Hibbing Taconite Analysis of Best Available Control Technology 

(BART) 

Table of Contents 

1. Executive Summary.............................................................................................................................iii

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

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

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

3. Streamlined BART Analysis ................................................................................................................7

3.A Indurating Furnaces ....................................................................................................................7

3.B PM-Only Taconite MACT Emission Units ................................................................................7

3.C Sources of fugitive PM that are subject to MACT standards......................................................8

3.D Non-MACT Units and Fugitive Sources (PM only)...................................................................8

3.E Other Combustion Units .............................................................................................................9

3.F Visibility Impact Modeling for Negligible Impacts....................................................................9

4. Baseline Conditions and Visibility Impacts for BART Eligible Units ...............................................11

4.A MPCA Subject-to-BART Modeling .........................................................................................11

4.B Facility Baseline Modeling .......................................................................................................12

4.C Facility Baseline Modeling Results ..........................................................................................17

5. BART Analysis for BART Eligible Emission Units ..........................................................................18

5.A Indurating Furnace....................................................................................................................18

5.A.i Sulfur Dioxide Controls............................................................................................... 18

5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 18

5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 19

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

Technologies................................................................................................ 24

5.A.i.d STEP 4 – Evaluate Impacts and Document the Results............................... 24

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

5.A.ii Nitrogen Oxide Controls.............................................................................................. 27

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

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

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

Technologies................................................................................................ 40

5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results............................... 40

5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 42

6. Visibility Impacts................................................................................................................................43

6.A Post-Control Modeling Scenarios .............................................................................................43

6.B Post-Control Modeling Results.................................................................................................43

7. Select BART.......................................................................................................................................44

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List of Tables 

Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis.... 10

Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data . 13

Table 4-2 Baseline Visibility Modeling Results........................................................................... 17

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

Technical Feasibility.................................................................................................... 23

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness ......................................... 24

Table 5-3 SO2 Control Cost Summary ......................................................................................... 25

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

Technical Feasibility.................................................................................................... 39

Table 5-5 Indurating Furnace NOx Control Technology Effectiveness......................................... 40

Table 5-6 NOx Control Cost Summary......................................................................................... 41

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 

Appendix E BART, CAIR, & Other References to Cost-Effective Air Pollution Controls 

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1. Executive Summary 

Hibbing Taconite Company (HTC) is located on the Iron Range in northern Minnesota, with mining 

and processing facilities near the towns of Chisholm and Hibbing. At its facility, HTC mines and 

processes iron ore to produce pellets used in steel making. Within the pellet making process, there 

are many pieces of equipment with pollution control devices to reduce emissions. Some of these 

units are subject to the Regional Haze Rule and BART. The MPCA identified approximately 30 

pieces of equipment at HTC that were installed within the time window (1962-1977) that makes them 

subject to BART. The equipment includes the three straight-grate indurating furnace lines that use 

natural gas for fuel, as well as material handling and/or storage units for as ore, product, and 

additives. Preliminary visibility modeling conducted by the MPCA found that air emissions from 

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

making the facility subject to BART. This report describes the background and methods for the 

selection of the Best Available Retrofit Technology (BART) as proposed by HTC for its taconite 

processing plant. 

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

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

scrubber designed to control of particulate matter (PM); however some collateral control of sulfur 

dioxide (SO2) is also achieved. A dispersion modeling sequence of CALMET, CALPUFF, and 

CALPOST was used to assess the visibility impacts of the baseline emissions before 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, HTC establishes the following as BART: 

• SO2 emissions will be controlled by the existing wet scrubbers on the furnaces. 

• NOx emissions will be reduced by energy efficiency projects implemented after the BART 

baseline date. In fall of 2005, the Line 3 project was implemented, which reduced natural gas 

usage on Line 3by 12%. The Line 1 project was implemented in February 2006 and reduced

natural gas usage on Line 1 by 20%. The Line 2 efficiency project was recently completed 

and an evaluation of fuel reduction on Line 2 will be available in the near future. Fuel 

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iii
reductions on Line 2 are expected to be 12%. Because a portion of NOx formed during the 

indurating process is fuel bound NOx, it is reasonable to expect that because fuel usage was 

reduced, the amount of NOx emissions are also reduced. In addition, because the changes 

reduced hot spots in the furnaces and provided a more even temperature distribution 

throughout the furnaces, NOx emissions are expected to be reduced, but stack testing would 

be necessary in order to quantify the reduction. 

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

technology (MACT) standard1

. 

The proposed BART controls will result in visibility improvements of 13% on the worst visibility 

days and reduce the number of days that the visibility contribution from HTC is above 0.5 deciviews 

(dv) by 31 days. The NOx reductions at HTC represent a significant contribution to the default glide 

path goal of improving visibility by one to two percent per year. This level of reduction goes well 

beyond the annual goal and represents a realistic commitment that HTC can make within the time 

frame for MPCA’s SIP submittal in 2007. 

 

1

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

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2. Introduction 

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

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

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

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

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

Within its boundary, Minnesota has two Class I areas – the Boundary 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. 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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1
Figure 2-1 Minnesota’s BART Geography 

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

Waters Canoe Area (BWCA)] and BART-eligible units illustrated above.

(Source MPCA BART-Strategy October 4, 2005) 

By definition, reasonable progress means that the visibility on the 20 best days must not worsen, and 

the visibility on the 20 worst days must become equivalent to the 20 worst days under natural 

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

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

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

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

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

2.A BART Eligibility 

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

must meet the following three conditions: 

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2
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. 

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 

E:\BART\HTC\HTC BART Report Final.doc 

3
source, the energy and non-air quality environmental impacts of the technology, and the visibility 

impacts.2

 The five steps of a BART analysis are: 

Step 1 - Identify all Control Technologies 

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

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

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

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

A control technique is considered available, within the context presented 

above, if it has reached the licensing and commercial sales stages of 

development. Similarly, we 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. Consequently, you would not consider technologies in 

the pilot scale testing stages of development as available for purposes of a 

BART review.3

In summary, to be a commercially available control technology for a taconite plant a 

technology must have been demonstrated in a full scale operation at a source type with 

exhaust properties that are similar in scale and composition to the exhaust from a 

taconite plant. 

Step 2 - Eliminate Technically Infeasible Options 

In the second step, the technical feasibility of each control option identified in step one 

is evaluated with respect to source-specific factors. Technically infeasible technologies 

are eliminated from further consideration. Commercial availability is not a sufficient 

basis for concluding that a technology is applicable and technically feasible. If a 

technology is commercially available, it is also “applicable” if it has been used on “the 

same or a similar source type.”4

 If it has not been applied on a similar source type, the 

physical and chemical characteristics of the gas streams would be evaluated as well as 

the capabilities of the technology, to provide a basis for concluding whether the 

technology is technically feasible. 

 

2

 40 CFR 51 Appendix Y 

3

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

4

 IBID 

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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 protocol5

, including receptor grid, meteorological 

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

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

and the number of days the facility 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: 

 

5

 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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5
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.6

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 time7

.” 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 basis8

.” which could include the incorporation of 

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

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

technological or economic limitations make measurement methodology for an emission unit 

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

standard, or combination of these types of standards9

.” 

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

the Minnesota SIP. 

 

6

 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 7

 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 8

 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 9

 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 analyses10. The streamlined approach will allow both states and the 

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

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

results of the streamlined approach. 

3.A Indurating Furnaces 

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

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

furnaces are subject to the taconite MACT standard11 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.”12 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. 

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 handling operations, additive storage and handling operations, and finished pellet handling 

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

SO2. The ore 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). Therefore, the emissions from the pellet coolers are considered to have a 

 

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

11 40 CFR 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing 

12 Minnesota Pollution Control Agency (MPCA). March 2006. Guidance for Facilities Conducting a BART 

Analysis. Attachment 2. Page 2. 

 

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

consistent with the intention of the BART analysis. 

