foundations & supports 12% of purchased equip cost (B) 403,232

Handling & erection 40% of purchased equip cost (B) 1,344,108

Electrical 1% of purchased equip cost (B) 33,603

Piping 30% of purchased equip cost (B) 1,008,081

Insulation 1% of purchased equip cost (B) 33,603

Painting 1% of purchased equip cost (B) 33,603

Installation Subtotal Standard Expenses 85% 2,856,229

Total Direct Capital Cost, DC 6,216,499

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 168,013

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 168,013

Start-up 1% of purchased equip cost (B) 33,603

Performance test 1% of purchased equip cost (B) 33,603

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 100,808

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040

Total Capital Investment (TCI) = DC + IC 6,720,540

Retrofit multiplier560% of TCI 4,032,324

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 16,952,864

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823

Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883

WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783

Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789

Total Annual Direct Operating Costs 476,790

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411

Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205

Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

See Summary page for notes and assumptions

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EU100 Wet Scrubber 9/6/2006 Page 5 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 3: SOx 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 222,400 8.55 0.7 - 317.8 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 8,451 gpm 1 60 0.7 - 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 209 gpm 1 60 0.7 - 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 457.4

Reagent Use & Other Operating Costs

Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic

Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 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

8,451 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 209 gpm

Evaporation Loss4 = 39.66 gpm

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Supervisor 15% of Op. NA 15% of Operator Costs 3,909

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization

Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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EU100 Wet Scrubber 9/6/2006 Page 6 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 4: SOx

 Control - Wet Scrubber

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105

Standardized Flow Rate 152,520 scfm @ 32o F

Expected Utilization Rate 93% Temperature 140 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3%

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,484,419

 Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569

 Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,565,783

 Total Direct Capital Cost, DC 5,584,352

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785

Total Capital Investment (TCI) = DC + IC 15,859,420

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

Actual

Emission Control Cost Calculation Emis Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA

Sulfur Dioxide (SO2

) 9.6 11.8 60% 3.8 5.7 384,034

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.

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EU104 Wet Scrubber 9/6/2006 Page 7 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 4: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419

Instrumentation 10% of control device cost (A) 248,442

MN Sales Taxes 7% of control device cost (A) 161,487

Freight 5% of control device cost (A) 124,221

Purchased Equipment Total (B) 22% 3,018,569

Installation

Foundations & supports 12% of purchased equip cost (B) 362,228

Handling & erection 40% of purchased equip cost (B) 1,207,427

Electrical 1% of purchased equip cost (B) 30,186

Piping 30% of purchased equip cost (B) 905,571

Insulation 1% of purchased equip cost (B) 30,186

Painting 1% of purchased equip cost (B) 30,186

Installation Subtotal Standard Expenses 85% 2,565,783

Total Direct Capital Cost, DC 5,584,352

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 150,928

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 150,928

Start-up 1% of purchased equip cost (B) 30,186

Performance test 1% of purchased equip cost (B) 30,186

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 90,557

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785

Total Capital Investment (TCI) = DC + IC 6,037,137

Retrofit multiplier560% of TCI 3,622,282

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 15,859,420

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990

Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483

WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050

Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930

Total Annual Direct Operating Costs 407,966

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU104 Wet Scrubber 9/6/2006 Page 8 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 4: SOx 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 186,000 8.55 0.7 - 265.8 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 7,068 gpm 1 60 0.7 - 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 175 gpm 1 60 0.7 - 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 382.5

Reagent Use & Other Operating Costs

Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic

Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 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

7,068 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 175 gpm

Evaporation Loss4 = 33.17 gpm

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Supervisor 15% of Op. NA 15% of Operator Costs 3,909

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization

Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU104 Wet Scrubber 9/6/2006 Page 9 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 5 SOx

 Control - Wet Scrubber

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113

Standardized Flow Rate 181,762 scfm @ 32o F

Expected Utilization Rate 93% Temperature 142 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5%

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,765,654

 Purchased Equipment Total (B) 22% of control device cost (A) 3,360,270

 Installation - Standard Costs 85% of purchased equip cost (B) 2,856,229

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,856,229

 Total Direct Capital Cost, DC 6,216,499

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040

Total Capital Investment (TCI) = DC + IC 16,952,864

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 476,790

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

Actual

Emission Control Cost Calculation Emis Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA

Sulfur Dioxide (SO2

) 26.3 35.5 60% 10.5 15.8 152,149 

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU110 Wet Scrubber 9/6/2006 Page 10 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 5 SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,765,654

Instrumentation 10% of control device cost (A) 276,565

MN Sales Taxes 7% of control device cost (A) 179,768

Freight 5% of control device cost (A) 138,283

Purchased Equipment Total (B) 22% 3,360,270

Installation

Foundations & supports 12% of purchased equip cost (B) 403,232

Handling & erection 40% of purchased equip cost (B) 1,344,108

Electrical 1% of purchased equip cost (B) 33,603

Piping 30% of purchased equip cost (B) 1,008,081

Insulation 1% of purchased equip cost (B) 33,603

Painting 1% of purchased equip cost (B) 33,603

Installation Subtotal Standard Expenses 85% 2,856,229

Total Direct Capital Cost, DC 6,216,499

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 168,013

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 168,013

Start-up 1% of purchased equip cost (B) 33,603

Performance test 1% of purchased equip cost (B) 33,603

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 100,808

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 504,040

Total Capital Investment (TCI) = DC + IC 6,720,540

Retrofit multiplier560% of TCI 4,032,324

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 16,952,864

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization 212,823

Water 0.28 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization 26,883

WW Treat Neutralization 1.69 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization 132,783

Lime 88.98 $/ton, 34 lb/hr, Annual Operating Hours, 93% utilization 11,789

Total Annual Direct Operating Costs 476,790

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 134,411

Property tax (1% total capital costs) 1% of total capital costs (TCI) 67,205

Insurance (1% total capital costs) 1% of total capital costs (TCI) 67,205

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,600,230

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,924,559

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,401,349

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU110 Wet Scrubber 9/6/2006 Page 11 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 5 SOx 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 222,400 8.55 0.7 - 317.8 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 8,451 gpm 1 60 0.7 - 136.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 209 gpm 1 60 0.7 - 3.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 457.4

Reagent Use & Other Operating Costs

Caustic Use 35.50 lb/hr SO2 2.50 lb NaOH/lb SO2 88.75 lb/hr Caustic

Lime Use 35.50 lb/hr SO2 0.96 lb Lime/lb SO2 34.17 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

8,451 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 209 gpm

Evaporation Loss4 = 39.66 gpm

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Supervisor 15% of Op. NA 15% of Operator Costs 3,909

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 457.4 kW-hr 3,547,050 212,823 $/kwh, 457 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 208.7 gpm 97,104 26,883 $/kgal, 209 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 169.0 gpm 78,651 132,783 $/kgal, 169 gpm, Annual Operating Hours, 93% utilization

Lime 89.0 $/ton 34.2 lb/hr 132 11,789 $/ton, 34 lb/hr, Annual Operating Hours, 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU110 Wet Scrubber 9/6/2006 Page 12 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 6: SOx

 Control - Wet Scrubber

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115

Standardized Flow Rate 152,520 scfm @ 32o F

Expected Utilization Rate 93% Temperature 140 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 2,484,419

 Purchased Equipment Total (B) 22% of control device cost (A) 3,018,569

 Installation - Standard Costs 85% of purchased equip cost (B) 2,565,783

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,565,783

 Total Direct Capital Cost, DC 5,584,352

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785

Total Capital Investment (TCI) = DC + IC 15,859,420

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 407,966

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

Actual

Emission Control Cost Calculation Emis Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA

Sulfur Dioxide (SO2

) 8.8 11.8 60% 3.5 5.3 417,742

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.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU114 Wet Scrubber 9/6/2006 Page 13 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 6: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 2,484,419

Instrumentation 10% of control device cost (A) 248,442

MN Sales Taxes 7% of control device cost (A) 161,487

Freight 5% of control device cost (A) 124,221

Purchased Equipment Total (B) 22% 3,018,569

Installation

Foundations & supports 12% of purchased equip cost (B) 362,228

Handling & erection 40% of purchased equip cost (B) 1,207,427

Electrical 1% of purchased equip cost (B) 30,186

Piping 30% of purchased equip cost (B) 905,571

Insulation 1% of purchased equip cost (B) 30,186

Painting 1% of purchased equip cost (B) 30,186

Installation Subtotal Standard Expenses 85% 2,565,783

Total Direct Capital Cost, DC 5,584,352

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 150,928

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 150,928

Start-up 1% of purchased equip cost (B) 30,186

Performance test 1% of purchased equip cost (B) 30,186

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 90,557

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 452,785

Total Capital Investment (TCI) = DC + IC 6,037,137

Retrofit multiplier560% of TCI 3,622,282

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 15,859,420

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization 177,990

Water 0.28 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization 22,483

WW Treat Neutralization 1.69 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization 111,050

Lime 88.98 $/ton, 11 lb/hr, Annual Operating Hours, 93% utilization 3,930

Total Annual Direct Operating Costs 407,966

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,743

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,371

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,371

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,497,017

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,794,010

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,201,975

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU114 Wet Scrubber 9/6/2006 Page 14 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 6: SOx 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 186,000 8.55 0.7 - 265.8 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 7,068 gpm 1 60 0.7 - 113.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 175 gpm 1 60 0.7 - 2.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 382.5

Reagent Use & Other Operating Costs

Caustic Use 11.83 lb/hr SO2 2.50 lb NaOH/lb SO2 29.58 lb/hr Caustic

Lime Use 11.83 lb/hr SO2 0.96 lb Lime/lb SO2 11.39 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

7,068 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 175 gpm

Evaporation Loss4 = 33.17 gpm

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Supervisor 15% of Op. NA 15% of Operator Costs 3,909

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 382.5 kW-hr 2,966,507 177,990 $/kwh, 383 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 174.5 gpm 81,211 22,483 $/kgal, 175 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 141.4 gpm 65,778 111,050 $/kgal, 141 gpm, Annual Operating Hours, 93% utilization

Lime 89.0 $/ton 11.4 lb/hr 44 3,930 $/ton, 11 lb/hr, Annual Operating Hours, 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU114 Wet Scrubber 9/6/2006 Page 15 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 7: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103

Standardized Flow Rate 181,762 scfm @ 32o F

Expected Utilization Rate 93% Temperature 142 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3%

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,999,843

 Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809

 Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,256,072

 Total Direct Capital Cost, DC 8,115,881

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091

Total Capital Investment (TCI) = DC + IC 23,617,556

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,425,578

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 51.3 112.4 0% 112.4 - NA

Sulfur Dioxide (SO2

) 28.6 35.5 80% 5.7 22.9 182,993 

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

EU100 WWESP 9/6/2006 Page 16 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 7: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,999,843

Instrumentation 10% of control device cost (A) 399,984

MN Sales Taxes 6.5% of control device cost (A) 259,990

Freight 5% of control device cost (A) 199,992

Purchased Equipment Total (B) 22% 4,859,809

Installation

Foundations & supports 4% of purchased equip cost (B) 194,392

Handling & erection 50% of purchased equip cost (B) 2,429,905

Electrical 8% of purchased equip cost (B) 388,785

Piping 1% of purchased equip cost (B) 48,598

Insulation 2% of purchased equip cost (B) 97,196

Painting 2% of purchased equip cost (B) 97,196

Installation Subtotal Standard Expenses 67% 3,256,072

Total Direct Capital Cost, DC 8,115,881

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 971,962

Construction & field expenses 20% of purchased equip cost (B) 971,962

Contractor fees 10% of purchased equip cost (B) 485,981

Start-up 1% of purchased equip cost (B) 48,598

Performance test 1% of purchased equip cost (B) 48,598

Model Studies 2% of purchased equip cost (B) 97,196

Contingencies 3% of purchased equip cost (B) 145,794

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091

Total Capital Investment (TCI) = DC + IC 10,885,972

Retrofit multiplier3

60% of TCI 6,531,583

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 23,617,556

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization 104,239

Supervisor 15% of Op., 0 , Annual Operating Hours, 0% utilization 15,636

Maintenance

Maintenance Labor 60.00 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization 4,340

Maintenance Materials 1.00 % of Maintenance Labor 39,998

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544

Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251

WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571

Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296

Total Annual Direct Operating Costs 1,425,578

Indirect Operating Costs

Overhead 60% of total labor and material costs 98,528

Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719

Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860

Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,188,875

See summary page for notes and assumptions

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EU100 WWESP 9/6/2006 Page 17 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 7: 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 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 525.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor , 0 , Annual Operating Hours, 0% utilization

Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2 hr/8 hr shift, Annual Operating Hours, 0% utilization

Supervisor 15% of Op. NA 15,636 of Op., 0 , Annual Operating Hours, 0% utilization

Maintenance , 0 , Annual Operating Hours, 0% utilization

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15 hr/wk, Annual Operating Hours, 0% utilization

Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization

Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

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EU100 WWESP 9/6/2006 Page 18 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 8: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105

Standardized Flow Rate 152,520 scfm @ 32o F

Expected Utilization Rate 93% Temperature 140 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3%

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,593,104

 Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622

 Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,924,967

 Total Direct Capital Cost, DC 7,290,588

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404

Total Capital Investment (TCI) = DC + IC 21,846,389

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,249,949

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 124.8 273.7 0% 273.7 - NA

Sulfur Dioxide (SO2

) 9.6 11.8 80% 1.9 7.6 496,949

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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EU104 WWESP 9/6/2006 Page 19 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 8: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,593,104

Instrumentation 10% of control device cost (A) 359,310

MN Sales Taxes 6.5% of control device cost (A) 233,552

Freight 5% of control device cost (A) 179,655

Purchased Equipment Total (B) 22% 4,365,622

Installation

Foundations & supports 4% of purchased equip cost (B) 174,625

Handling & erection 50% of purchased equip cost (B) 2,182,811

Electrical 8% of purchased equip cost (B) 349,250

Piping 1% of purchased equip cost (B) 43,656

Insulation 2% of purchased equip cost (B) 87,312

Painting 2% of purchased equip cost (B) 87,312

Installation Subtotal Standard Expenses 67% 2,924,967

Total Direct Capital Cost, DC 7,290,588

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 873,124

Construction & field expenses 20% of purchased equip cost (B) 873,124

Contractor fees 10% of purchased equip cost (B) 436,562

Start-up 1% of purchased equip cost (B) 43,656

Performance test 1% of purchased equip cost (B) 43,656

Model Studies 2% of purchased equip cost (B) 87,312

Contingencies 3% of purchased equip cost (B) 130,969

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404

Total Capital Investment (TCI) = DC + IC 9,778,993

Retrofit multiplier3

60% of TCI 5,867,396

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 21,846,389

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 35,931

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519

Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805

WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595

Caustic 305.96 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization 35,099

Total Annual Direct Operating Costs 1,249,949

Indirect Operating Costs

Overhead 60% of total labor and material costs 95,958

Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580

Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790

Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,799,211

See summary page for notes and assumptions

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EU104 WWESP 9/6/2006 Page 20 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 8: 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 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 439.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15,636 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr

Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization

Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

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EU104 WWESP 9/6/2006 Page 21 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 9: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113

Standardized Flow Rate 181,762 scfm @ 32o F

Expected Utilization Rate 93% Temperature 142 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5%

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,999,843

 Purchased Equipment Total (B) 22% of control device cost (A) 4,859,809

 Installation - Standard Costs 67% of purchased equip cost (B) 3,256,072

 Installation - Site Specific Costs 6,200,000

 Installation Total 3,256,072

 Total Direct Capital Cost, DC 8,115,881

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091

Total Capital Investment (TCI) = DC + IC 23,617,556

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,530,874

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 51.3 109.9 0% 109.9 - NA

Sulfur Dioxide (SO2

) 26.3 35.5 80% 5.3 21.0 204,058 

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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EU110 WWESP 9/6/2006 Page 22 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 9: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,999,843

Instrumentation 10% of control device cost (A) 399,984

MN Sales Taxes 6.5% of control device cost (A) 259,990

Freight 5% of control device cost (A) 199,992

Purchased Equipment Total (B) 22% 4,859,809

Installation

Foundations & supports 4% of purchased equip cost (B) 194,392

Handling & erection 50% of purchased equip cost (B) 2,429,905

Electrical 8% of purchased equip cost (B) 388,785

Piping 1% of purchased equip cost (B) 48,598

Insulation 2% of purchased equip cost (B) 97,196

Painting 2% of purchased equip cost (B) 97,196

Installation Subtotal Standard Expenses 67% 3,256,072

Total Direct Capital Cost, DC 8,115,881

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 971,962

Construction & field expenses 20% of purchased equip cost (B) 971,962

Contractor fees 10% of purchased equip cost (B) 485,981

Start-up 1% of purchased equip cost (B) 48,598

Performance test 1% of purchased equip cost (B) 48,598

Model Studies 2% of purchased equip cost (B) 97,196

Contingencies 3% of purchased equip cost (B) 145,794

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,770,091

Total Capital Investment (TCI) = DC + IC 10,885,972

Retrofit multiplier3

60% of TCI 6,531,583

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 23,617,556

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,340

Maintenance Materials 1.00 % of Maintenance Labor 39,998

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization 244,544

Water 0.28 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 143,251

WW Treat Neutralization 1.69 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization 873,571

Caustic 305.96 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization 105,296

Total Annual Direct Operating Costs 1,530,874

Indirect Operating Costs

Overhead 60% of total labor and material costs 98,528

Administration (2% total capital costs) 2% of total capital costs (TCI) 217,719

Property tax (1% total capital costs) 1% of total capital costs (TCI) 108,860

Insurance (1% total capital costs) 1% of total capital costs (TCI) 108,860

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,229,330

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,763,297

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,294,171

See summary page for notes and assumptions

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EU110 WWESP 9/6/2006 Page 23 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 9: 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 222,400 10 402.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 20.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 52,600 102.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 525.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 1112.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 88.75 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15,636 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,340 $/Hr, 15.0 hr/wk, 8339.1 hr/yr

Maint Mtls 1 % of Purchase Cost NA 39,998 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 525.5 kW-hr 4,075,729 244,544 $/kwh, 526 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/mgal 1,112.0 gpm 517,438 143,251 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/mgal 1,112.0 gpm 517,438 873,571 $/mgal, 1,112 gpm, Annual Operating Hours, 93% utilization

Caustic 305.96 $/ton 88.8 lb/hr 344 105,296 $/ton, 89 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

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BART Report - Appendix A Emission Control Cost Analysis

Table 10: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115

Standardized Flow Rate 152,520 scfm @ 32o F

Expected Utilization Rate 93% Temperature 140 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 3,593,104

 Purchased Equipment Total (B) 22% of control device cost (A) 4,365,622

 Installation - Standard Costs 67% of purchased equip cost (B) 2,924,967

 Installation - Site Specific Costs 6,200,000

 Installation Total 2,924,967

 Total Direct Capital Cost, DC 7,290,588

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404

Total Capital Investment (TCI) = DC + IC 21,846,389

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,214,850

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113

Actual

Emission Control Cost Calculation Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 124.8 267.7 0% 267.7 - NA

Sulfur Dioxide (SO2

) 8.8 11.8 80% 1.8 7.0 535,575

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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EU114 WWESP 9/6/2006 Page 25 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 10: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 3,593,104

Instrumentation 10% of control device cost (A) 359,310

MN Sales Taxes 6.5% of control device cost (A) 233,552

Freight 5% of control device cost (A) 179,655

Purchased Equipment Total (B) 22% 4,365,622

Installation

Foundations & supports 4% of purchased equip cost (B) 174,625

Handling & erection 50% of purchased equip cost (B) 2,182,811

Electrical 8% of purchased equip cost (B) 349,250

Piping 1% of purchased equip cost (B) 43,656

Insulation 2% of purchased equip cost (B) 87,312

Painting 2% of purchased equip cost (B) 87,312

Installation Subtotal Standard Expenses 67% 2,924,967

Total Direct Capital Cost, DC 7,290,588

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 873,124

Construction & field expenses 20% of purchased equip cost (B) 873,124

Contractor fees 10% of purchased equip cost (B) 436,562

Start-up 1% of purchased equip cost (B) 43,656

Performance test 1% of purchased equip cost (B) 43,656

Model Studies 2% of purchased equip cost (B) 87,312

Contingencies 3% of purchased equip cost (B) 130,969

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 2,488,404

Total Capital Investment (TCI) = DC + IC 9,778,993

Retrofit multiplier3

60% of TCI 5,867,396

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 21,846,389

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, 8339.1 hr/yr 4,125

Maintenance Materials 1.00 % of Maintenance Labor 35,931

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization 204,519

Water 0.28 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 119,805

WW Treat Neutralization 1.69 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization 730,595

Total Annual Direct Operating Costs 1,214,850

Indirect Operating Costs

Overhead 60% of total labor and material costs 95,958

Administration (2% total capital costs) 2% of total capital costs (TCI) 195,580

Property tax (1% total capital costs) 1% of total capital costs (TCI) 97,790

Insurance (1% total capital costs) 1% of total capital costs (TCI) 97,790

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,062,145

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,549,263

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,764,113

See summary page for notes and assumptions

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EU114 WWESP 9/6/2006 Page 26 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 10: 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 186,000 10 336.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 17.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 43,991 85.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 439.5

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 930.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 29.58 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15,636 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 4,125 $/Hr, 15.0 hr/wk, 8339.1 hr/yr

Maint Mtls 1 % of Purchase Cost NA 35,931 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 439.5 kW-hr 3,408,658 204,519 $/kwh, 440 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/mgal 930.0 gpm 432,749 119,805 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/mgal 930.0 gpm 432,749 730,595 $/mgal, 930 gpm, Annual Operating Hours, 93% utilization

Caustic 305.96 $/ton 29.6 lb/hr 115 35,099 $/ton, 30 lb/hr, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See summary page for notes and assumptions

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EU114 WWESP 9/6/2006 Page 27 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 11: - SCR + Reheat (100)

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment (A) 10,191,798

 Purchased Equipment Total (B) SCR Only 10,854,265

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,024,725

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,019,283

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,301,482

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,326,542

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,628,024

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 112.4 1.5 0.01 5.7 106.7 108,969

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 = 90% reduction which is typically the upper range of normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 11: - SCR + Reheat (100)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,191,798

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 662,467

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 10,854,265

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 24% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,024,725

Total Plant Cost D A + B + C 15,522,888

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 475,098

Inventory Capital Reagent Vol * $/gal 2,331

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,232,317

Retrofit multiplier360% of TCI 14,539,390

Total Retorfit Capital Investment 38,771,707

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 363,485

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization 672,157

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 423,178

NA NA - 

Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 1,642,933

Indirect Operating Costs

Overhead 60% of total labor and material costs 40,360

Administration (2% total capital costs) 2% of total capital costs (TCI) 484,646

Property tax (1% total capital costs) 1% of total capital costs (TCI) 242,323

Insurance (1% total capital costs) 1% of total capital costs (TCI) 242,323

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,287,359

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,297,011

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,939,944

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 11: - SCR + Reheat (100)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 1,052 Plant Cap kW A 107,954

Est power platn eff 35% Unc Nox lb/mmBtuB 0.05 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 107,954 Capital Cost $/kW D $94.41 $10,191,798.18 Total SCR Equipment

Uncontrolled Nox t/y 112.4 Fixed O&M E $67,265.87

Annual Operating Hrs 8000 Variable O&M F $205,606.98

Uncontrolled Nox lb/mmBtu 0.049 Ann Cap Factor G 0.82

Heat Input mmBtu/hrH 6,000

SCR Capital Cost

Duty 1,052 MMBtu/hr Catalyst Area 508 ft2614 f (h SCR)

Q flue gas 487,426 acfm Rx Area 584 83 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 24.2 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,220,568 f (vol catalyst)

Temperature 142 Deg F h SCR 131 ft f (h SCR)

Catalyst Volume 34,252 ft3New/Retrofit R N or R 

Electrical Use

Duty 1,052 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 1,444.5

NOx in 0.05 lb/MMBtu

n catalyst layers 23 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1444.5

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

20 lb/hr Neat 9.2 gal/hr

29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost

69 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.01

Nitrous Oxides (NOx) 112.4 0.05 51.25

Actual dscf/MMBtu 69,180

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 1,052 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 363,485 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 1444.5 kW-hr 11,202,612 672,157 $/kwh, 1,444 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 108.0 mw 112 423,178 Catalyst Replacement

7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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BART Report - Appendix A Emission Control Cost Analysis

Table 12: Reheat (100)

Operating Unit: Furnace 11 Hood Exhaust

Emission Unit Number EU 100 Stack/Vent Number SV 101, 102, & 103 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 11.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 172,951 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 535,530

 Purchased Equipment Total (B) 22% of control device cost (A) 650,668

 Installation - Standard Costs 30% of purchased equip cost (B) 195,201

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,395,201

 Total Direct Capital Cost, DC 7,045,869

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707

Total Capital Investment (TCI) = DC + IC 7,247,576

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,658,549

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079

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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BART Report - Appendix A Emission Control Cost Analysis

Table 12: Reheat (100)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 535,530

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 53,553

MN Sales Taxes 6.5% of control device cost (A) 34,809

Freight 5% of control device cost (A) 26,776

Purchased Equipment Total (B) 22% 650,668

Installation

Foundations & supports 8% of purchased equip cost (B) 52,053

Handling & erection 14% of purchased equip cost (B) 91,094

Electrical 4% of purchased equip cost (B) 26,027

Piping 2% of purchased equip cost (B) 13,013

Insulation 1% of purchased equip cost (B) 6,507

Painting 1% of purchased equip cost (B) 6,507

Installation Subtotal Standard Expenses 30% 195,201

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

Installation Total 6,395,201

Total Direct Capital Cost, DC 7,045,869

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 65,067

Construction & field expenses 5% of purchased equip cost (B) 32,533

Contractor fees 10% of purchased equip cost (B) 65,067

Start-up 2% of purchased equip cost (B) 13,013

Performance test 1% of purchased equip cost (B) 6,507

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,520

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,707

Total Capital Investment (TCI) = DC + IC 7,247,576

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,576

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421

Natural Gas 10.02 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization 5,182,616

Total Annual Direct Operating Costs 5,658,549

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952

Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476

Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,530

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,688,079

See Summary page for notes and assumptions

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BART Report - <Insert attachment name> Emission Control Cost Analysis

Table 12: Reheat (100)

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 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 824.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 3,909 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization

Natural Gas 10.02 $/mscf 1,112 scfm 517,206 5,182,616 $/mscf, 1,112 scfm, 8339.1 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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BART Report - Appendix A Emission Control Cost Analysis

Table 12: Reheat (100)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 142 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 568 Deg F - Temperature of waste gas out of heat recovery

Tfo 324 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 195,062 scfm - Flow of waste gas 

Qaf 1,112 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 196,173 scfm Flue Gas Cost in 1989 $'s $449,154

Current Cost Using CHE Plant Cost Index $535,530

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Indurator Flue Gas Heat Capacity - Basis Typical Composition

100 scfm 359 scf/lbmole

Gas Composition lb/hr f wt % Cp Gas Cp Flue

28 mw CO 0 v % 0

44 mw CO2 15 v % 184 22.0% 0.24 0.0528

18 mw H2O 10 v % 50 6.0% 0.46 0.0276

28 mw N2 60 v % 468 56.0% 0.27 0.1512

32 mw O2 15 v % 134 16.0% 0.23 0.0368

Cp Flue Gas 100 v % 836 100.0% 0.2684

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

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Table 13: - SCR + Reheat (104)

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs EPRI Correlation 1998

 Purchased Equipment (A) 2005 0

 Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 9,372,318

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,802,433

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,197,692

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 4,157,530

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,081,731

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 8,239,261

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 273.7 4.6 0.03 17.8 255.9 32,199

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 = 90% reduction which is typically the upper range of normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 13: - SCR + Reheat (104)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,800,299

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 572,019

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 9,372,318

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 28% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 1,802,433

Total Plant Cost D A + B + C 13,818,649

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 441,013

Inventory Capital Reagent Vol * $/gal 5,677

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,497,340

Retrofit multiplier360% of TCI 13,498,404

Total Retorfit Capital Investment 35,995,743

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 337,460

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization 543,246

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 327,363

NA NA - 

Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 1,484,414

Indirect Operating Costs

Overhead 60% of total labor and material costs 34,849

Administration (2% total capital costs) 2% of total capital costs (TCI) 449,947

Property tax (1% total capital costs) 1% of total capital costs (TCI) 224,973

Insurance (1% total capital costs) 1% of total capital costs (TCI) 224,973

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,123,590

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,058,332

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,542,746

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 13: - SCR + Reheat (104)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 814 Plant Cap kW A 83,511

Est power platn eff 35% Unc Nox lb/mmBtuB 0.15 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 83,511 Capital Cost $/kW D $105.38 $8,800,298.76 Total SCR Equipment

Uncontrolled Nox t/y 273.7 Fixed O&M E $58,081.97

Annual Operating Hrs 8000 Variable O&M F $171,504.18

Uncontrolled Nox lb/mmBtu 0.153 Ann Cap Factor G 0.82

Heat Input mmBtu/hrH 6,000

SCR Capital Cost

Duty 814 MMBtu/hr Catalyst Area 393 ft2638 f (h SCR)

Q flue gas 377,064 acfm Rx Area 452 121 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 21.3 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,646,500 f (vol catalyst)

Temperature 140 Deg F h SCR 135 ft f (h SCR)

Catalyst Volume 27,694 ft3New/Retrofit R N or R 

Electrical Use

Duty 814 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 1,167.5

NOx in 0.15 lb/MMBtu

n catalyst layers 24 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1167.5

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

49 lb/hr Neat 22.3 gal/hr

29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost

167 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.03

Nitrous Oxides (NOx) 273.7 0.15 124.83

Actual dscf/MMBtu 53,517

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 814 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 337,460 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 1167.5 kW-hr 9,054,097 543,246 $/kwh, 1,167 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 83.5 mw 112 327,363 Catalyst Replacement