Since the MACT standard was established recently and 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 HTC 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.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 

• Limestone storage 

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

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

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

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

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

impact on visibility improvement in Class I areas. For these controlled sources, existing controls will 

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

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

 

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3.E Other Combustion Units 

No other combustion units were identified as potentially BART eligible for HTC. No analysis to 

establish BART for such sources is necessary. 

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. HTC 

does not have any potentially BART eligible sources that require screening modeling. 

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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

Existing Limit 

Expressed As 

lbs/day2

3.A Indurating Furnaces gr/dscf 

EU020 Pellet Indurating Furnace Line No 1 PM 0.01 1,128 

EU021 Pellet Indurating Furnace Line No 2 PM 0.01 864 

EU022 Pellet Indurating Furnace Line No 3 PM 0.01 1,056 

3.B PM-Only Taconite MACT Emission Units 

EU001 Phase I Apron Feeder (1st Level) PM 0.008 16 

EU002 Phase II Apron Feeder (1st Level) PM 0.008 16 

EU003 

Phase I Primary Ore Conveyor - (6th 

Level) PM 0.008 

EU004 

Phase II Primary Ore Conveyor - (6th 

Level) PM 0.008 

21 

EU005 Line No. 1 Mill Feed Conveyor PM 0.008 15 

EU006 Line No. 2 Mill Feed Conveyor PM 0.008 15 

EU007 Line No. 3 Mill Feed Conveyor PM 0.008 15 

EU008 Line No. 4 Mill Feed Conveyor PM 0.008 15 

EU009 Line No. 5 Mill Feed Conveyor PM 0.008 15 

EU010 Line No. 6 Mill Feed Conveyor PM 0.008 15 

EU011 Line No. 7 Mill Feed Conveyor PM 0.008 15 

EU012 Line No. 8 Mill Feed Conveyor PM 0.008 15 

EU013 Line No. 9 Mill Feed Conveyor PM 0.008 15 

EU018 Phase I Hearth Layer Bin PM 0.008 72 

EU018 Phase I Hearth Layer Feed PM 0.008 18 

EU019 Phase II Hearth Layer Bin PM 0.008 72 

EU019 Phase II Hearth Layer Feed PM 0.008 18 

EU023 Pellet Machine Discharge Line No 1 PM 0.008 50 

EU024 Pellet Machine Discharge Line No 2 PM 0.008 50 

EU025 Pellet Machine Discharge Line No 3 PM 0.008 50 

EU026 Pellet Hearth Layer Screening PM 0.008 86 

EU027 Pellet Transfer House PM 0.008 65 

3.D 

Non-MACT Emission Units and Fugitive 

Sources (PM-Only) 

EU016 Phase I Bentonite Day Bins PM 8 

EU017 Phase II Bentonite Day Bins PM 8 

EU028 Bentonite Storage Silo - East PM 0 

EU029 Bentonite Storage Silo - West PM 0 

EU033 Limestone Storage Silo PM 0 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 guidance13, one of the factors to consider when determining 

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

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

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

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

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

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

approach when assessing visibility impacts. 

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

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

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

the maximum 24-hour actual emissions14. 

4.A MPCA Subject-to-BART Modeling 

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

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

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

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

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

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

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

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

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

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

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

this facility is subject-to-BART. 

 

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

14 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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11
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12

4.B Facility Baseline Modeling 

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

On behalf of HTC 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 HTC and 

adjusted, as appropriate, to confirm that the emission rates represent the maximum steady-state 

operating conditions during periods of high capacity utilization. The maximum 24-hour emission 

rates were adjusted to reflect changes at the facility that occurred after the submittal of the 

information requested by MPCA. 

Energy efficiency projects have been implemented on Lines 1, 2 and 3 that will reduce natural gas 

usage and therefore reduce fuel bound NOx emissions by a yet to be determined amount. 

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

analysis is presented in Appendix C.
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions D

Emission Unit ID 

(Emission) 

Unit 

Description 

SO2 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

SO2 

24-hr 

Actua

l 

Emis

sions 

NOx 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

NOx 

24-hr 

Actua

l 

Emis

sions 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.

5 24-

hr 

Actua

l 

Emis

sions 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM1

0 24-

hr 

Actua

l 

Emis

sions Stack No. 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height 

of 

Openi

ng 

from 

Groun

d 

(ft) 

Base 

Elevation 

from 

Ground 

(ft) 

3.A Indurating Furnaces 

EU020 

Pellet 

Indurating 

Furnace Line 

No 1 

720 A 13,392 A 0 1,128 SV021M-SV024M 502391.00 5258098.00 119 1,630 

EU021 

Pellet 

Indurating 

Furnace Line 

No 2 

912 A 11,112 A 0 864 SV025M-SV028M 502448.00 5258105.00 119 1,630 

EU022 

Pellet 

Indurating 

Furnace Line 

No 3 

1,032 A 12,624 A 0 1,056 SV029M-SV032M 502491.00 5258114.00 119 1,630 

3.B 

PM-Only 

Taconite 

MACT 

Emission 

Units 

EU001 

Phase I 

Apron 

Feeder (1st 

Level) 

N/A N/A 0 16 SV001M 40 1,730 

EU002 

Phase II 

Apron 

Feeder (1st 

Level) 

N/A N/A 0 16 SV002M 40 1,730 

EU003 

Phase I 

Primary Ore 

Conveyor - 

(6th Level) 

N/A N/A 0 SV003M 61 1,730 

EU004 

Phase II 

Primary Ore 

Conveyor - 

(6th Level) 

N/A N/A 0 

21 

SV003M 61 1,730 

E:\BART\HTC\HTC BART Report Final.doc 

13
Emissio

n Unit ID 

(Emission) 

Unit 

Description 

SO2 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

SO2 

24-hr 

Actua

l 

Emis

sions 

NOx 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

NOx 

24-hr 

Actua

l 

Emis

sions 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.

5 24-

hr 

Actua

l 

Emis

sions 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM1

0 24-

hr 

Actua

l 

Emis

sions Stack No. 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height 

of 

Openi

ng 

from 

Groun

d 

(ft) 

Base 

Elevation 

from 

Ground 

(ft) 

EU005 

Line No. 1 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV004M 61 1,690 

EU006 

Line No. 2 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV005M 61 1,690 

EU007 

Line No. 3 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV006M 61 1,690 

EU008 

Line No. 4 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV007M 61 1,690 

EU009 

Line No. 5 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV008M 61 1,690 

EU010 

Line No. 6 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV009M 61 1,690 

EU011 

Line No. 7 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV010M 61 1,690 

EU012 

Line No. 8 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV011M 61 1,690 

EU013 

Line No. 9 

Mill Feed 

Conveyor 

N/A N/A 0 15 SV012M 61 1,690 

EU018 

Phase I 

Hearth Layer 

Bin 

N/A N/A 0 72 SV017M 109 1,630 

EU018 

Phase I 

Hearth Layer 

Feed 

N/A N/A 0 18 SV019M 109 1,630 

EU019 

Phase II 

Hearth Layer 

Bin 

N/A N/A 0 72 SV018M 109 1,630 

EU019 

Phase II 

Hearth Layer 

Feed 

N/A N/A 0 18 SV020M 106 1,630 

E:\BART\HTC\HTC BART Report Final.doc 

14
Emissio

n Unit ID 

(Emission) 

Unit 

Description 

SO2 

Max. 24-

hr Actual 

Emission

s (lb/day) 

Basis 

for 

SO2 

24-hr 

Actua

l 

Emis

sions 

NOx 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

NOx 

24-hr 

Actua

l 

Emis

sions 

PM2.5 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM2.

5 24-

hr 

Actua

l 

Emis

sions 

PM10 

Max. 

24-hr 

Actual 

Emissio

ns 

(lb/day) 

Basis 

for 

PM1

0 24-

hr 

Actua

l 

Emis

sions Stack No. 