7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 14: - Reheat (104)

Operating Unit: Furnace 11 Waste Gas

Emission Unit Number EU 104 Stack/Vent Number SV 104 & 105 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 512,205

 Purchased Equipment Total (B) 22% of control device cost (A) 622,328

 Installation - Standard Costs 30% of purchased equip cost (B) 186,699

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,386,699

 Total Direct Capital Cost, DC 7,009,027

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922

Total Capital Investment (TCI) = DC + IC 7,201,949

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,673,116

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (104) Reheat (104) 38 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 14: - Reheat (104)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 512,205

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 51,220

MN Sales Taxes 6.5% of control device cost (A) 33,293

Freight 5% of control device cost (A) 25,610

Purchased Equipment Total (B) 22% 622,328

Installation

Foundations & supports 8% of purchased equip cost (B) 49,786

Handling & erection 14% of purchased equip cost (B) 87,126

Electrical 4% of purchased equip cost (B) 24,893

Piping 2% of purchased equip cost (B) 12,447

Insulation 1% of purchased equip cost (B) 6,223

Painting 1% of purchased equip cost (B) 6,223

Installation Subtotal Standard Expenses 30% 186,699

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

Installation Total 6,386,699

Total Direct Capital Cost, DC 7,009,027

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 62,233

Construction & field expenses 5% of purchased equip cost (B) 31,116

Contractor fees 10% of purchased equip cost (B) 62,233

Start-up 2% of purchased equip cost (B) 12,447

Performance test 1% of purchased equip cost (B) 6,223

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 18,670

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 192,922

Total Capital Investment (TCI) = DC + IC 7,201,949

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,201,949

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667

Natural Gas 10.02 $/mscf, 485 scfm, 8339.1 hr/yr, 93% utilization 2,259,937

Total Annual Direct Operating Costs 2,673,116

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 144,039

Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,019

Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,019

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,813

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,398

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,696,515

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - <Insert attachment name> Emission Control Cost Analysis

Table 14: - Reheat (104)

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 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 689.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 3,909 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization

Natural Gas 10.02 $/mscf 485 scfm 225,534 2,259,937 $/mscf, 485 scfm, 8339.1 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 14: - Reheat (104)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 140 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 357 Deg F - Temperature of waste gas out of heat recovery

Tfo 233 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 163,680 scfm - Flow of waste gas 

Qaf 485 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 164,165 scfm Flue Gas Cost in 1989 $'s $429,591

Current Cost Using CHE Plant Cost Index $512,205

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 15: - SCR + Reheat (110)

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs EPRI Correlation 1998

 Purchased Equipment (A) 2005 10,324,640

 Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 10,995,741

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 2,045,946

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 46,284,809

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 7,339,040

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,349,371

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 11,688,411

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 109.9 1.4 0.01 5.6 104.4 112,008

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 = 90% reduction which is typically the upper range of normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 15: - SCR + Reheat (110)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 10,324,640

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 671,102

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 10,995,741

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 24% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 24% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 2,045,946

Total Plant Cost D A + B + C 15,685,586

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 478,352

Inventory Capital Reagent Vol * $/gal 2,331

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 24,398,268

Retrofit multiplier360% of TCI 14,638,961

Total Retorfit Capital Investment 39,037,230

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 365,974

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization 686,019

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 431,932

NA NA - 

Ammonia 0.12 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization 64,238

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 1,668,038

Indirect Operating Costs

Overhead 60% of total labor and material costs 40,886

Administration (2% total capital costs) 2% of total capital costs (TCI) 487,965

Property tax (1% total capital costs) 1% of total capital costs (TCI) 243,983

Insurance (1% total capital costs) 1% of total capital costs (TCI) 243,983

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,303,024

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,319,840

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,987,878

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 15: - SCR + Reheat (110)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 1,074 Plant Cap kW A 110,187

Est power platn eff 35% Unc Nox lb/mmBtuB 0.05 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 110,187 Capital Cost $/kW D $93.70 $10,324,639.77 Total SCR Equipment

Uncontrolled Nox t/y 109.9 Fixed O&M E $68,142.62

Annual Operating Hrs 8000 Variable O&M F $209,166.23

Uncontrolled Nox lb/mmBtu 0.048 Ann Cap Factor G 0.82

Heat Input mmBtu/hrH 6,000

SCR Capital Cost

Duty 1,074 MMBtu/hr Catalyst Area 518 ft2613 f (h SCR)

Q flue gas 497,508 acfm Rx Area 596 80 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 24.4 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.05 lb/MMBtu n layer 22 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 23.5 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 23 layers 8,387,553 f (vol catalyst)

Temperature 142 Deg F h SCR 131 ft f (h SCR)

Catalyst Volume 34,948 ft3New/Retrofit R N or R 

Electrical Use

Duty 1,074 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 1,474.3

NOx in 0.05 lb/MMBtu

n catalyst layers 23 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1474.3

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

20 lb/hr Neat 9.2 gal/hr

29% solution Volume 14 day inventory 3,083 gal $2,331 Inventory Cost

69 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.01

Nitrous Oxides (NOx) 109.9 0.05 51.25

Actual dscf/MMBtu 70,611

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 1,074 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 365,974 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 1474.3 kW-hr 11,433,649 686,019 $/kwh, 1,474 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 110.2 mw 112 431,932 Catalyst Replacement

7 Ammonia 0.12 $/lb 69 lb/hr 532,660 64,238 $/lb, 69 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 16: - Reheat (110)

Operating Unit: Furnace 12 Hood Exhaust

Emission Unit Number EU 110 Stack/Vent Number SV 111, 112, & 113 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 181,762 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 142 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 9.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 222,400 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 195,062 scfm @ 68o F

Dry Std Flow Rate 176,529 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 535,531

 Purchased Equipment Total (B) 22% of control device cost (A) 650,671

 Installation - Standard Costs 30% of purchased equip cost (B) 195,201

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,395,201

 Total Direct Capital Cost, DC 7,045,872

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708

Total Capital Investment (TCI) = DC + IC 7,247,580

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 5,671,002

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 16: - Reheat (110)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 535,531

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 53,553

MN Sales Taxes 6.5% of control device cost (A) 34,810

Freight 5% of control device cost (A) 26,777

Purchased Equipment Total (B) 22% 650,671

Installation

Foundations & supports 8% of purchased equip cost (B) 52,054

Handling & erection 14% of purchased equip cost (B) 91,094

Electrical 4% of purchased equip cost (B) 26,027

Piping 2% of purchased equip cost (B) 13,013

Insulation 1% of purchased equip cost (B) 6,507

Painting 1% of purchased equip cost (B) 6,507

Installation Subtotal Standard Expenses 30% 195,201

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

Installation Total 6,395,201

Total Direct Capital Cost, DC 7,045,872

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 65,067

Construction & field expenses 5% of purchased equip cost (B) 32,534

Contractor fees 10% of purchased equip cost (B) 65,067

Start-up 2% of purchased equip cost (B) 13,013

Performance test 1% of purchased equip cost (B) 6,507

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 19,520

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 201,708

Total Capital Investment (TCI) = DC + IC 7,247,580

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,247,580

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization 383,421

Natural Gas 10.02 $/mscf, 1,114 scfm, 8339.1 hr/yr, 93% utilization 5,195,069

Total Annual Direct Operating Costs 5,671,002

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 144,952

Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,476

Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,476

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 684,120

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,029,531

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,700,533

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - <Insert attachment name> Emission Control Cost Analysis

Table 16: - Reheat (110)

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 222,400 19 0.6 824.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 222,400 23 0.6 997.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 824.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 3,909 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 824.0 kW-hr 6,390,357 383,421 $/kwh, 824 kW-hr, 8339.1 hr/yr, 93% utilization

Natural Gas 10.02 $/mscf 1,114 scfm 518,449 5,195,069 $/mscf, 1,114 scfm, 8339.1 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (110) Reheat (110) 47 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 16: - Reheat (110)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 140 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 567 Deg F - Temperature of waste gas out of heat recovery

Tfo 323 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 195,062 scfm - Flow of waste gas 

Qaf 1,114 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 196,176 scfm Flue Gas Cost in 1989 $'s $449,155

Current Cost Using CHE Plant Cost Index $535,531

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (110) Reheat (110) 48 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 17: - SCR + Reheat (114)

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 114 & 115

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F

Expected Utiliztion Rate 93% Temperature 140 Deg F

Expected Annual Hours of Operation 8,339 Hours Moisture Content 16.4%

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 136,902 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment (A) 8,929,135

 Purchased Equipment Total (B) SCR Only 9,509,529

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 1,823,014

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC SCR + Reheat 43,455,895

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 6,279,410

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 4,103,963

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 10,383,373

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 267.7 4.5 0.03 17.4 250.3 41,488

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 = 90% reduction which is typically the upper range of normal SCR control efficiency

12 $35/MW-hr, 140 MW

13 Catalyst replacement every 8000 hours. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

Notes to User

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 17: - SCR + Reheat (114)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 8,929,135

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 580,394

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 9,509,529

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 28% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 28% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 1,823,014

Total Plant Cost D A + B + C 13,976,441

Allowance for Funds During Construction (E) Additional 10 week outage for installation 8,232,000

Pre Production Costs (G) 2% of (D+E)) 444,169

Inventory Capital Reagent Vol * $/gal 5,677

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 22,658,287

Retrofit multiplier360% of TCI 13,594,972

Total Retorfit Capital Investment 36,253,260

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr 104,239

Supervisor 15% 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 339,874

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization 555,760

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 35.00 Catalyst Replacement 334,973

NA NA - 

Ammonia 0.12 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization 156,470

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 1,506,951

Indirect Operating Costs

Overhead 60% of total labor and material costs 35,359

Administration (2% total capital costs) 2% of total capital costs (TCI) 453,166

Property tax (1% total capital costs) 1% of total capital costs (TCI) 226,583

Insurance (1% total capital costs) 1% of total capital costs (TCI) 226,583

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,138,782

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,080,473

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,587,424

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

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BART Report - Appendix A Emission Control Cost Analysis

Table 17: - SCR + Reheat (114)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 833 Plant Cap kW A 85,452

Est power platn eff 35% Unc Nox lb/mmBtuB 0.15 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 85,452 Capital Cost $/kW D $104.49 $8,929,134.83 Total SCR Equipment

Uncontrolled Nox t/y 267.7 Fixed O&M E $58,932.29

Annual Operating Hrs 8000 Variable O&M F $174,705.21

Uncontrolled Nox lb/mmBtu 0.150 Ann Cap Factor G 0.82

Heat Input mmBtu/hrH 6,000

SCR Capital Cost

Duty 833 MMBtu/hr Catalyst Area 402 ft2638 f (h SCR)

Q flue gas 385,829 acfm Rx Area 462 117 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 21.5 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 0.15 lb/MMBtu n layer 23 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 24.5 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 24 layers 6,792,565 f (vol catalyst)

Temperature 140 Deg F h SCR 135 ft f (h SCR)

Catalyst Volume 28,302 ft3New/Retrofit R N or R 

Electrical Use

Duty 833 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 1,194.4

NOx in 0.15 lb/MMBtu

n catalyst layers 24 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 1194.4

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

49 lb/hr Neat 22.3 gal/hr

29% solution Volume 14 day inventory 7,509 gal $5,677 Inventory Cost

167 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.03

Nitrous Oxides (NOx) 267.7 0.15 124.83

Actual dscf/MMBtu 54,761

Method 19 Factor dscf/MMBtu 9,860

Adjusted Duty 833 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 2,085 104,239 $/Hr, 2.0 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 15,636

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 339,874 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 1194.4 kW-hr 9,262,659 555,760 $/kwh, 1,194 kW-hr, 8339.1 hr/yr, 93% utilization

Cat. Replacement [14] 35 $/MW-hr 85.5 mw 112 334,973 Catalyst Replacement

7 Ammonia 0.12 $/lb 167 lb/hr 1,297,437 156,470 $/lb, 167 lb/hr, 8339.1 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

NOx SCR+ Reheat 90% Eff (114) NOx SCR+ Reheat 90% Eff (114) 51 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 18: - Reheat (114)

Operating Unit: Furnace 12 Waste Gas

Emission Unit Number EU 114 Stack/Vent Number SV 104 & 105 Chemical Engineering

Desgin Capacity 150 MMBtu/hr Standardized Flow Rate 152,520 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 140 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,339 Hours Moisture Content 18.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 186,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 163,680 scfm @ 68o F

Dry Std Flow Rate 133,792 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 512,555

 Purchased Equipment Total (B) 22% of control device cost (A) 622,755

 Installation - Standard Costs 30% of purchased equip cost (B) 186,826

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,386,826

 Total Direct Capital Cost, DC 7,009,581

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054

Total Capital Investment (TCI) = DC + IC 7,202,635

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,772,459

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (114) Reheat (114) 52 of 56
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BART Report - Appendix A Emission Control Cost Analysis

Table 18: - Reheat (114)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 512,555

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 51,256

MN Sales Taxes 6.5% of control device cost (A) 33,316

Freight 5% of control device cost (A) 25,628

Purchased Equipment Total (B) 22% 622,755

Installation

Foundations & supports 8% of purchased equip cost (B) 49,820

Handling & erection 14% of purchased equip cost (B) 87,186

Electrical 4% of purchased equip cost (B) 24,910

Piping 2% of purchased equip cost (B) 12,455

Insulation 1% of purchased equip cost (B) 6,228

Painting 1% of purchased equip cost (B) 6,228

Installation Subtotal Standard Expenses 30% 186,826

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

Installation Total 6,386,826

Total Direct Capital Cost, DC 7,009,581

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 62,275

Construction & field expenses 5% of purchased equip cost (B) 31,138

Contractor fees 10% of purchased equip cost (B) 62,275

Start-up 2% of purchased equip cost (B) 12,455

Performance test 1% of purchased equip cost (B) 6,228

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 18,683

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 193,054

Total Capital Investment (TCI) = DC + IC 7,202,635

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 7,202,635

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 26,060

Supervisor 15% 15% of Operator Costs 3,909

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr 31,272

Maintenance Materials 100% of maintenance labor costs 31,272

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization 320,667

Natural Gas 10.02 $/mscf, 935 scfm, 8339.1 hr/yr, 93% utilization 4,359,280

Total Annual Direct Operating Costs 4,772,459

Indirect Operating Costs

Overhead 60% of total labor and material costs 55,507

Administration (2% total capital costs) 2% of total capital costs (TCI) 144,053

Property tax (1% total capital costs) 1% of total capital costs (TCI) 72,026

Insurance (1% total capital costs) 1% of total capital costs (TCI) 72,026

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 679,878

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,023,490

Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,795,949

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (114) Reheat (114) 53 of 56
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BART Report - <Insert attachment name> Emission Control Cost Analysis

Table 18: - Reheat (114)

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 186,000 19 0.6 689.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 186,000 23 0.6 834.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 689.1

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,339

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 521 26,060 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Supervisor 15% of Op. NA 3,909 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 521 31,272 $/Hr, 0.5 hr/8 hr shift, 8339.1 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 31,272 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.060 $/kwh 689.1 kW-hr 5,344,453 320,667 $/kwh, 689 kW-hr, 8339.1 hr/yr, 93% utilization

Natural Gas 10.02 $/mscf 935 scfm 435,040 4,359,280 $/mscf, 935 scfm, 8339.1 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (114) Reheat (114) 54 of 56
Cleveland Cliffs Incorporated: Northshore Mining

BART Report - Appendix A Emission Control Cost Analysis

Table 18: - Reheat (114)

Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery

Auxiliary Fuel Use Equation 3.19 

Twi 140 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 567 Deg F - Temperature of waste gas out of heat recovery

Tfo 323 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 163,680 scfm - Flow of waste gas 

Qaf 935 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 164,615 scfm Flue Gas Cost in 1989 $'s $429,885

Current Cost Using CHE Plant Cost Index $512,555

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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xls

Reheat (114) Reheat (114) 55 of 56
Inputs

Calculated or scaled valuesEstimated value

1 2 3 4 5 6 7 

Stack No Facility Name

SO2 Max. 24-

hr Actual

Emissions

Flow Rate

at Exit

Specific 

Collection Area 

(SCA)1 

Surface Collection 

Area2

lb/hr acfm ft2/kacfm ft2 

BASE N/A 291,000 198 68,825 

SV 101, 102, & 103 Northshore Furnace 11 Hood Exhaust 35.50 222,400 198 52,600 

SV 104 & 105 Northshore Furnace 11 Waste Gas 11.83 186,000 198 43,991 

SV 111, 112, & 113 Northshore Furnace 12 Hood Exhaust 35.50 222,400 198 52,600 

SV 114 & 115 Northshore Furnace 12 Waste Gas 11.83 186,000 198 43,991 

SV021M-SV024M Hibbtac Pellet Indurating Furnace Line No 1 30.00 772,000 198 182,587 SV025M-SV028M Hibbtac Pellet Indurating Furnace Line No 2 38.00 795,000 198 188,027 SV029M-SV032M Hibbtac Pellet Indurating Furnace Line No 3 43.00 827,000 198 195,595 

SV 014 Ispat Indurating Furnace 125.00 205,478 198 48,598 

SV 015 Ispat Indurating Furnace 125.00 205,478 198 48,598 

SV 016 Ispat Indurating Furnace 125.00 205,478 198 48,598 

SV 017 Ispat Indurating Furnace 125.00 205,478 198 48,598 

SV 046 UTAC Line 1 Pellet Induration 4.25 369,137 198 87,305 

SV 049 UTAC Line 2 Pellet Induration 286.67 380,000 198 89,875 

SV 048 UTAC Line 2 Pellet Induration 345.50 346,000 198 81,833 

SV051M Keetac Grate Kiln - Indurator Waste Gas, Phase II 217.2 848,000 198 200,562 

SV 151 Minntac Line 7 waste gas 75.0 600,000 198 141,907 

SV 127 Minntac Line 5 waste gas 93.7 650,000 198 153,733 

SV 144 Minntac Line 6 waste gas 113.5 555,650 198 131,418 

SV 118 Minntac Line 4 waste gas 133.1 650,000 198 153,733 

SV 103 Minntac Line 3 waste gas 128.9 322,000 198 76,157 

NSM Power 365.0 300,000 141,907 

1) Estimated value from Durr. Value indpendent of stack flow.2) Original estimate from Durr. Scaled linearly using stack flow rates.3) Pressure drop is not a design driving factor, but must be maintained at an acceptably low value. 10" H2O is used as a maximum value.

4) Capital price back calculated using reverse of EPA control cost manual factors from installed price estimate provided from DURR. Used 0.6 power law factor to adjust price to each stack's acfm from bid basis of 291,000 acfm.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Control Costs.xlsWWESP Scale 
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost AnalysisTable 19: Cost Summary - Natural gas boiler

NOx Control Cost Summary baseline: 0.17 lb/mmBtu 11.625 lb/hr

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton Incremental Cost $/ton

Selective Catalytic Reduction (SCR) 90% 4.1 37.1 $5,563,529 $1,119,307 $30,139

Low NOx Burner / Flue Gas Recirculation 75% 10.3 30.9 $547,722 $77,510 $2,505 $30,626Low Nox Burner/Over Fire Air 68% 13.4 27.9 $1,091,532 $387,372 $13,908Low NOx Burner 50% 20.6 20.6 $95,851 $16,766 $813

Selective Non-Catalytic Reduction (SNCR) 50% 20.6 20.6 $925,876 $250,181 $12,126

SO2 Control Cost Summary baseline 0.24 lb/mmBtu 16.75 lb/hr

Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Total Annual Cost $/yr Pollution Control Cost $/ton

Wet ESPProcess Boiler 1 & 2 80% 11.9 61.5 $11,808,857 $2,247,725 $36,558

SO2 AbsorberProcess Boiler 1 & 2 80% 11.9 61.5 $3,935,118 $1,118,879 $18,198Spray Dryer and BaghouseProcess Boiler 1 & 2 90 11.9 61.5 $16,134,577 $2,754,704 $44,804DSI BaghouseProcess Boiler 1 & 2 55 11.9 61.5 $4,890,063 $1,412,189 $22,969Wet ScrubberProcess Boiler 1 & 2 80% 14.68 58.72 $13,618,522 $1,869,933 $31,845

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsCost Summary 9/6/2006 
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost AnalysisTable 20: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Process Boiler 1 & 2 Study Year 2006

Emission Unit Number 003 & 004Stack/Vent Number 003

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 50.00 $/hr Estimated industry average

Maintenance Labor 60.00 $/hr Estimated industry average

Electricity 0.052 $/kwh 0.049 2004

DOE Average Retail Price of Industrial Electricity, 2004 http://www.eia.doe.gov/emeu/aer/txt/p

Natural Gas 2.31 $/mscf 2005

Average natural gas spot price July 04 - June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com

Water 0.40 $/mgal 0.76 2004 Estimated industrial cost cost adjusted for 3% inflation

Cooling Water 0.28 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th ed. Section 3.1 Ch 1

Ch 1 Carbon Absorbers, 1999 $0.15 3% inflation

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, Cinflation

Wastewater Disposal Neutralization 3.80 $/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 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.28 $/mgal 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 tadjusted for 3% inflation

Solid Waste Disposal 11.48 $/ton 25.00 2002

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $20 - $30/ton Used $25inflation

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 $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 

Internal Waste Recycle 1 $/ton 1.00 2000 Estimated waste cost Used $1/ton to cover cost of materials 

Chemicals & SuppliesLime 90.00 $/ton Info provided by Sonnek EngineeingCaustic 305.21 $/ton 2005 Hawkins Chemical 50% solution (50 Deg Be) includes deUrea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, include

Soda Ash $/tonOxygen 1.49 Mscf 1.40 2004 Industry estimate cost adjusted for 3% inflation

EPA Urea 179.1 $/tonAmmonia 0.92 $/lbReagent #8 0.00 $/tonCatalyst & Replacement Parts SCR Catalyst 500 $/ft3 Cormetech, Inc., 1/2006 bid

CO Catalyst 650 $/ft3 Vendor quote if neededCatalyst #3Catalyst #4Catalyst #5Filter Bags 37.94 $/bag 33.71 2002

EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6, Chapter 1 Example problem cost for 10 ft bags. 

Tower Packing 100 $/ft3

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsUtility Chem$ Data 9/6/2006 
Replacement Parts

Replacement PartsReplacement PartsOtherSales 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 defau

Operating InformationAnnual Op. Hrs 7,650 Hours Engineering Estimate

Utilization Rate 93%Equipment Life 20 yrs Engineering Estimate

Design Capacity 70 MMBtu/hrStandardized Flow Rate 64,771 scfm @ 32o F

Temperature 450 Deg F

Moisture Content 13.3%Actual Flow Rate 119,800 acfm

Standardized Flow Rate 69,510 scfm @ 68o F Based on Table 19.2 of 40 CFR 60, A

Dry Std Flow Rate 60,265 dscfm @ 68o F

Max Emis

Pollutant Lb/Hr

PM10 1.90Total Particulates 1.90Nitrous Oxides (NOx) 11.60Sulfur Dioxide (SO2) 16.800

Sulfuric Acid MistFluoridesVolatile Organic Compounds (VOC) 0.99Carbon Monoxide (CO) 0.00Lead (Pb)Enter this data for each emission unitEnter data for this study (applies to all units)

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xlsUtility Chem$ Data 9/6/2006 
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 21: NOx Control - Low NOx Burner

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 49,000

 Purchased Equipment Total (B) 22% of control device cost (A) 59,535

 Installation - Standard Costs 30% of purchased equip cost (B) 17,861

 Installation - Site Specific Costs NA

 Installation Total 17,861

 Total Direct Capital Cost, DC 77,396

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456

Total Capital Investment (TCI) = DC + IC 95,851

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,866

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900

Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766

Emission Control Cost Calculation

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

PM10 1.9 6.8 6.8 - NA

Total Particulates 1.9 6.8 6.8 - NA

Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 813

Sulfur Dioxide (SO2

) 16.8 59.8 59.8 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA

Carbon Monoxide (CO) - - 0.0 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Burner cost scaled from MacTec Burner Estimate, March 2005 cost estimate

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

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Low NOx 9/6/2006 Page 4 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 21: NOx Control - Low NOx Burner

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 49,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 4,900

Mn Sales Taxes 6.5% of control device cost (A) 3,185

Freight 5% of control device cost (A) 2,450

Purchased Equipment Total (B) 22% 59,535

Installation

Foundations & supports 8% of purchased equip cost (B) 4,763

Handling & erection 14% of purchased equip cost (B) 8,335

Electrical 4% of purchased equip cost (B) 2,381

Piping 2% of purchased equip cost (B) 1,191

Insulation 1% of purchased equip cost (B) 595

Painting 1% of purchased equip cost (B) 595

Installation Subtotal Standard Expenses 30% 17,861

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 17,861

Total Direct Capital Cost, DC 77,396

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 5,954

Construction & field expenses 5% of purchased equip cost (B) 2,977

Contractor fees 10% of purchased equip cost (B) 5,954

Start-up 2% of purchased equip cost (B) 1,191

Performance test 1% of purchased equip cost (B) 595

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 1,786

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 18,456

Total Capital Investment (TCI) = DC + IC 95,851

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 95,851

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478

Supervisor 15% 15% of Operator Costs 72

Maintenance

Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574

Maintenance Materials 100% of maintenance labor costs 574

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,168

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 2,866

Indirect Operating Costs

Overhead 60% of total labor and material costs 1,018

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,917

Property tax (1% total capital costs) 1% of total capital costs (TCI) 959

Insurance (1% total capital costs) 1% of total capital costs (TCI) 959

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 9,048

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 13,900

Total Annual Cost (Annualized Capital Cost + Operating Cost) 16,766

See Summary page for notes and assumptions

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Low NOx 9/6/2006 Page 5 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 21: NOx Control - Low NOx Burner

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 650 $/ft3

Amount Required 39 ft3

Catalyst Cost 28,265 Cost adjusted for freight & sales tax

Installation Labor 4,240 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 37.940902 $ 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 D P in H2O Efficiency Hp kW

Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3.2

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 72 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 3.2 kW-hr 22,465 1,168 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.49 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization

2 CO Catalyst 650 $/ft3 0 ft30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 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 BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Low NOx 9/6/2006 Page 6 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 280,000

 Purchased Equipment Total (B) 22% of control device cost (A) 340,200

 Installation - Standard Costs 30% of purchased equip cost (B) 102,060

 Installation - Site Specific Costs NA

 Installation Total 102,060

 Total Direct Capital Cost, DC 442,260

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462

Total Capital Investment (TCI) = DC + IC 547,722

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,881

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628

Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510

Emission Control Cost Calculation

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

PM10 1.9 6.8 6.8 - NA

Total Particulates 1.9 6.8 6.8 - NA

Nitrous Oxides (NOx) 11.6 41.3 75% 10.3 30.9 2,505

Sulfur Dioxide (SO2

) 16.8 59.8 59.8 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA

Carbon Monoxide (CO) - - 0.0 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Low NOx FGR 9/6/2006 Page 7 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 280,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 28,000

MN Sales Taxes 6.5% of control device cost (A) 18,200

Freight 5% of control device cost (A) 14,000

Purchased Equipment Total (B) 22% 340,200

Installation

Foundations & supports 8% of purchased equip cost (B) 27,216

Handling & erection 14% of purchased equip cost (B) 47,628

Electrical 4% of purchased equip cost (B) 13,608

Piping 2% of purchased equip cost (B) 6,804

Insulation 1% of purchased equip cost (B) 3,402

Painting 1% of purchased equip cost (B) 3,402

Installation Subtotal Standard Expenses 30% 102,060

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 102,060

Total Direct Capital Cost, DC 442,260

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 34,020

Construction & field expenses 5% of purchased equip cost (B) 17,010

Contractor fees 10% of purchased equip cost (B) 34,020

Start-up 2% of purchased equip cost (B) 6,804

Performance test 1% of purchased equip cost (B) 3,402

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 10,206

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 105,462

Total Capital Investment (TCI) = DC + IC 547,722

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 547,722

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 478

Supervisor 15% 15% of Operator Costs 72

Maintenance

Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574

Maintenance Materials 100% of maintenance labor costs 574

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization 1,184

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 2,881

Indirect Operating Costs

Overhead 60% of total labor and material costs 1,018

Administration (2% total capital costs) 2% of total capital costs (TCI) 10,954

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,477

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,477

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 51,701

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 74,628

Total Annual Cost (Annualized Capital Cost + Operating Cost) 77,510

See Summary page for notes and assumptions

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Low NOx FGR 9/6/2006 Page 8 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 22: NOx Control - Low NOx Burner with Flue Gas Recirculation/Advanced Controls

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 650 $/ft3

Amount Required 39 ft3

Catalyst Cost 28,265 Cost adjusted for freight & sales tax

Installation Labor 4,240 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 37.940902 $ 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 D P in H2O Efficiency Hp kW

Blower, Thermal 3,239 5 0.6 3.2 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3.2

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 0.01 hr/8 hr shift 10 478 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 72 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 3.2 kW-hr 22,766 1,184 $/kwh, 3 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization

2 CO Catalyst 650 $/ft3 0 ft30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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Low NOx FGR 9/6/2006 Page 9 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 23: NOx Control - Low NOx Burner with Overfire Air

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs [2]

 Direct Capital Costs 468000

 Purchased Equipment (A) 558,000

 Purchased Equipment Total (B) 22% of control device cost (A) 677,970

 Installation - Standard Costs 30% of purchased equip cost (B) 203,391

 Installation - Site Specific Costs NA

 Installation Total 203,391

 Total Direct Capital Cost, DC 881,361

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171

Total Capital Investment (TCI) = DC + IC 1,091,532

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 174,008

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364

Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372

Emission Control Cost Calculation

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

PM10 1.9 6.8 6.8 - NA

Total Particulates 1.9 6.8 6.8 - NA

Nitrous Oxides (NOx) 11.6 41.3 68% 13.4 27.9 13,908

Sulfur Dioxide (SO2

) 16.8 59.8 59.8 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA

Carbon Monoxide (CO) - - 0.0 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 