Stack 

Easting 

(utm) 

Stack 

Northing 

(utm) 

Height 

of 

Openi

ng 

from 

Groun

d 

(ft) 

Base 

Elevation 

from 

Ground 

(ft) 

EU023 

Pellet 

Machine 

Discharge 

Line No 1 

N/A N/A 0 50 SV033M 116 1,630 

EU024 

Pellet 

Machine 

Discharge 

Line No 2 

N/A N/A 0 50 SV034M 116 1,630 

EU025 

Pellet 

Machine 

Discharge 

Line No 3 

N/A N/A 0 50 SV035M 116 1,630 

EU026 

Pellet Hearth 

Layer 

Screening 

N/A N/A 0 86 SV036M 117 1,630 

EU027 

Pellet 

Transfer 

House 

N/A N/A 0 65 SV037M 65 1,630 

3.D 

Non-MACT 

Emission 

Units and 

Fugitive 

Sources 

(PM-Only) 

EU016 

Phase I 

Bentonite 

Day Bins 

N/A N/A 0 8 SV015M 109 1,630 

EU017 

Phase II 

Bentonite 

Day Bins 

N/A N/A 0 8 SV016M 109 1,630 

EU028 

Bentonite 

Storage Silo 

- East 

N/A N/A 0 0 SV038M 75 1,605 

EU029 

Bentonite 

Storage Silo 

- West 

N/A N/A 0 0 SV039M 83 1,605 

EU033 Limestone Storage Silo N/A N/A 0 0 SV043 0 0 

E:\BART\HTC\HTC BART Report Final.doc 

15
E:\BART\HTC\HTC BART Report Final.doc 

16

Basis for 24-hour Actual Emissions 

A. Representative Stack Tests; 2004-2005. Fuel: Natural Gas B. Permit Limit C. Maximum Hourly PTE D. Emission Factor Calculation 
4.C Facility Baseline Modeling Results 

The Minnesota BART modeling protocol15 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-control 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 BART16, a source "contributes to 

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

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

protected Class I area receptor. 

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

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

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

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

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

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

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

The full modeling analysis is presented in Appendix C. 

Table 4-2 Baseline Visibility Modeling Results 

2002 2003 2004 

2002 – 2004 

Combined 

Class I Area 

with 

Greatest 

Impact 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

Modeled 

98th

Percentile 

Value 

(deciview) 

No. of 

days 

exceeding 

0.5 

deciview 

BWCA 1.634 73 1.638 64 1.604 52 1.609 189 

 

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

Subject-to-BART in the State of Minnesota. Page 8. 16 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources 

Subject-to-BART in the State of Minnesota. 

E:\BART\HTC\HTC BART Report Final.doc 

17
5. BART Analysis for BART Eligible Emission Units 

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

5.A Indurating Furnace 

HTC has three straight grate furnaces, Lines 1, 2, and 3. “Wet” or “green” pellets are oxidized and 

heat-hardened in these indurating furnaces. The induration process involves pellet drying, preheating, firing (hardening and oxidation) and cooling zones.. 

HTC uses straight grate furnaces, in which pellets move through the entire furnace on a traveling 

grate. The pellet hardening and oxidation zone of the induration furnace is designed to operate at 

2,350 to 2,400 oF. This temperature is required to meet taconite pellet product specifications. Fuel 

combustion in the induration furnace is carried out at 300 % to 400 % excess air to provide sufficient 

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. Pellet drying and pre-heat zones are heated with the high 

temperature exhaust gases generated in the pellet firing and cooling zones. Each of these zones is 

designed to maximize heat recovery within process constraints. Natural gas is the primary fuel used 

for indurating in all three furnaces with diesel fuel as a backup. HTC has been evaluating alternate 

solid fuels. Each line is controlled by four wet scrubbers. The wet scrubbers are designed to remove 

PM and would be considered a high efficiency PM wet scrubber. Since collateral SO2 reductions 

occur within the existing wet scrubber, it is considered a low efficiency SO2 scrubber and will be 

evaluated as such within this BART analysis. The lines do not have add-on controls for NOx. NOx is 

reduced by minimizing energy use. 

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. 

E:\BART\HTC\HTC BART Report Final.doc 

18
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. 

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

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

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

absorber. 

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

as SO2 flue gas concentration, fuel used, and ore composition. Since HTC currently employs a wet 

scrubber designed for removal of particulate matter, it performs as a low efficiency SO2 wet 

scrubber. The addition of a 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 WWESP is considered an available 

technology for SO2 reduction for this BART analysis. It is commercially available and has been 

demonstrated to be effective for SO2 removal on indurating furnaces. 

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. 

E:\BART\HTC\HTC BART Report Final.doc 

19
For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require 

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

could 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: 

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. 

E:\BART\HTC\HTC BART Report Final.doc 

20
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, wet scrubbers are currently in place on the furnace 

exhausts and are believed to remove 15 to 30% of the SO2 in the exhaust based on Barr’s experience 

and testing we have completed. Taking into consideration the removal of SO2 from the lowefficiency primary PM scrubber as well as a high efficiency SO2 polishing wet scrubber, an overall 

efficiency of the control train would then be 80%. 

In theory, the existing scrubber may be redesigned as a recirculating scrubber with addition of 

caustic, lime, or limestone to the scrubber water to improve SO2 removal, but this not a practical 

solution. Given the space limitations and equipment additions that would be required it would be 

more cost effective to construct a new, secondary scrubber, which is the alternative that is carried 

forward in this analysis. 

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

technology for SO2 reduction for this BART analysis. 

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) 

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

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

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

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

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

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

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

wet scrubber or a wet walled ESP. 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. 

E:\BART\HTC\HTC BART Report Final.doc 

21
Spray Dryer Absorption (SDA) 

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

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

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

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

desulfurization (FGD) may also be used. 

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

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

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

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

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

be further evaluated in this report. 

Energy Efficiency Projects 

Energy efficiency projects provide opportunities for a 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 would be to improve the heat 

distribution and improve the flow of air in the furnace to reduce the fuel usage. Each project is very 

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

HTC has been implementing energy efficiency projects on-site and continues to evaluate new 

projects. Some of these projects were implemented after the BART information submittal. and they 

have reduced furnace fuel usage, which would primarily reduce NOx emissions. Therefore, this 

option is not applicable for SO2 reductions at HTC. 

E:\BART\HTC\HTC BART Report Final.doc 

22
Alternate Fuels 

As described within the energy efficiency description, unpredictable pricing and availability of 

certain fuels has pushed companies to evaluate alternate fuel sources. These fuel sources come in all 

forms – solid, liquid and gas. However; currently for the taconite industry, the more economic 

alternatives are typically solid fuels. To achieve reduction of SO2 emissions through alternative fuel 

usage, the source must be currently burning solid fuels, which HTC is not currently permitted to 

burn. Therefore, this option is not applicable for SO2 reductions at HTC. 

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.17 

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

Coal Processing 

Since HTC does not burn coal, this option is not applicable for SO2 reductions at HTC. 

Step 2 Conclusion 

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

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

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

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

Technical Feasibility 

SO2 Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

Wet Scrubbing (High Efficiency) Yes Yes Yes 

Wet Scrubbing (Low Efficiency) Yes Yes Yes 

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 Yes 

Coal Drying Yes No No 

 

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

E:\BART\HTC\HTC BART Report Final.doc 

23
5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

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

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

considered a polishing scrubber since a wet scrubber currently exists. The low efficiency wet 

scrubbing option would optimize the existing PM wet scrubber to enhance SO2 control efficiency, if 

possible. 

Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness 

SO2 Pollution Control Technology Approximate Control Efficiency

Wet Walled Electrostatic Precipitator (WWESP) 80 

Secondary Wet Scrubber 60 

Modifications to Existing Wet Scrubbing (Low Efficiency) 0-50 

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 wet scrubber after the 

existing scrubber and a wet walled electrostatic precipitator (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 8000 operating hours 

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

E:\BART\HTC\HTC BART Report Final.doc 

24
established based on the U.S. EPA control cost manual18 and engineering experience, and were 

adjusted for the specific flow rates and pollutant concentrations. 