2 Cost based upon Analyzing Electric Power Gneration Under the CAAA.

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 23: NOx Control - Low NOx Burner with Overfire Air

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 558,000

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) 55,800

MN Sales Taxes 6.5% of control device cost (A) 36,270

Freight 5% of control device cost (A) 27,900

Purchased Equipment Total (B) 22% 677,970

Installation

Foundations & supports 8% of purchased equip cost (B) 54,238

Handling & erection 14% of purchased equip cost (B) 94,916

Electrical 4% of purchased equip cost (B) 27,119

Piping 2% of purchased equip cost (B) 13,559

Insulation 1% of purchased equip cost (B) 6,780

Painting 1% of purchased equip cost (B) 6,780

Installation Subtotal Standard Expenses 30% 203,391

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 203,391

Total Direct Capital Cost, DC 881,361

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 67,797

Construction & field expenses 5% of purchased equip cost (B) 33,899

Contractor fees 10% of purchased equip cost (B) 67,797

Start-up 2% of purchased equip cost (B) 13,559

Performance test 1% of purchased equip cost (B) 6,780

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 20,339

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 210,171

Total Capital Investment (TCI) = DC + IC 1,091,532

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,091,532

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625

Supervisor 15% 15% of Operator Costs 14,344

Maintenance

Maintenance Labor 60.00 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr 574

Maintenance Materials 100% of maintenance labor costs 574

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization 62,892

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 174,008

Indirect Operating Costs

Overhead 60% of total labor and material costs 66,670

Administration (2% total capital costs) 2% of total capital costs (TCI) 21,831

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,915

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,915

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 103,033

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 213,364

Total Annual Cost (Annualized Capital Cost + Operating Cost) 387,372

See Summary page for notes and assumptions

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Low NOx OFA 9/6/2006 Page 11 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 23: NOx Control - Low NOx Burner with Overfire Air

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 650 $/ft3

Amount Required 39 ft3

Catalyst Cost 28,265 Cost adjusted for freight & sales tax

Installation Labor 4,240 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 37.940902 $ 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 D P in H2O Efficiency Hp kW

Blower, Thermal 0 19 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Blower, Catalytic 0 23 0.6 0.0 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 0.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 2.00 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 14,344 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.01 hr/8 hr shift 10 574 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 574 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 170.0 kW-hr 1,209,465 62,892 $/kwh, 170 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization

2 CO Catalyst 650 $/ft3 0 ft30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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BART Report - Appendix A Emission Control Cost Analysis

Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F

Expected Utilization Rate 93% Temperature 450 Deg F

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3%

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) NA

 Purchased Equipment Total (B) 22% of control device cost (A) NA

 Installation - Standard Costs 30% of purchased equip cost (B) NA

 Installation - Site Specific Costs NA

 Installation Total NA

 Total Direct Capital Cost, DC NA

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 5,563,529

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 362,636

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307

Emission Control Cost Calculation

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

PM10 1.9 6.8 6.8 - NA

Total Particulates 1.9 6.8 6.8 - NA

Nitrous Oxides (NOx) 11.6 41.3 90% 4.1 37.1 30,139

Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA

Carbon Monoxide (CO) - - 0.0 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

Basis for SCR control cost:

1 The SCR capital investment is from vendor estimates (Babcok Power Inc, 2005). 

2 SCR catalyst quote based on information obtained from Cormetech, Inc. It is used for catalyst replacement costs.

3 The total direct and indirect operating costs are based on operation and maintenance costs in the

 "Pwr Plt SCR $" tab per EPA correlation of SCR costs for power plants.

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BART Report - Appendix A Emission Control Cost Analysis

Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

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 (B) 22% NA

Installation

Foundations & supports 8% of purchased equip cost (B) NA

Handling & erection 14% of purchased equip cost (B) NA

Electrical 4% of purchased equip cost (B) NA

Piping 2% of purchased equip cost (B) NA

Insulation 1% of purchased equip cost (B) NA

Painting 1% of purchased equip cost (B) NA

Installation Subtotal Standard Expenses 30% NA

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 NA

Total Direct Capital Cost, DC NA

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) NA

Construction & field expenses 5% of purchased equip cost (B) NA

Contractor fees 10% of purchased equip cost (B) NA

Start-up 2% of purchased equip cost (B) NA

Performance test 1% of purchased equip cost (B) NA

Model Studies of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) NA

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 5,563,529

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 5,425,183

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Labor NA - 

Maintenance Materials 100% of maintenance labor costs - 

Utilities, Supplies, Replacements & Waste Management

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

CO Catalyst 650.00 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization 52,717

NA NA - 

Total Annual Direct Operating Costs 362,636

Indirect Operating Costs

Overhead 60% of total labor and material costs 22,032

Administration (2% total capital costs) 2% of total capital costs (TCI) 111,271

Property tax (1% total capital costs) 1% of total capital costs (TCI) 55,635

Insurance (1% total capital costs) 1% of total capital costs (TCI) 55,635

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 512,099

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 756,672

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,119,307

See Summary page for notes and assumptions

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst Estimate amount of catalyst required 

Equipment Life 3 years Vol. #1 5000 ft3

CRF 0.3811 Flow #1 359,256 acfm Basis SCR Bids for proposed 2001 Taconite Plant

Rep part cost per unit 65 $/ft3Flow #2 119,800 acfm

Amount Required 1667.3 ft3

Vol #2 1667.3 ft3

Catalyst Cost 120,301 Cost adjusted for freight & sales tax

Installation Labor 18,045 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 138,346 Zero out if no replacement parts needed

Annualized Cost 52,717

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 37.940902 $ 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 D P in H2O Efficiency Hp kW

Blower, Thermal 119,800 19 0.6 443.9 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Blower, Catalytic 119,800 23 0.6 537.3 EPA Cont Cost Manual 6th ed - Oxidizers Chapter 2.5.2.1

Oxidizer Type Catalytic (catalytic or thermal) 537.3

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 0 0 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 0 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 537.3 kW-hr 0 0 $/kwh, 537 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 14676 scfm 0 0 $/mscf, 14,676 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization

2 CO Catalyst 650 $/ft3 0 ft30 52,717 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 23: Selective Catalytic Reduction - Basis Power Plant Installed Cost

EPA SCR Cost Worksheet for Coal Fired Power Plants

Determine Comparable Boiler Size Based on Flue Gas Exhaust Rate

stack exhaust flow scfm 69,510

Moisture Content 10%

Stack exhaust flow dcfm 60,265

Coal F Factor dscf/MMBtu 10,000

Equivalent Duty MMBtu/hr 362

Est. Power Plant Efficiency 35%

Watt per Btu/hr 0.29307

Equivalent Power Plant kW 37,090

Uncontrolled NOx t/yr 41

Annual Operating Hours 8,000

Uncontrolled NOx lb/MMBtu 0.029

Plant Capacity kW A 37,090

Uncontrolled NOx lb/MMBtu B 0.029

NOx Reduction Efficiency C 90

Capital Cost $/kW D $150.00 Total Capital Cost $5,563,529

 D= 75*(300,000((B/1.5)^0.05*(C/100)^0.04/A)^0.35

Plant Capacity kW A 37,090

Capital Cost $/kW D $150.00

Fixed O&M Cost, $/yr E $36,719

E = D*A*0.0066

Plant Capacity kW A 37,090

Uncontrolled NOx lb/MMBtu B 0.03

NOx Reduction Efficiency C 90

Capital Cost $/kW D $150.00

Annual Capacity Factor G 0.82

Heat Input MMBtu/hr H 6000

Variable O&M Cost $/yr F $362,636

F = G*(225(0.37*B*H*C/100*8760/2000)*1.005+0.075*D*A*((B/1.5)^0.05*(c/100)^.4)+1.45*A)

Note: used worst case factor for catalyst replacement

Note: Capital Cost kW is estimate from Tom Robinson @ Babcock Power Inc.

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BART Report - Appendix A Emission Control Cost Analysis

Table 25: Selective Non-Catalytic Reduction SNCR

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 50% 0.17 1998 551,300

 Purchased Equipment (A) 2005 657,319

 Purchased Equipment Total (B) 0% of control device cost (A) 657,319

 Installation - Standard Costs 15% of purchased equip cost (B) 118,317

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 925,876

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 153,526

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655

Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181

Emission Control Cost Calculation

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

PM10 6.8 1.9 6.8 - NA

Total Particulates 1.9 6.8 6.8 - NA

Nitrous Oxides (NOx) 11.6 41.3 50% 20.6 20.6 12,126

Sulfur Dioxide (SO2) 16.8 59.8 59.8 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) 1.0 3.5 3.5 - NA

Carbon Monoxide (CO) - - 0.0 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Cost Estimate from EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 

3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 

4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

5 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

6 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29

7 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

8 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21

9 No coal ash disposal cost; fuel is natural gas

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 25: Selective Non-Catalytic Reduction SNCR

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 657,319

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) 657,319

Indirect Installation

General Facilities 5% of purchased equip cost (A) 32,866

Engineering & Home Office 10% of purchased equip cost (A) 65,732

Process Contingency 5% of purchased equip cost (A) 32,866

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 131,464

Project Contingency ( C) 15% of (A + B) 118,317

Total Plant Cost D A + B + C 907,100

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)) 18,142

Inventory Capital Reagent Vol * $/gal 634

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 925,876

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 925,876

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total 15.00 % of Total Capital Investment 138,881

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

NA NA - 

Natural Gas 2.31 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization 1,215

Water 0.40 $/mgal, 4 gph, 7650 hr/yr, 93% utilization 13

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Urea 405.00 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 13,416

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 153,526

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) 0 of total capital costs (TCI) 9,259

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 87,396

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 96,655

Total Annual Cost (Annualized Capital Cost + Operating Cost) 250,181

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 25: Selective Non-Catalytic Reduction SNCR

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 500 $/ft3

Amount Required 12 ft3

Packing Cost 6,690 Cost adjusted for freight & sales tax

Installation Labor 1,004 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: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 38 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use

NOx in 0.17 lb/MMBtu kW

NSR 1.12

Power 0.0

Total 0.0

Reagent Use & Other Operating Costs Urea Use

NOx in 0.17 lb/MMBtu 5 lb/hr Neat

Efficiency 50% 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 70 MMBtu/hr 9 lb/hr 1.0 gal/hr

Volume 14 day inventory 330 gal $634 Inventory Cost

Water Use 4 gal/hr Inject at 10% solution

Fuel Use 0.1 MMBtu/hr 0.1 mscfh natural gas

Ash Generation 0.6 lb/hr

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total 15 % of Total Capital Investment 138,881 % of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0.1 scfh 526 1,215 $/mscf, 0 scfh, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 4.5 gph 32 13 $/mgal, 4 gph, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Recycle 1.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

1 Lime 90 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

3 Urea 405 $/ton 0.0047 ton/hr 33 13,416 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.48526 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 7650 hr/yr, 93% utilization

1 SCR Catalyst 500 $/ft3 0 ft30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.940902 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 hr/yr, 93% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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NOx SNCR 9/6/2006 Page 19 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 26: SO2 Control - Wet ESP

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs (1)

 Purchased Equipment (A) 2005 5,519,073 2,687,838

 Purchased Equipment Total (B) 22% of control device cost (A) 3,265,724

 Installation - Standard Costs 69% of purchased equip cost (B) 2,253,349

 Installation - Site Specific Costs 0

 Installation Total 2,253,349

 Total Direct Capital Cost, DC 5,519,073

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462

Total Capital Investment (TCI) = DC + IC 11,808,857

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 742,986

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost (5)

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

PM10 8.3 1.5 0.021 5.3 3.0 758,310

Total Particulates 8.3 1.5 0.021 5.3 3.0 758,310

Nitrous Oxides (NOx) 50.9 - 50.9 - NA

Sulfur Dioxide (SO2) 73.4 3.4 0.048 11.9 61.5 36,558

Notes & Assumptions

1 Total Direct Capital Cost Cost Estimated, 19% as compared to dry ESP cost.

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 

3 ESP Maintenance costs Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3

4 ESP Maintenance Materials Eq 3.45 EPA Cont Cost Manual Section 6 Chapter 3

5 High control cost is due to the small additional decrease in emissions as compared to existing controls.

6 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User

1) Enter Data in Blue Highlighted Cells Throughout Worksheet 

2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell

2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H

2b) If using concentration, enter concentration data in coluND Fand units in coluND H

3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors

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SO2 WESP 9/6/2006 Page 20 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

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SO2 WESP 9/6/2006 Page 21 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 26: SO2 Control - Wet ESP

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 2,687,838

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 268,784

MN Sales Taxes 6.5% of control device cost (A) 174,709

Freight 5% of control device cost (A) 134,392

Purchased Equipment Total (B) 22% 3,265,724

Installation

Foundations & supports 4% of purchased equip cost (B) 130,629

Handling & erection 50% of purchased equip cost (B) 1,632,862

Electrical 8% of purchased equip cost (B) 261,258

Piping 3% of purchased equip cost (B) 97,972

Insulation 2% of purchased equip cost (B) 65,314

Painting 2% of purchased equip cost (B) 65,314

Installation Subtotal Standard Expenses 69% 2,253,349

Installation Total 2,253,349

Total Direct Capital Cost, DC 5,519,073

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 653,145

Construction & field expenses 20% of purchased equip cost (B) 653,145

Contractor fees 10% of purchased equip cost (B) 326,572

Start-up 1% of purchased equip cost (B) 32,657

Performance test 1% of purchased equip cost (B) 32,657

Model Studies 2% of purchased equip cost (B) 65,314

Contingencies 3% of purchased equip cost (B) 97,972

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 1,861,462

7,380,535

Retrofit TCI (TCI*1.6) (6) 11,808,857

Total Capital Investment (TCI) = DC + IC Site Preparation, as required site preparation and foundations 0

Buildings, as required structural steel 0

Site Specific - Other Replacement Power - One 14 day outage [8] 0

Total Site Specific Costs 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 11,808,857

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 47,813

Supervisor 48% % of Operator Costs. 22,950

Maintenance

Maintenance Labor (3) 66,249 ft2 grid area, 0.8 $/ft2 of grid area 54,656

Maintenance Materials (4) 1 1% of purchased equipment cost 32,657

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization 84,287

NA NA - 

Water 0.40 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization 4,091

NA NA - 

NA NA - 

NA NA - 

NA NA - 

SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Caustic 305.21 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization 246,456

NA NA - 

Lost Revenue - Fly Ash NA 250,000

NA NA - 

Total Annual Direct Operating Costs 742,986

Indirect Operating Costs

Overhead 60% of total labor and material costs 94,845

Administration (2% total capital costs) 2% of total capital costs (TCI) 147,611

Property tax (1% total capital costs) 1% of total capital costs (TCI) 73,805 1

Insurance (1% total capital costs) 1% of total capital costs (TCI) 73,805 2

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,114,673 5

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,504,739 1

1

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,247,725

See Summary page for notes and assumptions

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Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 26: SO2 Control - Wet ESP

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 500 $/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 37.94090199 $ 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 Baghouse & ESP 119,800 4.48 97.1 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.46

Liq flow Liquid SPGR ∆ P ft H2O Efficiency Hp kW

WESP Pump 120 gpm 1.000 40 0.5 1.8 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47

WESP H2O WW Disch 24 gpm 1.000 40 0.5 0.4 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.47

SCA Factor 553 ft2

/1000 acfm

ESP Grid 66,249 ft21.94E-03 kW/ft2128.5 EPA Cost Cont Manual 6th ed Section 6 Chapter 3 Eq 3.48

Total 227.8

Reagent Use & Other Operating Costs

WESP Pump 23,960 acfm 5 gpm/kacfm 120 gpm EPA Cost Cont Manual 6th ed Section 6 Chapter 3.4.1.9

WESP Water Makeup Rate/WW Disch 20% of circulating water rate = 24 gpm

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 1.0 hr/8 hr shift 956 47,813 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr

Supervisor 48% of Operator Costs. NA 22,950 % of Operator Costs.

Maintenance

Maint Labor 66,249 ft2 grid area 0.825 $/ft2 of grid area 54,656 ft2 grid area, 0.8 $/ft2 of grid area

Maint Mtls 1 % of purchased equipment cost NA 32,657 1% of purchased equipment cost

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 227.8 kW-hr 1,620,903 84,287 $/kwh, 228 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 24.0 gpm 10,228 4,091 $/mgal, 24 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 Mi 0 0 $/ton-mi, 0 Mi, 7650 hr/yr, 93% utilization

PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost

Lime 90.0 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

Caustic 305.21 $/ton 227.0 lb/hr 807 246,456 $/ton, 227 lb/hr, 7650 hr/yr, 93% utilization

Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization

SCR Catalyst 500 $/ft3 0 ft3

0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 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

Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.

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SO2 WESP 9/6/2006 Page 24 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 27: SO2 Absorber

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs (1) 2002 [1] 1,908,056

 Purchased Equipment (A) 2005 2,274,990 1,012,119

 Purchased Equipment Total (B) 22% of control device cost (A) 1,229,724

 Installation - Standard Costs 85% of purchased equip cost (B) 1,045,266

 Installation - Site Specific Costs 0

 Installation Total 1,045,266

 Total Direct Capital Cost, DC 2,274,990

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459

Total Capital Investment (TCI) = DC + IC 3,935,118

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 598,134

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

PM10 8.3 - 8.3 - NA

Total Particulates 8.3 - 8.3 - NA

Nitrous Oxides (NOx) 50.9 - 50.9 - NA

Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 18,198

Notes & Assumptions

1 Original estimate was from Durr. Use 0.6 Powerlaw 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.

Notes to User

1) Enter Data in Blue Highlighted Cells Throughout Worksheet 

2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell

2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H

2b) If using concentration, enter concentration data in coluND Fand units in coluND H

3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors

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SO2 Absorber 9/6/2006 Page 25 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

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SO2 Absorber 9/6/2006 Page 26 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 27: SO2 Absorber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 1,012,119

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 101,212

MN Sales Taxes 6.5% of control device cost (A) 65,788

Freight 5% of control device cost (A) 50,606

Purchased Equipment Total (B) 22% 1,229,724

Installation

Foundations & supports 12% of purchased equip cost (B) 147,567

Handling & erection 40% of purchased equip cost (B) 491,890

Electrical 1% of purchased equip cost (B) 12,297

Piping 30% of purchased equip cost (B) 368,917

Insulation 1% of purchased equip cost (B) 12,297

Painting 1% of purchased equip cost (B) 12,297

Installation Subtotal Standard Expenses 85% 1,045,266

Installation Total 1,045,266

Total Direct Capital Cost, DC 2,274,990

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 61,486

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 61,486

Start-up 1% of purchased equip cost (B) 12,297

Performance test 1% of purchased equip cost (B) 12,297

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 36,892

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 184,459

Total Capital Investment (TCI) = DC + IC 2,459,448

Retrofit TCI (TCI*1.6) (5) 3,935,118

Site Preparation, as required site preparation and foundations 0

Buildings, as required structural steel 0

Site Specific - Other Replacement Power - One 14 day outage [8] 0

Total Site Specific Costs 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,935,118

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 23,906

Supervisor 15% 15% of Operator Costs 3,586

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr 28,688

Maintenance Materials 100% of maintenance labor costs 28,688

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization 91,145

NA NA - 

Water 0.40 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization 19,194

NA NA - 

NA NA - 

WW Treat Neutralization 3.80 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization 147,690

NA NA - 

SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77

NA NA - 

NA NA - 

NA NA - 

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161

NA NA - 

NA NA - 

Lost Revenue - Fly Ash NA 250,000

NA NA - 

Total Annual Direct Operating Costs 598,134

Indirect Operating Costs

Overhead 60% of total labor and material costs 50,920

Administration (2% total capital costs) 2% of total capital costs (TCI) 49,189

Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,594 1

Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,594 2

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 371,447 5

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 520,746 1

1

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,118,879

See Summary page for notes and assumptions

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SO2 Absorber 9/6/2006 Page 27 of 42
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SO2 Absorber 9/6/2006 Page 28 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 27: SO2 Absorber

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 500 $/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 37.94 $ 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 119,800 8.55 0.7 - 171.2 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 4,552 gpm 1 60 0.7 - 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 112 gpm 1 60 0.7 - 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 246.4

Reagent Use & Other Operating Costs

Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 41.88 lb/hr Caustic

Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Liquid/Gas ratio (2) 38.0 * L/G = Gal/1,000 acf

Circulating Water Rate 4,552 gpm

Water Makeup Rate/WW Disch = (3) 2.0% of circulating water rate + evap. loss = 112 gpm

Evaopration Loss = (4) 21.36 gpm

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.05

NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 3,586

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 112.4 gpm 47,984 19,194 $/mgal, 112 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 0 kscfm 0 0 $/mscf, 0 kscfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 91.0 gpm 38,866 147,690 $/mgal, 91 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost

Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization

Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization

SCR Catalyst 500 $/ft3 0 ft30 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

Filter Bags 37.94 $/bag 0 bags 0 0 $/bag, 0 bags, 7650 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

Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.

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SO2 Absorber 9/6/2006 Page 29 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 28: SO2 Control - Spray Dryer and Baghouse

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs (1) 2002 [1] 7,786,400

 Purchased Equipment (A) 2005 9,283,785 4,391,365

 Purchased Equipment Total (B) 22% of control device cost (A) 5,335,508

 Installation - Standard Costs 74% of purchased equip cost (B) 3,948,276

 Installation - Site Specific Costs 0

 Installation Total 3,948,276

 Total Direct Capital Cost, DC 9,283,785

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326

Total Capital Investment (TCI) = DC + IC (5) 16,134,577

Operating Costs (2)

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

PM10 8.3 - 8.3 - NA

Total Particulates 8.3 - 8.3 - NA

Nitrous Oxides (NOx) 50.9 - 50.9 - NA

Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 44,804

Notes & Assumptions

1 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8

4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.

5 Bag replacement costs for baghouse need to be updated. Bag costs from EPA example calculations were used. 

6 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing baghouse could not handle additional loading.

7 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User

1) Enter Data in Blue Highlighted Cells Throughout Worksheet 

2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell

2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H

2b) If using concentration, enter concentration data in coluND Fand units in coluND H

3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors

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Spray Dry Baghouse 9/6/2006 Page 30 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

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Spray Dry Baghouse 9/6/2006 Page 31 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 28: SO2 Control - Spray Dryer and Baghouse

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 4,391,365

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 439,136

MN Sales Taxes 6.5% of control device cost (A) 285,439

Freight 5% of control device cost (A) 219,568

Purchased Equipment Total (B) 22% 5,335,508

Installation

Foundations & supports 4% of purchased equip cost (B) 213,420

Handling & erection 50% of purchased equip cost (B) 2,667,754

Electrical 8% of purchased equip cost (B) 426,841

Piping 1% of purchased equip cost (B) 53,355

Insulation 7% of purchased equip cost (B) 373,486

Painting 4% of purchased equip cost (B) 213,420

Installation Subtotal Standard Expenses 74% 3,948,276

Installation Total 3,948,276

Total Direct Capital Cost, DC 9,283,785

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 266,775

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 266,775

Start-up 1% of purchased equip cost (B) 53,355

Performance test 1% of purchased equip cost (B) 53,355

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 160,065

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 800,326

Total Capital Investment (TCI) = DC + IC 10,084,111

Retrofit TCI (TCI*1.6) (7) 16,134,577

Site Preparation, as required site preparation and foundations 0

Buildings, as required structural steel 0

Site Specific - Other Replacement Power - One 14 day outage [8] 0

Total Site Specific Costs 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 16,134,577

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625

Supervisor 15% 15% of Operator Costs 14,344

Maintenance

Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375

Maintenance Materials 100% of maintenance labor costs 57,375

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220

NA NA - 

Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000

NA NA - 

Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391

NA NA - 

NA NA - 

SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77

NA NA - 

NA NA - 

NA NA - 

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161

NA NA - 

Lost Revenue - Fly Ash NA 250,000

NA NA - 

Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951

Total Annual Direct Operating Costs 693,518

Indirect Operating Costs

Overhead 60% of total labor and material costs 134,831

Administration (2% total capital costs) 2% of total capital costs (TCI) 201,682

Property tax (1% total capital costs) 1% of total capital costs (TCI) 100,841

Insurance (1% total capital costs) 1% of total capital costs (TCI) 100,841

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,522,990

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,061,186

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,754,704

See Summary page for notes and assumptions

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Spray Dry Baghouse 9/6/2006 Page 32 of 42
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Spray Dry Baghouse 9/6/2006 Page 33 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 28: SO2 Control - Spray Dryer and Baghouse

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalsyt:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 500 $/ft3

Amount Required 0 ft3

Total Rep Parts 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: Filter bags & cages (4)

Equipment Life 4 years

CRF 0.2952

Rep part cost per unit 38 $/bag

Amount Required 4410

Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax

Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4

Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.

Annualized Cost 76,951

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Baghouse 119,800 10 216.8

Baghouse Shaker 0.0 Gross fabric area ft20 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14

Other 

Other 

Other 

Other 

Other 

Total 216.8

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Gross BH Filter Area 0 ft2

Cages 0 ft long 0 in dia 0.00 area/cage ft20.000 $/cage

Bags 0 $/ft2 of fabric 0.00 $/bag

H2O Use (1) 140.56 gpm 0.000 Total

Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.05

NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 14,344

Maintenance

Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

(3) Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost

1 Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization

2 Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

5 Oxygen 1.48526 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization

1 SCR Catalyst 500 $/ft3 0 ft3

0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

1 Filter Bags 37.940902 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 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

Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

Spray Dry Baghouse 9/6/2006 Page 34 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003 Chemical Engineering

Design Capacity 70 MMBtu/hr Standardized Flow Rate 64,771 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 93% Temperature 450 Deg F 1998/1999 390

Expected Annual Hours of Operation 7,650 Hours Moisture Content 13.3% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs (1) 1997 2,359,900

 Purchased Equipment (A) 2005 [6] 2,813,727 1,330,934

 Purchased Equipment Total (B) 22% of control device cost (A) 1,617,084

 Installation - Standard Costs 74% of purchased equip cost (B) 1,196,642

 Installation - Site Specific Costs 0

 Installation Total 1,196,642

 Total Direct Capital Cost, DC 2,813,727

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563

Total Capital Investment (TCI) = DC + IC (5) 4,890,063

Operating Costs (2)

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 693,518

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

PM10 8.3 - 8.3 - NA

Total Particulates 8.3 - 8.3 - NA

Nitrous Oxides (NOx) 50.9 - 50.9 - NA

Sulfur Dioxide (SO2) 73.4 3.4 0.05 11.9 61.5 22,969

Notes & Assumptions

1 Total Direct Capital Cost Cost Estimated using the Integrated Air Pollution Control Sytem Program Version 5a, EPA May 1999

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8

4 Bag replacement at 10 min/bag EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.

5 Dry scrubbing SO2 costs include addition of a baghouse. Assumed that the existing Ebaghouse could not handle additional loading.

6 Stone and Webster 2002 total direct installed cost estimate adjusted for inflation adjusted for costs already included

7 CUECost Workbook Version 1.0, USEPA Document Page 2.

Notes to User

1) Enter Data in Blue Highlighted Cells Throughout Worksheet 

2) Control cost basis calculated by % control efficiency or concentration. Enter valued in appropriate yellow highlighted cell

2a) If using % control efficiency, enter data only in coluND F, do not enter concentration units in coluND H

2b) If using concentration, enter concentration data in coluND Fand units in coluND H

3) If not data entered in colums F and G; control cost will show NA. This was done to prevent divide by zero errors

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\NMC\NMC Furnace-Process Boiler\Appendices\Appendix A - NMC Process Boiler Control Cost.xls

DSI Baghouse 9/6/2006 Page 35 of 42
4) See comments in cell V88 regarding selection of reagents, catalysts and supplies

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DSI Baghouse 9/6/2006 Page 36 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 1,330,934

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 

Instrumentation 10% of control device cost (A) 133,093

MN Sales Taxes 6.5% of control device cost (A) 86,511

Freight 5% of control device cost (A) 66,547

Purchased Equipment Total (B) 22% 1,617,084

Installation

Foundations & supports 4% of purchased equip cost (B) 64,683

Handling & erection 50% of purchased equip cost (B) 808,542

Electrical 8% of purchased equip cost (B) 129,367

Piping 1% of purchased equip cost (B) 16,171

Insulation 7% of purchased equip cost (B) 113,196

Painting 4% of purchased equip cost (B) 64,683

Installation Subtotal Standard Expenses 74% 1,196,642

Installation Total 1,196,642

Total Direct Capital Cost, DC (6) 2,813,727

Indirect Capital Costs

Engineering, supervision [6] 5% of purchased equip cost (B) 80,854

Construction & field expenses [6] 0% of purchased equip cost (B) 0

Contractor fees [6] 5% of purchased equip cost (B) 80,854

Start-up 1% of purchased equip cost (B) 16,171

Performance test 1% of purchased equip cost (B) 16,171

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 48,513

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 242,563

Total Capital Investment (TCI) = DC + IC 3,056,290

Retrofit TCI (TCI*1.6) (7) 4,890,063

Site Preparation, as required site preparation and foundations 0

Buildings, as required structural steel 0

Site Specific - Other Replacement Power - One 14 day outage [8] 0

Total Site Specific Costs 0

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 4,890,063

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 50.00 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr 95,625

Supervisor 15% 15% of Operator Costs 14,344

Maintenance

Maintenance Labor 60.00 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr 57,375

Maintenance Materials 100% of maintenance labor costs 57,375

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization 80,220

NA NA - 

Water 0.40 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization 24,000

NA NA - 

Comp Air 0.32 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization 32,391

NA NA - 

NA NA - 

SW Disposal 11.48 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization 77

NA NA - 

NA NA - 

NA NA - 

Lime 90.00 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization 5,161 (3)

NA NA - 

Lost Revenue - Fly Ash NA 250,000

NA NA - 

Filter Bags 37.94 $/bag, 0 bags, 7650 hr/yr, 93% utilization 76,951

Total Annual Direct Operating Costs 693,518

Indirect Operating Costs 1

Overhead 60% of total labor and material costs 134,831 2

Administration (2% total capital costs) 2% of total capital costs (TCI) 61,126 5

Property tax (1% total capital costs) 1% of total capital costs (TCI) 30,563 1

Insurance (1% total capital costs) 1% of total capital costs (TCI) 30,563 1

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 461,587

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 718,670

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,412,189

See Summary page for notes and assumptions

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DSI Baghouse 9/6/2006 Page 37 of 42
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DSI Baghouse 9/6/2006 Page 38 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 29: SO2 Control - Dry Sorbent Injection and Baghouse

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalsyt:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 500 $/ft3

Amount Required 0 ft3

Total Rep Parts 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: Filter bags & cages (4)

Equipment Life 4 years

CRF 0.2952

Rep part cost per unit 38 $/bag

Amount Required 4410

Total Rep Parts Cost 186,561 Cost adjusted for freight & sales tax

Installation Labor 74,088 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cost Cont Manual 6th ed Section 6 Chapter 1.5.1.4

Total Installed Cost 260,649 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.