Due to space considerations, 60%19 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. 

Table 5-3 SO2 Control Cost Summary 

Control Technology 

Installed 

Capital Cost 

(MM$) 

Operating 

Cost 

(MM$/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Wet Walled Electrostatic 

Precipitator (WWESP) 

Pellet Indurating Furnace Line No 1 $28,888,911 $4,460,257 $36,762 

Pellet Indurating Furnace Line No 2 $28,888,911 $4,460,257 $36,762 

Pellet Indurating Furnace Line No 3 $28,888,911 $4,460,257 $36,762 

Wet Scrubber (Additional) 

Pellet Indurating Furnace Line No 1 $42,951,640 $9,337,928 $57,723 

Pellet Indurating Furnace Line No 2 $43,604,738 $9,559,244 $66,582 

Pellet Indurating Furnace Line No 3 $44,500,959 $9,848,188 $65,434 

 

18 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 19 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 

E:\BART\HTC\HTC BART Report Final.doc 

25
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, then visibility modeling was conducted and energy and other impacts were evaluated. 

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 are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix E. 

However, MPCA has set a screening level for annualized air pollution control cost of $8,000 to 

$12,00020 per ton of controlled pollutant. Therefore, all air pollution control costs analyses and 

incremental costs were compared to the higher MPCA-directed annualized cost. 

The cost of SO2 control for HTC is greater than $30,000 per ton of pollutant removed. This cost is 

far in excess of any cost that is considered to be cost effective for BART, or even for BACT. 

Therefore, it is not necessary to calculate the incremental control cost of a WWESP compared to a 

wet scrubber. 

Energy and Environmental Impacts 

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

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

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

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

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

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

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. Table 

4-1 provides a summary of the SO2, NOx, and PM10 emissions for the baseline modeling scenario, 

 

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

Processing Plant, Fairmont, MN Permit 09100059-002. 

E:\BART\HTC\HTC BART Report Final.doc 

26
5.A.ii Nitrogen Oxide Controls 

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

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

• Fuel bound NOx is formed as nitrogen compounds in the fuel are 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, the balance 

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

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

With some 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 

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27
level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For 

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

the burner tip. 

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

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

1. The process exhaust gas in an induration furnace typically has an oxygen concentration 

that is close to the concentration of oxygen in ambient air, or 18% oxygen vs. a boiler 

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

a diluent for flame temperature reduction. Taconite waste gas has a 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. 

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

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

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

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

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

The estimated NOx control efficiency for low NOx burners in high temperature applications is 10%. 

Application of low NOx burners would be limited to the preheating section of the furnace, where the 

temperature is less critical to product quality. 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. 

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, but is not yet commercially available. The water injection 

technique shows promise for high temperature applications, but will not be further investigated in 

this report as the technology is still in the research and development phase. 

 Induced Flue Gas Recirculation Burners 

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

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

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

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

burners in high temperature applications is 25-50%. 

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

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

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

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

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

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

would adversely affect taconite pellet product quality. 

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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 other variables. 

HTC has implemented an energy efficiency project that reduces natural gas usage and therefore 

should reduces emissions of NOx. The project involved a change to the two combustion chamber 

upper air inlet ducts on each furnace line to allow for more efficient combustion of natural gas. The 

project increased the cross-sectional area of the upper inlet air transition ducts to achieve a more 

uniform air flow. This change helps significantly minimize the need for the atomizing air that was 

needed to push the flame out into the firing hood. This air was needed because of interference of the 

lower burners’ flame pattern by the existing swirling action and uneven airflow in the combustion 

chambers. Because this atomizing air no longer needs to be heated, the natural gas usage is reduced. 

The project for Line 1 was implemented in February 2006 and resulted in a 20% fuel reduction. The 

project for Line 3 was implemented in fall of 2005 and resulted in a 12% fuel reduction. The project 

for Line 2 was completed in June of 2006 and is expected to result in a 12% fuel usage reduction. 

Because some percentage of NOx is formed from the fuel used in the indurating process, HTC can 

expect a reduction in NOx emissions as a direct result of these projects. 

HTC continues 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. 

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

HTC. Therefore, ported kilns are not an applicable technology for this facility. 

Alternate Fuels 

As described within the energy efficiency description, unpredictable pricing and availability of 

certain fuels 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 natural gas as the primary fuel. Switching from natural gas to a 

solid fuel for the indurating process would emit significantly less NOx. Switching natural gas usage 

to coal or other solid fuels exchanges one visibility impairment pollutant (NOx) for another (SO2). 

Therefore, if this option is pursued, the impact on emissions of all visibility impairing pollutants 

must be quantified and the cumulative visibility impact modeled to determine the net benefit of a 

particular alternative fuel. 

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

option, not to direct the fuel choice.21 It is also important to note that furnace and process 

modifications to the straight-grate furnace in order to use alternative fuels. 

HTC has evaluated several solid fuel alternatives. Oat hulls and wood chips were evaluated with 

limited success. Because of the furnace design, the solid fuel must be very finely ground. Several 

grades of fine sawdust have been evaluated, and in the testing trials, fine sawdust could provide up to 

30 percent of fuel needs. The supply of fine sawdust is very limited and supply cannot be relied 

upon to meet production needs. In addition, the cost is not as economical as natural gas. HTC 

intends to continue to evaluate other fuels, but no viable options are clear at this time. Therefore, 

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

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

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

Process Optimization with NOx CEMS or Other Parametric Monitoring 

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

emissions22. 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 

 

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

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would be measured using the NOx CEMS. This approach has been used in the electric utility 

industry to fine tune NOx emissions from boilers. It may also be possible to measure the impact of 

the process changes using parametric monitoring. 

However, 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 material 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 is not dependent upon controllable operating parameters. In the absence of 

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

emissions. 

• Process optimization for NOx reductions on an induration furnace is not a proven technology 

and is not commercially available as a method of NOx control. To date, NOx CEMS have not 

been documented as a control technology for induration furnaces. To meet the available and 

applicable BART analysis criteria, documentation of the control technology is needed. 

• To the best of our knowledge, there are no documented evaluations of NOx emission 

reductions for induration furnaces by optimizing the process using either NOx CEMS or 

parametric monitoring. We understand the reductions MPCA is aware of include other 

variables, such as a fuel switch, that would have an impact alone, so the CEMS contribution 

hasn’t been isolated. 

 

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

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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.

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 

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

this report. 

Regenerative Selective Catalytic Reduction and 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. 

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. 

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• 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 significant 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; 

• SCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by the 

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

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

identify mitigation methods if needed. 

To date, 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 

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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 will be carried forward in this analysis as available 

and applicable technology that is reasonably expected to be technically feasible. 

Low Temperature Oxidation (LTO) 

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

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

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

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

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

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

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

NO + O3 → NO2 + O2 (1) 

NO2 + O3 → NO3 + O2 (2) 

NO3 + NO2 → N2O5 (3) 

N2O5 + H2O → 2HNO3 (4) 

HNO3 + NaOH → NaNO3 + H2O (5) 

Low Temperature Oxidation (Tri-NOx

®) 

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

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

reactions are as follows: 

O3 + NO → O2 + NO2 (1) 

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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 

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 up to 

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772,000 to 827,000 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 

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 

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furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of 

performance would be forthcoming in advance of a demonstration project. The timeline required to 

perform such a demonstration project would likely be two years to develop and agree on the test 

plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs 

for a reasonable study period, and evaluate and report on the results. The results would not be 

available within the time window for establishing emission limits to be incorporated in the state 

implementation plan (SIP) by December 2007. 

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

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

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

Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for 

this application and will not be evaluated further. 

Step 2 Conclusion 

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

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

feasibility as determined in Step 2 is also included in Table 5-4.