Annualized Cost 76,951

Electrical Use

Flow acfm ∆ P in H2O Efficiency Hp kW

Blower, Baghouse 119,800 10 216.8

Baghouse Shaker 0.0 Gross fabric area ft20 EPA Cost Cont Manual 6th ed Section 6 Chapter 1 Eq 1.14

Other 

Other 

Other 

Other 

Other 

Total 216.8

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Gross BH Filter Area 0 ft2

Cages 0 ft long 5 in dia 0.00 area/cage ft20.000 $/cage

Bags 0 $/ft2 of fabric 0.00 $/bag

H2O Use (6) 140.56 gpm 0.000 Total

Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio 

Pollutant BART Baseline Emissions Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.05

NOx 50.90 0.166071429 11.625

SO2 73.40 0.239285714 16.75

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 2.0 hr/8 hr shift 1,913 95,625 $/Hr, 2.0 hr/8 hr shift, 7650 hr/yr

Supervisor 15% of Op. NA 14,344 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 1.0 hr/8 hr shift 956 57,375 $/Hr, 1.0 hr/8 hr shift, 7650 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 57,375 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 216.8 kW-hr 1,542,694 80,220 $/kwh, 217 kW-hr, 7650 hr/yr, 93% utilization

Natural Gas 2.31 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 7650 hr/yr, 93% utilization

Water 0.40 $/mgal 140.6 gpm 60,000 24,000 $/mgal, 141 gpm, 7650 hr/yr, 93% utilization

Cooling Water 0.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

Comp Air 0.32 $/mscf 2 scfm/kacfm 102,278 32,391 $/mscf, 2 scfm/kacfm, 7650 hr/yr, 93% utilization

WW Treat Neutralization 3.80 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

WW Treat Biotreatement 4.28 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 7650 hr/yr, 93% utilization

SW Disposal 11.48 $/ton 0.0 ton/hr 7 77 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Haz W Disp 281 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 7650 hr/yr, 93% utilization

Waste Transport 0.56 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 7650 hr/yr, 93% utilization

PRB Coal 1 $/ton 0.0 ton/hr 0 0 $/ton, $5.1MM/yr extra for PRB - $1MM/yr Lower O&M Cost

Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, 7650 hr/yr, 93% utilization

Caustic 305.21 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 7650 hr/yr, 93% utilization

Oxygen 1.49 Mscf 0.0 kscf/hr 0 0 Mscf, 0 kscf/hr, 7650 hr/yr, 93% utilization

SCR Catalyst 500 $/ft3 0 ft3

0 0 $/ft3, 0 ft3, 7650 hr/yr, 93% utilization

Filter Bags 37.94 $/bag 0 bags NA 76,951 $/bag, 0 bags, 7650 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

Note: Select reagent, catayst and repacement parts by entering number in coluND U. Unhide Col U to enter choice.

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DSI Baghouse 9/6/2006 Page 39 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 30: SOx Control - Wet Scrubber

Operating Unit: Process Boiler 1 & 2

Emission Unit Number 003 & 004 Stack/Vent Number 003

Standardized Flow Rate 64,771 scfm @ 32o F

Expected Utilization Rate 93% Temperature 450 Deg F

Expected Annual Hours of Operation 7,650 0 Moisture Content 13% 0

Annual Interest Rate 7.0% Actual Flow Rate 119,800 acfm

Expected Equipment Life 20 0 Standardized Flow Rate 69,510 scfm @ 68o F

Dry Std Flow Rate 60,265 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 1,908,056

 Purchased Equipment Total (B) 22% of control device cost (A) 2,318,288

 Installation - Standard Costs 85% of purchased equip cost (B) 1,970,545

 Installation - Site Specific Costs 6,200,000

 Installation Total 1,970,545

 Total Direct Capital Cost, DC 4,288,833

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743

Total Capital Investment (TCI) = DC + IC 13,618,522

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 348,057

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933

Actual

Emission Control Cost Calculation Emis Emissions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 11.6 50.9 0% 50.9 - NA

Sulfur Dioxide (SO2) 73.4 16.8 80% 14.7 58.7 31,845

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.

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 Wet Scrubber 9/6/2006 Page 40 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 30: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,908,056

Instrumentation 10% of control device cost (A) 190,806

MN Sales Taxes 6.5% of control device cost (A) 124,024

Freight 5% of control device cost (A) 95,403

Purchased Equipment Total (B) 22% 2,318,288

Installation

Foundations & supports 12% of purchased equip cost (B) 278,195

Handling & erection 40% of purchased equip cost (B) 927,315

Electrical 1% of purchased equip cost (B) 23,183

Piping 30% of purchased equip cost (B) 695,486

Insulation 1% of purchased equip cost (B) 23,183

Painting 1% of purchased equip cost (B) 23,183

Installation Subtotal Standard Expenses 85% 1,970,545

Total Direct Capital Cost, DC 4,288,833

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 115,914

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 115,914

Start-up 1% of purchased equip cost (B) 23,183

Performance test 1% of purchased equip cost (B) 23,183

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 69,549

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 347,743

Total Capital Investment (TCI) = DC + IC 4,636,576

Retrofit multiplier560% of TCI 2,781,946

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 13,618,522

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 23,906

Supervisor 15% 15% of Operator Costs 3,586

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 28,688

Maintenance Materials 100% of maintenance labor costs 28,688

Utilities, Supplies, Replacements & Waste Management

Electricity 0.05 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization 91,145

Water 0.40 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization 19,194

WW Treat Neutralization 3.80 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization 147,690

Lime 90.00 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization 5,161

Total Annual Direct Operating Costs 348,057

Indirect Operating Costs

Overhead 60% of total labor and material costs 50,920

Administration (2% total capital costs) 2% of total capital costs (TCI) 92,732

Property tax (1% total capital costs) 1% of total capital costs (TCI) 46,366

Insurance (1% total capital costs) 1% of total capital costs (TCI) 46,366

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,285,492

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,521,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,869,933

See Summary page for notes and assumptions

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 Wet Scrubber 9/6/2006 Page 41 of 42
Northshore Process Boiler

BART Report - Appendix A Emission Control Cost Analysis

Table 30: SOx 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 119,800 8.55 0.7 - 171.2 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 4,552 gpm 1 60 0.7 - 73.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 112 gpm 1 60 0.7 - 1.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 246.4

Reagent Use & Other Operating Costs

Caustic Use 16.75 lb/hr SO2 2.50 lb NaOH/lb SO2 41.88 lb/hr Caustic

Lime Use 16.75 lb/hr SO2 0.96 lb Lime/lb SO2 16.12 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

4,552 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 112 gpm

Evaopration Loss4 = 21.36 gpm

Operating Cost Calculations Annual hours of operation: 7,650

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 50.00 $/Hr 0.5 hr/8 hr shift 478 23,906 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Supervisor 15% of Op. NA 15% of Operator Costs 3,586

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 478 28,688 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours, 

Maint Mtls 100 % of Maintenance Labor NA 28,688 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.052 $/kwh 246.4 kW-hr 1,752,797 91,145 $/kwh, 246 kW-hr, Annual Operating Hours, 93% utilization

Water 0.40 $/kgal 112.4 gpm 47,984 19,194 $/kgal, 112 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 3.80 $/kgal 91.0 gpm 38,866 147,690 $/kgal, 91 gpm, Annual Operating Hours, 93% utilization

Lime 90.0 $/ton 16.1 lb/hr 57 5,161 $/ton, 16 lb/hr, Annual Operating Hours, 93% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions

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 Wet Scrubber 9/6/2006 Page 42 of 42
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

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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 Northshore Mining Company (NMC) 

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 Technology (BART) Modeling Protocol to Determine Sources 

Subject-to-Bart in the State of Minnesota. 

4

 40 CFR 51, Appendix Y. 

5

 MPCA, March 2006, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources 

Subject-to-Bart in the State of Minnesota. 
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. There were no post-BART scenarios to be modeled. 

Table 4-1 describes the pre-BART model input parameters. There were no post-BART scenarios to be 

modeled. 

Modeled Results 

Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for 

the pre-BART emission scenario. 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 4-2. 
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100 0

Meters

Northshore Aerial Photo
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconidistributed without the full text not 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? Comments Bas

Combustion Controls

1 Overfire Air (OFA) Y N --- --- NOx formation front is not stationary in an indurating furnace Combustion air is separated into 

achieve complete burnout and to 

than NOx

2 External Flue Gas Recirculation (EFGR) Y Y N --- Mixes flue gas with combustion a

therefore reduces flame tempera

3 Low-NOx Burners Y Y

Y 

(preheat 

burners)

Y 

(preheat 

burners)

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 --- Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel i5 Low Excess Air Y N --- --- Need high O2 for process requirements and product quality Reduces oxygen content in flue g

6 Burners out of Service (BOOS) Y N --- --- Need capacity of all burners for worst case scenario Shut off the fuel flow from one bu

lean zones

7 Fuel Biasing Y N --- --- Power plant technology

Combustion is staged by diverting lower ones or from the center to tfuel-lean zones 

8 Reburning Y N --- --- Kiln configuration not correct for this technology.

Part of the total fuel heat input is 

above the primary (main burners) (re-burn zone), where hydrocarboelemental nitrogen

9 Load Reduction N --- --- --- Power plant technology -product demand side solution This is a strategy to reduce load o

electrical demand throught efficie

10 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

decrease amount of fuel required 

11 Coal Drying Y N --- --- 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 --- --- --- Check on status of research Reduce flame temperature and e
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconidistributed without the full text not 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? Comments Bas

13 Ported Kilns Y Y

Y

(grate-kilns 

only)

N

(Metso says 

no NOx 

improvement)

Applicable to grate kilns. Provides additional oxygen for pe

energy use of the kiln 

14 Combustion Zone Cooling Y N --- --- 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)

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with soNOx by using a fuel with less nitro

16 Oxygen Enhanced Combustion N --- --- --- Research level A small fraction of the combustio

17 Preheat Combustion N --- --- --- Research level

Pulverized coal preheated and vocompounds are released in a connitrogen compounds are reduced 

18 ROFA-ROTAMIX Y N --- --- Can't achieve correct temperature window (1400-1800F). Too hot in kiln 

too cold in reheat

Combination of OFA and SCR. Wutilizes high velocity overfire air. Awith ammonia injection (Rotamix)

19 NOx CEMS Y N --- --- Optimization of combustion20 Parametric Monitoring Y N --- --- Optimization of combustion38 Catalyst Injection (EPS Technologies) N --- --- --- Research Level A combustion catalyst is directly i

delivered to the combustion site, the dynamics of the flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Y N --- --- For clean services. Too much stuff in flue gas would poison catalyst Under near stoichiometric conditi

reduced by CO, resulting in nitrog

22 Low Temperature Oxidation (LTO) - Tri-NOx® Y N --- --- Used for higher flue gas concentrations Utilizes an oxidizing agent such a

including NOx
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconidistributed without the full text not 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? Comments Bas

23 Low Temperature Oxidation (LTO) - LoTOx Y N --- --- 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

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 th

catalyst to convert NOx into N2 an

25 Regenerative SCR Y N --- --- Clean side only26 Selective Non-Catalytic Reduction (SNCR) Y N --- --- Can't achieve correct temperature window (1400-1800F). Too hot in kiln too cold in reheat Urea or ammonia-based chemica

convert NO to molecular nitrogen

27 Adsorption N --- --- --- Still in research stages. Use of char (activated carbon) to 

28 Absorption Y N --- --- Similar to TriNOx

Use of water, hydroxide and carbsolutions, molten alkali carbonatenitrogen.

29 Oxidizer Y N --- --- Redundant to regenerative SCR

Gas stream is sent through the re

direct fired oxidizer where pollutadestroyed.

30 SNOX N --- --- --- Early commercial development stage

Catalytic reduction of NOx in the 

catalytic oxidation of SO2 to SO3. 

passes through a novel glass-tub

hydrated to H2SO4 vapor and the

sulfuric acid (H2SO4).

31 SOx-NOx-Rox-Box N --- --- --- Technology has not been demonstrated Dry sorbent injection upstream of 

ammonia injection upstream of a (SCR) catalyst incorporated in the 
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconidistributed without the full text not 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? Comments Bas

32 Electron (E-Beam) Process N --- --- --- No operating commercial applications on coal Electron beam irradiation in the p

conversion of sulfur and nitrogen easily collected by conventional m

33 Electrocatalytic Oxidation N --- --- --- Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, N

dioxide (NO2), sulfuric acid, and m

thermal plasma.On recent project, the vender waapplications.

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 --- --- --- Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with co

of alumina, to form copper sulfatebefore the absorption reactor and reaction occurs that reduces the regeneration step, the copper sulreducing agent, such as natural gSO2.

36 Cold Plasma N --- --- --- Research Level

37 Biofilters Y N --- --- Not applicable to furnaces.

Gas stream is passed through a fPollutants are adsorbed and degthe products carbon dioxide and w

38 Pahlman Process N --- --- --- Research Level

Gas stream is passed through a fdeveloped, 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.htm
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconidistributed without the full text not 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? Comments Bas

2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Taconite BART Analysis

SO2 Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconite distributed without the full text of not 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?

Comments Basi

1 Wet Scrubbing (High Efficiency) Y Y Y Y Absorption and reaction using an alkali

2 Wet Scrubbing (Low Efficiency) Y Y Y Y Absorption and reaction using an alkali

3 Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y Suspended particles are separated from 

collected in hoppers

4 Dry sorbent injection Y Y Y N

Pulverized lime or limestone is directly filter. Dry sorption of SO2 onto the lime 

particles are collected with a fabric filte

5 Spray Dryer Absorption (SDA) Y Y Y N Lime slurry is sprayed into an absorptio

slurry, forming CaSO3/CaSO4

6 Alternative Fuels Y Y

Y

(for furnaces 

capable of 

multiple fuels)

Y

(not required 

by BART)

Natural gas is base case Use a fuel with lower sulfur content.