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 Yes 

Ported Kilns 

(Applies to Grate Kilns Only) Yes No No 

Alternative Fuels Yes Yes No 

Process Optimization using 

NOx CEMS Yes No No 

Non-Selective Catalytic 

Reduction (NSCR) Yes No No 

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NOx Pollution Control 

Technology Available? Applicable?

Technically 

Feasible? 

Selective Catalytic 

Reduction (SCR) with 

conventional reheat 

Yes Yes Yes 

Regenerative SCR Yes No No 

Selective Non-Catalytic 

Reduction (SNCR) Yes No No 

Low Temperature Oxidation 

(LTO) Yes No No 

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

Table 5-5 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% 

Energy Efficiency Projects 12-20% 

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

Table 5-6 details the expected costs associated with installation of SCR with conventional reheat. 

Capital costs were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and 

vendor estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to 

each stack’s flow rate using the 6/10 power law to account for the economy of scale. Operating costs 

were based on 93% utilization and 8000 operating hours 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 personnel, it was determined that 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 recent actual retrofit 

costs for installation of a secondary wet scrubber at an existing taconite plant. See Appendix C for a 

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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 NOx Control Cost Summary 

Control 

Technology 

Installed 

Capital Cost 

($) 

Total 

Annualized 

Cost 

($/yr) 

Annualized 

Pollution 

Control Cost 

($/ton) 

Incremental

Control 

Cost 

($/ton) 

SCR with Conventional Reheat 

Pellet Indurating 

Furnace Line No 1 $80,957,276 $42,647,613 $20,478 NA 

Pellet Indurating 

Furnace Line No 2 $78,666,631 $40,222,018 $22,357 NA 

Pellet Indurating 

Furnace Line No 3 $83,052,744 $40,685,307 $22,208 NA 

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, then visibility modeling was conducted and energy and other impacts were evaluated. 

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 are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix E. 

However, MPCA has set a screening level for annualized air pollution control cost of $8,000 to 

$12,000 per ton of controlled pollutant23. Therefore, all air pollution control costs analyses and 

incremental costs will be compared to the higher MPCA-directed annualized cost. 

The cost of NOx control for HTC is greater than $18,000 per ton of pollutant removed. This cost is 

far in excess of any cost that is considered to be cost effective for BART, or even for BACT. It is 

not necessary to calculate incremental control costs because only one technology is technically 

feasible. 

 

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

Processing Plant, Fairmont, MN Permit 09100059-002. 

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Energy and Environmental Impacts 

Because the cost of additional NOx controls for HTC is so high and does not meet a reasonable 

definition of cost effective technology, SCR 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 add-on controls for NOx are not reasonably cost effective, and 

the reductions due to the energy efficiency projects cannot yet be quantified, so visibility impacts 

were not modeled for NOx controls. 

E:\BART\HTC\HTC BART Report Final.doc 

42
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 determines the resulting degree of visibility improvement. 

6.A Post-Control Modeling Scenarios 

Steps 1-4 of the BART analysis identified the control technologies that were: 

• Available and applicable; 

• Technically feasible; and 

• Below the screening cost threshold for further BART analysis. 

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that 

met the requirements of the screening analysis of steps 1-4. 

However, because there are no add-on control options available that meet the above criteria, there are 

no available control combinations, or control scenarios, that must be considered. 

6.B Post-Control Modeling Results 

As mentioned in section 5.B.ii.e, the energy efficiency projects underway at HTC reduce its fuel 

consumption significantly, although the impact on NOx emissions has not yet been quantified. 

E:\BART\HTC\HTC BART Report Final.doc 

43
7. Select BART 

BART for HTC is determined to be as described below. 

For SO2, add-on controls are not cost effective. Therefore, BART is determined to be existing 

controls. The corresponding SO2 emissions limit would be 720 lb/day for Line 1, 912 lb/day for Line 

2 and 1032 lb/day on Line 3. This will scale up from 1994 test data (690 gal/hr -> 1100 gal/hr) 

For NOx, the energy efficiency projects recently implemented or soon to be implemented are 

concluded to be BART. Other add-on controls for NOx are not cost effective. The corresponding 

NOx limits would be established following stack testing to confirm the estimated NOx emission 

levels. 

For PM, requirements compelled by the upcoming MACT standard constitute BART. The 

corresponding emissions limit would be equivalent to the limits identified in Table 3-1. 

The schedule for implementation of these controls is within the 5-year time-frame required for BART 

implementation. 

E:\BART\HTC\HTC BART Report Final.doc 

44
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 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

Selective Catalytic Reduction (SCR) with ReheatPellet Indurating Furnace Line No 1 80% 415.2 2,082.6 $80,957,276 $42,647,613 $20,478 Pellet Indurating Furnace Line No 2 80% 344.5 1,799.1 $78,666,631 $40,222,018 $22,357 Pellet Indurating Furnace Line No 3 80% 415.2 1,832.0 $83,052,744 $40,685,307 $22,208 

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)Pellet Indurating Furnace Line No 1 80% 40.4 161.8 $42,951,640 $9,337,928 $57,723

Pellet Indurating Furnace Line No 2 80% 35.9 143.6 $43,604,738 $9,559,244 $66,582Pellet Indurating Furnace Line No 3 80% 37.6 150.5 $44,500,959 $9,848,188 $65,434Wet Scrubber (Additional)Pellet Indurating Furnace Line No 1 60% 80.9 121.3 $28,888,911 $4,460,257 $36,762Pellet Indurating Furnace Line No 2 60% 80.9 121.3 $28,888,911 $4,460,257 $36,762Pellet Indurating Furnace Line No 3 60% 80.9 121.3 $28,888,911 $4,460,257 $36,762

E:\BART\HTC\HTC Control Costs.xlsCost Summary 
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 2: - Summary of Utility, Chemical and Supply Costs

Operating Unit: Pellet Indurating Furnace Line No 1 Study Year 2006

Emission Unit Number EU 020

Stack/Vent Number SV021M-SV024M

Operating Unit: Pellet Indurating Furnace Line No 2

Emission Unit Number EU 021

Stack/Vent Number SV025M-SV028M

Operating Unit: Pellet Indurating Furnace Line No 3 7439.858594

Emission Unit Number EU 022

Stack/Vent Number SV029M-SV032M

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 48.30 $/hr 2006 Site Specific - Hibbing Taconite.

Maintenance Labor 60.00 $/hr 2006 Site Specific - Hibbing Taconite. Construction Labor Rate.

Electricity 0.0410 $/kwh 2006 Site Specific - Hibbing Taconite. Purchased Cost.

Natural Gas 7.41 $/mscf 2006 Site Specific - Hibbing Taconite.

Indurating cost: $7.41/mcf or $7.30/M

Heating cost: $7.72/mcf or $7.61/MMB

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 Abso

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, C

inflation.

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 

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

Chemicals & Supplies

Lime 90.33 $/ton 90.33 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 

adjusted for 3% inflation.

Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes de

Other

Sales Tax 6.5% %

Interest Rate 7.00% %

EPA Air Pollution Control Cost Manual 

Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a defau

Operating InformationAnnual Op. Hrs 8000 Hours Engineering Estimate.

Utilization Rate 93%

Equipment Life 20 yrs Engineering Estimate.

Standardized Flow Rate

SV021M-SV024M 654,869 scfm @ 32o F Calculated.

SV025M-SV028M 674,379 scfm @ 32o F Calculated.

SV029M-SV032M 701,524 scfm @ 32o F Calculated.

E:\BART\HTC\HTC Control Costs.xls

Utility Chem$ Data 
Reference

Item Unit Cost Units Cost Year Data Source Notes

Temperature

SV021M-SV024M 120 Deg F BART spreadsheet. Range is 90 - 120 °F

SV025M-SV028M 120 Deg F BART spreadsheet. Range is 90 - 120 °F

SV029M-SV032M 120 Deg F BART spreadsheet. Range is 90 - 120 °F

Moisture Content

SV021M-SV024M 7.4% 2005

Y:\23\69\951 Hibbing Taconite Stack 

test\Hibbtac 05. Average from test results in: SV021-S

SV025M-SV028M 7.1% 2004

Y:\23\69\870 Hibbtac Title V Stack Testing\Data\Furnace L2. Average from test results in: SV025 - 

SV029M-SV032M 8.5% 2005

Y:\23\69\951 Hibbing Taconite Stack 

test\Hibbtac 05 Week Two. Average from test results in: SV029 - 

Actual Flow RateSV021M-SV024M 772,000 acfm BART spreadsheet.

SV025M-SV028M 795,000 acfm BART spreadsheet.

SV029M-SV032M 827,000 acfm BART spreadsheet.

Standardized Flow Rate

SV021M-SV024M 702,786 scfm @ 68o F Calculated.

SV025M-SV028M 723,724 scfm @ 68o F Calculated.

SV029M-SV032M 752,855 scfm @ 68o F Calculated.

Dry Std Flow Rate

SV021M-SV024M 650,745 dscfm @ 68o F Calculated.

SV025M-SV028M 672,448 dscfm @ 68o F Calculated.

SV029M-SV032M 689,013 dscfm @ 68o F Calculated.

Max Emis Actual Emissions lb/hr ton/year

Pollutant Lb/Hr Ton/year ppmv ppmv

Nitrous Oxides (NOx) ('04&'05 Max plus 10%)

SV021M-SV024M 558.0 2,497.7 120 122.2 2005 plus 10%

SV025M-SV028M 463.0 2,143.5 96 101.5 2004 plus 10%

SV029M-SV032M 526.0 2,247.1 106 103.8 2004 plus 10%

Sulfur Dioxides (SO2)

SV021M-SV024M 30.0 202.2 5 7.1 2004 plus 10%

SV025M-SV028M 38.0 179.5 6 6.1 2004 plus 10%

SV029M-SV032M 43.0 188.1 6 6.2 2004 plus 10%

estimatecalculated value

known or assumed data

required data

E:\BART\HTC\HTC Control Costs.xls

Utility Chem$ Data 
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 3: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M

Standardized Flow Rate 654,869 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 772,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 8,439,806

 Purchased Equipment Total (B) 22% of control device cost (A) 10,254,364

 Installation - Standard Costs 67% of purchased equip cost (B) 6,870,424

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,870,424

 Total Direct Capital Cost, DC 17,124,788

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,844,987

Total Capital Investment (TCI) = DC + IC 42,951,640

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,238,475

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,099,453

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,337,928

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,497.7 558.0 0% 2497.7 - NA

Sulfur Dioxide (SO2) 30.0 202.2 80% 40.4 161.8 57,723

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.

4 Ammonia usage based on estimate from Vogt Power and scaled linearly using stack flow rate.

E:\BART\HTC\HTC Control Costs.xls

EU020 WWESP 9/1/2006 Page 4 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 3: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 8,439,806

Instrumentation 10% of control device cost (A) 843,981

MN Sales Taxes 6.5% of control device cost (A) 548,587

Freight 5% of control device cost (A) 421,990

Purchased Equipment Total (B) 22% 10,254,364

Installation

Foundations & supports 4% of purchased equip cost (B) 410,175

Handling & erection 50% of purchased equip cost (B) 5,127,182

Electrical 8% of purchased equip cost (B) 820,349

Piping 1% of purchased equip cost (B) 102,544

Insulation 2% of purchased equip cost (B) 205,087

Painting 2% of purchased equip cost (B) 205,087

Installation Subtotal Standard Expenses 67% 6,870,424

Total Direct Capital Cost, DC 17,124,788

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 2,050,873

Construction & field expenses 20% of purchased equip cost (B) 2,050,873

Contractor fees 10% of purchased equip cost (B) 1,025,436

Start-up 1% of purchased equip cost (B) 102,544

Performance test 1% of purchased equip cost (B) 102,544

Model Studies 2% of purchased equip cost (B) 205,087

Contingencies 3% of purchased equip cost (B) 307,631

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,844,987

Total Capital Investment (TCI) = DC + IC 22,969,775

Retrofit multiplier3

60% of TCI 13,781,865

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 42,951,640

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, Annual Operating Hours 15,063

Maintenance Materials 1.00 % of Maintenance Labor 84,398

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,824 kW-hr, Annual Operating Hours,93% utilization 556,471

Water 0.28 $/mgal, 3,860 gpm, Annual Operating Hours,93% utilization 477,036

WW Treat Neutralization 1.69 $/mgal, 3,860 gpm, Annual Operating Hours,93% utilization 2,909,053

Caustic 305.96 $/ton, 75 lb/hr, Annual Operating Hours,93% utilization 85,364

Total Annual Direct Operating Costs 4,238,475

Indirect Operating Costs

Overhead 60% of total labor and material costs 126,331

Administration (2% total capital costs) 2% of total capital costs (TCI) 459,395

Property tax (1% total capital costs) 1% of total capital costs (TCI) 229,698

Insurance (1% total capital costs) 1% of total capital costs (TCI) 229,698

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 4,054,331

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,099,453

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,337,928

See summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU020 WWESP 9/1/2006 Page 5 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 3: 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 772,000 10 1,397.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 72.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 182,587 354.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,824.3

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3860.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 75.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.3 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 14,490 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 15,063 $/Hr, 15.0 hr/wk, Annual Operating Hours

Maint Mtls 1 % of Purchase Cost NA 84,398 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1824.3 kW-hr 13,572,461 556,471 $/kwh, 1,824 kW-hr, Annual Operating Hours,93% utilization

Water 0.28 $/mgal 3,860.0 gpm 1,723,104 477,036 $/mgal, 3,860 gpm, Annual Operating Hours,93% utilization

WW Treat Neutralization 1.69 $/mgal 3,860.0 gpm 1,723,104 2,909,053 $/mgal, 3,860 gpm, Annual Operating Hours,93% utilization

Caustic 305.96 $/ton 75.0 lb/hr 279 85,364 $/ton, 75 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

E:\BART\HTC\HTC Control Costs.xls

EU020 WWESP 9/1/2006 Page 6 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 4: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Pellet Indurating Furnace Line No 2

Emission Unit Number EU 021 Stack/Vent Number SV025M-SV028M

Standardized Flow Rate 674,379 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.1%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 795,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 723,724 scfm @ 68o F

Dry Std Flow Rate 672,448 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 8,589,786

 Purchased Equipment Total (B) 22% of control device cost (A) 10,436,590

 Installation - Standard Costs 67% of purchased equip cost (B) 6,992,515

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,992,515

 Total Direct Capital Cost, DC 17,429,105

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,948,856

Total Capital Investment (TCI) = DC + IC 43,604,738

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,380,647

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,178,597

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,559,244

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,143.5 463.0 0% 2143.5 - NA

Sulfur Dioxide (SO2) 38.0 179.5 80% 35.9 143.6 66,582

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.