7 Load Reduction N --- --- --- Power plant technology This is a strategy to reduce load on a po

throught efficiency projects.

8 Energy Efficiency Projects Y Y

Y 

(for large 

projects like 

heat-recoup)

Y 

(for large 

projects like 

heat-recoup)

decrease amount of fuel required to ma

9 Coal Drying Y N --- --- Applies only to facilities that burn coal Dry coal will increase the as-burned BT

to be burned. Specific energy efficienc

10 Bio Filters N --- --- --- Research level

Gas stream passes through a packed besupports the growth of active bacterial biodegraded or biotransformed into innwater, chloride ion in water, sulfate or n

11 CANSOLV Regenerable SO2 N --- --- --- Research level

An aqueous solution of proprietary diam

countercurrent absorption tower. The rigiving a byproduct of pure, water satur

to the absorber.

12 Pahlman Process N --- --- --- Research level

Gas stream is passed through a filter baparticle, high-surface area metal oxide removed from the gases by adsorption.
Taconite BART Analysis

SO2 Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconite distributed without the full text of not 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?

Comments Basi

13 SOx-NOx-Rox-Box N --- --- --- Technology has not been demonstrated

Dry sorbent injection upstream of the binjection upstream of a zeolitic selectivincorporated in the baghouse to reduce 

14 Electron (E-Beam) Process N --- --- --- No operating commercial applications on coal Electron beam irradiation in the presen

conversion of sulfur and nitrogen oxidecollected by conventional methods such 

15 Electrocatalytic Oxidation N --- --- --- Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NOx, a

(NO2), sulfuric acid, and mercuric oxid

On recent project, the vender was doing 

16 NOXSO N --- --- --- Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simultane

from coal-fired utility and industrial bo

a saleable sulfur by-product (liquid SO

NOx is converted to nitrogen and oxyg

17 Copper-Oxide N --- --- --- Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copper o

alumina, to form copper sulfate. Ammoabsorption reactor and a selective catalreduces the nitric oxides in the flue gasis reduced in a regenerator with a reducconcentrated stream of SO2.

18 SNOX N --- --- --- Early commercial development stage

Catalytic reduction of NOx in the prese

catalytic oxidation of SO2 to SO3. The 

through a novel glass-tube condenser in 

and then condensed to a concentrated l

19 Cold Plasma N --- --- --- Research level

1) This number is for reference only. It does not in any way rank the control technologies.2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm2) c) New and Emerging Environmental Technologies, http://neet.rti.org/2) d) ND BART Reports
Appendix E Clean Air Interstate Rule (CAIR)

Cost-Effective air pollution Controls

Comments

Reference Regulatory Body/Rule SO2 NOx SO2 NOx

BART 100 to 1000 100 to 1000 70 FR 39135BART 281 to 1296 70 FR 39135 Table BART 919 70 FR 39133BART Guidelines dispara

dollars per ton" in cexceed MACT and 

70_FR_25210_CAIR.pdf CAIR 1300 Estimated Margina

BART(proposed rule) 200-1000

BART proposed lisSO2 control, which lb/MMBtu. Droppeflexibility to require bypasses aren't BABART.

BART(proposed rule)

0.2 lb/MMBtu for NRecognizes that soget this level. For tcost vs. visibility va

CAIR(using IPM) 1000 1500CAIR ( 2009 in 1999$) 900 2400

CAIR ( 2015 in 1999$) 1800 3000CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100

This was modeled Retrofitting Updatinmarginal values.

Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000

LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000

954-1134 was rulefor SO2. This did cSections XVII to XI

WRAP 3000EPA - Referenced by Wrap

References EPA-6<$500/ton, Moderaover $3000/ton

WRAP_Trading_program_methodology.pdf

Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)

MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdf

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xls
Northshore Process Boilers BART Analysis

NOx Control

Available and Applicable Review

Reference(s) 

Reference No.

1

NOx Pollution Control 

Technology Available? Applicable?

MPCA Taconite 

BART Report

AWMA Journal 

9/05

Other

2

Comments Basic Principle

Combustion Controls

1 Overfire Air (OFA) Yes Yes x x Combustion air is separated into primary and secon

complete burnout and to encourage the formation o

2 External Flue Gas Recirculation (EFGR) Yes Yes x x Mixes flue gas with combustion air which reduces o

reduces flame temperature

3 Low-NOx Burners Yes Yes x x x Burners are designed to reduce NOx formation thro

flame temperature, and/or residence time

4 Induced Flue Gas Recirculation Burners Yes Yes x x x Need to be upfired. Need convective loop to get gas recirculated Draws flue gas to dilute the fuel in order to reduce t

5 Low Excess Air Yes Yes x Reduces production Reduces oxygen content in flue gas and reduces fla

6 Burners out of Service (BOOS) Yes No x Need capacity of all burners for worst case scenario Shut off the fuel flow from one burner or more to cr

zones

7 Fuel Biasing Yes No x Combustion is staged by diverting fuel from the upp

ones or from the center to the side burners to create 

8 Reburning Yes Yes x x

Part of the total fuel heat input is injected into the fprimary (main burners) flames to create a reducing where hydrocarbon radicals react with NOx to prod

9 Load Reduction Yes Yes x This is a strategy to reduce load on a power plant by 

demand throught efficiency projects.

10 Energy Efficiency Projects Yes Yes x decrease amount of fuel required to make an accept

11 Coal Drying Yes Yes x Requires available excess heat. Dry coal will increase the as-burned BTU value, an

to be burned. Specific energy efficiency project

14 Combustion Zone Cooling Yes Yes x x Could reduce load capabilities Cooling of the primary flame zone by heat transfer 

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 
Reference(s) 

Reference No.

1

NOx Pollution Control 

Technology Available? Applicable?

MPCA Taconite 

BART Report

AWMA Journal 

9/05

Other

2

Comments Basic Principle

15 Alternate Fuels Yes Yes x x

Requires case by case analysis. Typically, facilities experience lower NOx when burning solid fuels.

Lower combustion temps with solid fuels vs gas. Musing a fuel with less nitrogen.

16 Oxygen Enhanced Combustion No No x x Research level A small fraction of the combustion air is replaced w17 Preheat Combustion No No x x Research level

Pulverized coal preheated and volatiles and fuel-boureleased in a controlled reducing atmosphere where reduced to N2.

18 ROFA-ROTAMIX Yes Yes x x

Combination of OFA and SCR. Wall-fired or tangeutilizes high velocity overfire air. Additional NOx rammonia injection (Rotamix)

19 NOx CEMS Yes Yes x Optimization of combustion20 Parametric Monitoring Yes Yes x Optimization of combustion38 Catalyst Injection (EPS Technologies) No No x Research Level A combustion catalyst is directly injected into the a

to the combustion site, initiating chemical reactions the flame.

Post Combustion Controls

21 Non-Selective Catalytic Reduction (NSCR) Yes No x x For clean services. Too much stuff in flue gas would poison catalyst Under near stoichiometric conditions, in the presen

reduced by CO, resulting in nitrogen (N2) and carbo

22 Low Temperature Oxidation (LTO) - Tri-NOx® Yes Yes x x Requires ozone generation Utilizes an oxidizing agent such as ozone to oxidize 

NOx

23 Low Temperature Oxidation (LTO) - LoTOx Yes Yes x x x

Has been included as an "applicable and available" 

technology in recent BACT analyses from multiple facilities.

Utilizes an oxidizing agent such as ozone to oxidize NOx

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 
Reference(s) 

Reference No.

1

NOx Pollution Control 

Technology Available? Applicable?

MPCA Taconite 

BART Report

AWMA Journal 

9/05

Other

2

Comments Basic Principle

24 Selective Catalytic Reduction (SCR) Yes Yes x x x

Need to inject at appropriate temperature. Applicable on clean side only.

Ammonia (NH3) is injected into the flue gas stream 

to convert NOx into N2 and water

25 Regenerative SCR Yes Yes x Clean side only

26 Selective Non-Catalytic Reduction (SNCR) Yes Yes x x x Urea or ammonia-based chemicals are injected into 

NO to molecular nitrogen, N2, and water

27 Adsorption No No x Still in research stages. Use of char (activated carbon) to adsorb oxides of n28 Absorption Yes Yes x Similar to TriNOx Use of water, hydroxide and carbonate solutions, su

molten alkali carbonates, or hydroxides to absorb o

29 Oxidizer Yes Yes x Redundant to regenerative SCR Gas stream is sent through the regenerative, recuper

oxidizer where pollutants are heated to a combustio

30 SNOX No No x x Early commercial development stage

Catalytic reduction of NOx in the presence of amm

catalytic oxidation of SO2 to SO3. The exit gas from 

through a novel glass-tube condenser in which the S

vapor and then condensed to a concentrated liquid s

31 SOx-NOx-Rox-Box No No x Technology has not been demonstrated Dry sorbent injection upstream of the baghouse for 

injection upstream of a zeolitic selective catalytic reincorporated in the baghouse to reduce NOx emissi

32 Electron (E-Beam) Process No No x x No operating commercial applications on coal Electron beam irradiation in the presence of ammon

conversion of sulfur and nitrogen oxides into compcollected by conventional methods such as an ESP 

33 Electrocatalytic Oxidation No No x

Similar to cold plasma. Will keep watch for availability of this technology

Utilizes a reactor in which SO2, NOx, and mercury 

dioxide (NO2), sulfuric acid, and mercuric oxide res

plasma.On recent project, the vender was doing final trials 

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 
Reference(s) 

Reference No.

1

NOx Pollution Control 

Technology Available? Applicable?

MPCA Taconite 

BART Report

AWMA Journal 

9/05

Other

2

Comments Basic Principle

34 NOXSO No No x

Commercial version of adsorption. Limited experience (proof-ofconcept tests).

Uses a regenerable sorbent to simultaneously adsorb 

from coal-fired utility and industrial boilers. In the p

to a saleable sulfur by-product (liquid SO2, element

the NOx is converted to nitrogen and oxygen.

35 Copper-Oxide No No x x

Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copper oxide, suppo

alumina, to form copper sulfate. Ammonia is injecteabsorption reactor and a selective catalytic reductioreduces the nitric oxides in the flue gas. In the regensulfate is reduced in a regenerator with a reducing aproducing a concentrated stream of SO2.

36 Cold Plasma No No x Research Level37 Biofilters Yes No x Research level

Gas stream is passed through a filter medium of soiadsorbed and degraded by microbial metabolism fodioxide and water.

38 Pahlman Process No No x Research Level

Gas stream is passed through a filter baghouse in wsmall-particle, high-surface area metal oxide sorbenPollutants are removed from the gases by adsorptio

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. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 
Taconite BART Analysis

SOx Control

Available and Applicable Review

Reference(s) 

Reference No.

1

SO2 Pollution Control Technology Available? Applicable?

MPCA Taconite 

BART Report

MPCA BART 

Guidance 

(Attachment 2)

Other

2

Comments Basic Principle

1 Wet Scrubbing (High Efficiency) Yes Yes x x x Absorption and reaction using an alkaline reagent to prod

2 Wet Scrubbing (Low Efficiency) Yes Yes x x x Absorption and reaction using an alkaline reagent to prod

3 Wet Walled Electrostatic Precipitator (WWESP) Yes Yes x x Existing fabric filter control Suspended particles are separated from the flue gas stream

hoppers

4 Dry sorbent injection Yes Yes x x x

Pulverized lime or limestone is directly injected into the dsorption of SO2 onto the lime or limestone particle occurs 

with a fabric filter

5 Spray Dryer Absorption (SDA) Yes Yes x x Lime slurry is sprayed into an absorption tower where SO

CaSO3/CaSO4

6 Alternative Fuels Yes Yes x x Not permitted for other fuels. Use a fuel with lower sulfur content.

7 Load Reduction Yes No x Could reduce production This is a strategy to reduce load on a power plant by redu

efficiency projects.

8 Energy Efficiency Projects Yes Yes x decrease amount of fuel required to make an acceptable p

9 Coal Drying Yes Yes x Requires available excess heat source Dry coal will increase the as-burned BTU value, and there

burned. Specific energy efficiency project

10 Bio Filters No No x Research level

Gas stream passes through a packed bed of specially engigrowth of active bacterial species. The pollutants in the gabiotransformed into innocuous products, such as carbon dsulfate or nitrate ions in water.

11 CANSOLV Regenerable SO2 No No x Research level

An aqueous solution of proprietary diamine captures SO2 

absorption tower. The rich solvent is regenerated by steam pure, water saturated SO2 gas and lean solvent for recycli

12 Pahlman Process No No x Research level

Gas stream is passed through a filter baghouse in which shigh-surface area metal oxide sorbent have been deployedgases by adsorption.

13 SOx-NOx-Rox-Box No No x Technology has not been demonstrated Dry sorbent injection upstream of the baghouse for remov

upstream of a zeolitic selective catalytic reduction (SCR) to reduce NOx emissions.

14 Electron (E-Beam) Process No No x

No operating commercial applications on coal

Electron beam irradiation in the presence of ammonia to iand nitrogen oxides into components which can be easily such as an ESP or baghouse.

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls 
Reference(s) 

Reference No.

1

SO2 Pollution Control Technology Available? Applicable?

MPCA Taconite 

BART Report

MPCA BART 

Guidance 

(Attachment 2)

Other

2

Comments Basic Principle

15 Electrocatalytic Oxidation No No x

Similar to cold plasma. Will keep 

watch for availability of this technology

Utilizes a reactor in which SO2, NOx, and mercury are ox

sulfuric acid, and mercuric oxide respectively using non-tOn recent project, the vender was doing final trials on ful

16 NOXSO No No

Commercial version of adsorption. Limited experience (proof-of-concept tests).

Uses a regenerable sorbent to simultaneously adsorb SO2 

fired utility and industrial boilers. In the process, the SO2 

product (liquid SO2, elemental sulfur, or sulfuric acid) an

and oxygen.

17 Copper-Oxide No No x

Absorption and SCR. Experience limited to pilot scale.

SO2 in the flue gas reacts with copper oxide, supported on 

copper sulfate. Ammonia is injected into the flue gas befoselective catalytic reduction-type reaction occurs that reduIn the regeneration step, the copper sulfate is reduced in a such as natural gas, producing a concentrated stream of S

18 SNOX No No x Early commercial development stage

Catalytic reduction of NOx in the presence of ammonia (N

of SO2 to SO3. The exit gas from the SO3 converter passe

condenser in which the SO3 is hydrated to H2SO4 vapor a

liquid sulfuric acid (H2SO4).

19 Cold Plasma No No 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. b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm c) New and Emerging Environmental Technologies, http://neet.rti.org/ d) ND BART Reports

Y:\23\38\131\NMC Process Boilers List of Control Technologies 2006-07-11.xls