E:\BART\HTC\HTC Control Costs.xls

EU021 WWESP 9/1/2006 Page 7 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 4: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 8,589,786

Instrumentation 10% of control device cost (A) 858,979

MN Sales Taxes 6.5% of control device cost (A) 558,336

Freight 5% of control device cost (A) 429,489

Purchased Equipment Total (B) 22% 10,436,590

Installation

Foundations & supports 4% of purchased equip cost (B) 417,464

Handling & erection 50% of purchased equip cost (B) 5,218,295

Electrical 8% of purchased equip cost (B) 834,927

Piping 1% of purchased equip cost (B) 104,366

Insulation 2% of purchased equip cost (B) 208,732

Painting 2% of purchased equip cost (B) 208,732

Installation Subtotal Standard Expenses 67% 6,992,515

Total Direct Capital Cost, DC 17,429,105

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 2,087,318

Construction & field expenses 20% of purchased equip cost (B) 2,087,318

Contractor fees 10% of purchased equip cost (B) 1,043,659

Start-up 1% of purchased equip cost (B) 104,366

Performance test 1% of purchased equip cost (B) 104,366

Model Studies 2% of purchased equip cost (B) 208,732

Contingencies 3% of purchased equip cost (B) 313,098

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,948,856

Total Capital Investment (TCI) = DC + IC 23,377,961

Retrofit multiplier3

60% of TCI 14,026,777

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 43,604,738

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, Annual Operating Hours 15,512

Maintenance Materials 1.00 % of Maintenance Labor 85,898

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,879 kW-hr, Annual Operating Hours,93% utilization 573,050

Water 0.28 $/mgal, 3,975 gpm, Annual Operating Hours,93% utilization 491,248

WW Treat Neutralization 1.69 $/mgal, 3,975 gpm, Annual Operating Hours,93% utilization 2,995,722

Caustic 305.96 $/ton, 95 lb/hr, Annual Operating Hours,93% utilization 108,128

Total Annual Direct Operating Costs 4,380,647

Indirect Operating Costs

Overhead 60% of total labor and material costs 127,500

Administration (2% total capital costs) 2% of total capital costs (TCI) 467,559

Property tax (1% total capital costs) 1% of total capital costs (TCI) 233,780

Insurance (1% total capital costs) 1% of total capital costs (TCI) 233,780

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 4,115,979

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,178,597

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,559,244

See summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU021 WWESP 9/1/2006 Page 8 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 4: 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 795,000 10 1,439.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 74.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 188,027 364.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,878.6

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 3975.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 95.00 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.3 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 14,490 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 15,512 $/Hr, 15.0 hr/wk, Annual Operating Hours

Maint Mtls 1 % of Purchase Cost NA 85,898 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1878.6 kW-hr 13,976,822 573,050 $/kwh, 1,879 kW-hr, Annual Operating Hours,93% utilization

Water 0.28 $/mgal 3,975.0 gpm 1,774,440 491,248 $/mgal, 3,975 gpm, Annual Operating Hours,93% utilization

WW Treat Neutralization 1.69 $/mgal 3,975.0 gpm 1,774,440 2,995,722 $/mgal, 3,975 gpm, Annual Operating Hours,93% utilization

Caustic 305.96 $/ton 95.0 lb/hr 353 108,128 $/ton, 95 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

E:\BART\HTC\HTC Control Costs.xls

EU021 WWESP 9/1/2006 Page 9 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 5: SO2

 Control - Wet Walled Electrostatic Precipitator

Operating Unit: Pellet Indurating Furnace Line No 3

Emission Unit Number EU 022 Stack/Vent Number SV029M-SV032M

Standardized Flow Rate 701,524 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 8.5%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 827,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 752,855 scfm @ 68o F

Dry Std Flow Rate 689,013 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 8,795,598

 Purchased Equipment Total (B) 22% of control device cost (A) 10,686,652

 Installation - Standard Costs 67% of purchased equip cost (B) 7,160,057

 Installation - Site Specific Costs 6,200,000

 Installation Total 7,160,057

 Total Direct Capital Cost, DC 17,846,708

 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 6,091,391

Total Capital Investment (TCI) = DC + IC 44,500,959

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 4,560,979

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,287,209

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,848,188

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,247.1 526.0 0% 2247.1 - NA

Sulfur Dioxide (SO2) 43.0 188.1 80% 37.6 150.5 65,434

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.

E:\BART\HTC\HTC Control Costs.xls

EU022 WWESP 9/1/2006 Page 10 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 5: SO2 Control - Wet Walled Electrostatic Precipitator

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A)1

Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 8,795,598

Instrumentation 10% of control device cost (A) 879,560

MN Sales Taxes 6.5% of control device cost (A) 571,714

Freight 5% of control device cost (A) 439,780

Purchased Equipment Total (B) 22% 10,686,652

Installation

Foundations & supports 4% of purchased equip cost (B) 427,466

Handling & erection 50% of purchased equip cost (B) 5,343,326

Electrical 8% of purchased equip cost (B) 854,932

Piping 1% of purchased equip cost (B) 106,867

Insulation 2% of purchased equip cost (B) 213,733

Painting 2% of purchased equip cost (B) 213,733

Installation Subtotal Standard Expenses 67% 7,160,057

Total Direct Capital Cost, DC 17,846,708

Indirect Capital Costs

Engineering, supervision 20% of purchased equip cost (B) 2,137,330

Construction & field expenses 20% of purchased equip cost (B) 2,137,330

Contractor fees 10% of purchased equip cost (B) 1,068,665

Start-up 1% of purchased equip cost (B) 106,867

Performance test 1% of purchased equip cost (B) 106,867

Model Studies 2% of purchased equip cost (B) 213,733

Contingencies 3% of purchased equip cost (B) 320,600

Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 6,091,391

Total Capital Investment (TCI) = DC + IC 23,938,099

Retrofit multiplier3

60% of TCI 14,362,860

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 44,500,959

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Labor 60.00 $/Hr, 15.0 hr/wk, Annual Operating Hours 16,137

Maintenance Materials 1.00 % of Maintenance Labor 87,956

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,954 kW-hr, Annual Operating Hours,93% utilization 596,116

Water 0.28 $/mgal, 4,135 gpm, Annual Operating Hours,93% utilization 511,021

WW Treat Neutralization 1.69 $/mgal, 4,135 gpm, Annual Operating Hours,93% utilization 3,116,304

Caustic 305.96 $/ton, 108 lb/hr, Annual Operating Hours,93% utilization 122,355

Total Annual Direct Operating Costs 4,560,979

Indirect Operating Costs

Overhead 60% of total labor and material costs 129,110

Administration (2% total capital costs) 2% of total capital costs (TCI) 478,762

Property tax (1% total capital costs) 1% of total capital costs (TCI) 239,381

Insurance (1% total capital costs) 1% of total capital costs (TCI) 239,381

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 4,200,576

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,287,209

Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,848,188

See summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU022 WWESP 9/1/2006 Page 11 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 5: 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 827,000 10 1,496.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46

Fluid Head (ft) Pump Eff.

Pump Power 60 60% 77.9 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47

Plate Area

ESP Power 195,595 379.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48

Total 1,954.2

Reagent Use & Other Operating Costs

gpm

Water 5.00 gal/min-kacfm 4135.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6

lb/hr

Reagent Use 2.50 lb NaOH/lb SO2 107.50 lb/hr caustic

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.3 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 14,490 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 15.0 hr/wk 660 16,137 $/Hr, 15.0 hr/wk, Annual Operating Hours

Maint Mtls 1 % of Purchase Cost NA 87,956 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1954.2 kW-hr 14,539,411 596,116 $/kwh, 1,954 kW-hr, Annual Operating Hours,93% utilization

Water 0.28 $/mgal 4,135.0 gpm 1,845,864 511,021 $/mgal, 4,135 gpm, Annual Operating Hours,93% utilization

WW Treat Neutralization 1.69 $/mgal 4,135.0 gpm 1,845,864 3,116,304 $/mgal, 4,135 gpm, Annual Operating Hours,93% utilization

Caustic 305.96 $/ton 107.5 lb/hr 400 122,355 $/ton, 108 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

E:\BART\HTC\HTC Control Costs.xls

EU022 WWESP 9/1/2006 Page 12 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 6: SOx Control - Wet Scrubber

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M

Standardized Flow Rate 654,869 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 772,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,835,625

 Purchased Equipment Total (B) 22% of control device cost (A) 7,090,285

 Installation - Standard Costs 85% of purchased equip cost (B) 6,026,742

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,026,742

 Total Direct Capital Cost, DC 13,117,027

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 28,888,911

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,113,462

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 558.0 2,497.7 0% 2497.7 - NA

Sulfur Dioxide (SO2) 30.0 202.2 60% 80.9 121.3 36,762

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.

E:\BART\HTC\HTC Control Costs.xls

EU020 Wet Scrubber 9/1/2006 Page 13 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

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 5,835,625

Instrumentation 10% of control device cost (A) 583,563

MN Sales Taxes 7% of control device cost (A) 379,316

Freight 5% of control device cost (A) 291,781

Purchased Equipment Total (B) 22% 7,090,285

Installation

Foundations & supports 12% of purchased equip cost (B) 850,834

Handling & erection 40% of purchased equip cost (B) 2,836,114

Electrical 1% of purchased equip cost (B) 70,903

Piping 30% of purchased equip cost (B) 2,127,085

Insulation 1% of purchased equip cost (B) 70,903

Painting 1% of purchased equip cost (B) 70,903

Installation Subtotal Standard Expenses 85% 6,026,742

Total Direct Capital Cost, DC 13,117,027

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 354,514

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 354,514

Start-up 1% of purchased equip cost (B) 70,903

Performance test 1% of purchased equip cost (B) 70,903

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 212,709

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 14,180,569

Retrofit multiplier560% of TCI 8,508,342

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 28,888,911

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization 484,289

Water 0.28 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization 89,522

WW Treat Neutralization 1.69 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization 442,176

Lime 90.33 $/ton, 29 lb/hr, Annual Operating Hours, 93% utilization 9,703

Total Annual Direct Operating Costs 1,113,462

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 283,611

Property tax (1% total capital costs) 1% of total capital costs (TCI) 141,806

Insurance (1% total capital costs) 1% of total capital costs (TCI) 141,806

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,726,909

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU020 Wet Scrubber 9/1/2006 Page 14 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

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 772,000 8.55 0.7 - 1,103.2 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 29,336 gpm 1 60 0.7 - 472.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 724 gpm 1 60 0.7 - 11.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1587.6

Reagent Use & Other Operating Costs

Caustic Use 30.00 lb/hr SO2 2.50 lb NaOH/lb SO2 75.00 lb/hr Caustic

Lime Use 30.00 lb/hr SO2 0.96 lb Lime/lb SO2 28.88 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

29,336 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 724 gpm

Evaporation Loss4 = 137.66 gpm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 15% of Operator Costs 3,623

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1587.6 kW-hr 11,811,923 484,289 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 724.4 gpm 323,362 89,522 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 586.7 gpm 261,912 442,176 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization

Lime 90.3 $/ton 28.9 lb/hr 107 9,703 $/ton, 29 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

E:\BART\HTC\HTC Control Costs.xls

EU020 Wet Scrubber 9/1/2006 Page 15 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 7: SOx Control - Wet Scrubber

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M

Standardized Flow Rate 654,869 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 772,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,835,625

 Purchased Equipment Total (B) 22% of control device cost (A) 7,090,285

 Installation - Standard Costs 85% of purchased equip cost (B) 6,026,742

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,026,742

 Total Direct Capital Cost, DC 13,117,027

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 28,888,911

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,113,462

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 558.0 2,497.7 0% 2497.7 - NA

Sulfur Dioxide (SO2) 30.0 202.2 60% 80.9 121.3 36,762

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.

E:\BART\HTC\HTC Control Costs.xls

EU021 Wet Scrubber 9/1/2006 Page 16 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 7: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,835,625

Instrumentation 10% of control device cost (A) 583,563

MN Sales Taxes 7% of control device cost (A) 379,316

Freight 5% of control device cost (A) 291,781

Purchased Equipment Total (B) 22% 7,090,285

Installation

Foundations & supports 12% of purchased equip cost (B) 850,834

Handling & erection 40% of purchased equip cost (B) 2,836,114

Electrical 1% of purchased equip cost (B) 70,903

Piping 30% of purchased equip cost (B) 2,127,085

Insulation 1% of purchased equip cost (B) 70,903

Painting 1% of purchased equip cost (B) 70,903

Installation Subtotal Standard Expenses 85% 6,026,742

Total Direct Capital Cost, DC 13,117,027

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 354,514

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 354,514

Start-up 1% of purchased equip cost (B) 70,903

Performance test 1% of purchased equip cost (B) 70,903

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 212,709

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 14,180,569

Retrofit multiplier560% of TCI 8,508,342

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 28,888,911

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization 484,289

Water 0.28 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization 89,522

WW Treat Neutralization 1.69 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization 442,176

Lime 90.33 $/ton, 29 lb/hr, Annual Operating Hours, 93% utilization 9,703

Total Annual Direct Operating Costs 1,113,462

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 283,611

Property tax (1% total capital costs) 1% of total capital costs (TCI) 141,806

Insurance (1% total capital costs) 1% of total capital costs (TCI) 141,806

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,726,909

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU021 Wet Scrubber 9/1/2006 Page 17 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 7: 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 772,000 8.55 0.7 - 1,103.2 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 29,336 gpm 1 60 0.7 - 472.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 724 gpm 1 60 0.7 - 11.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1587.6

Reagent Use & Other Operating Costs

Caustic Use 30.00 lb/hr SO2 2.50 lb NaOH/lb SO2 75.00 lb/hr Caustic

Lime Use 30.00 lb/hr SO2 0.96 lb Lime/lb SO2 28.88 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

29,336 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 724 gpm

Evaporation Loss4 = 137.66 gpm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 15% of Operator Costs 3,623

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1587.6 kW-hr 11,811,923 484,289 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 724.4 gpm 323,362 89,522 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 586.7 gpm 261,912 442,176 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization

Lime 90.3 $/ton 28.9 lb/hr 107 9,703 $/ton, 29 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

E:\BART\HTC\HTC Control Costs.xls

EU021 Wet Scrubber 9/1/2006 Page 18 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 8: SOx Control - Wet Scrubber

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M

Standardized Flow Rate 654,869 scfm @ 32o F

Expected Utilization Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4%

Annual Interest Rate 7.0% Actual Flow Rate7439.85859 772,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs (1)

 Purchased Equipment (A) 5,835,625

 Purchased Equipment Total (B) 22% of control device cost (A) 7,090,285

 Installation - Standard Costs 85% of purchased equip cost (B) 6,026,742

 Installation - Site Specific Costs 6,200,000

 Installation Total 6,026,742

 Total Direct Capital Cost, DC 13,117,027

 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 28,888,911

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,113,462

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

Actual

Emission Control Cost Calculation Emisssions

Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 558.0 2,497.7 0% 2497.7 - NA

Sulfur Dioxide (SO2) 30.0 202.2 60% 80.9 121.3 36,762

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.

E:\BART\HTC\HTC Control Costs.xls

EU022 Wet Scrubber 9/1/2006 Page 19 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 8: SOx Control - Wet Scrubber

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,835,625

Instrumentation 10% of control device cost (A) 583,563

MN Sales Taxes 7% of control device cost (A) 379,316

Freight 5% of control device cost (A) 291,781

Purchased Equipment Total (B) 22% 7,090,285

Installation

Foundations & supports 12% of purchased equip cost (B) 850,834

Handling & erection 40% of purchased equip cost (B) 2,836,114

Electrical 1% of purchased equip cost (B) 70,903

Piping 30% of purchased equip cost (B) 2,127,085

Insulation 1% of purchased equip cost (B) 70,903

Painting 1% of purchased equip cost (B) 70,903

Installation Subtotal Standard Expenses 85% 6,026,742

Total Direct Capital Cost, DC 13,117,027

Indirect Capital Costs

Engineering, supervision 5% of purchased equip cost (B) 354,514

Construction & field expenses 0% of purchased equip cost (B) 0

Contractor fees 5% of purchased equip cost (B) 354,514

Start-up 1% of purchased equip cost (B) 70,903

Performance test 1% of purchased equip cost (B) 70,903

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 212,709

Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 1,063,543

Total Capital Investment (TCI) = DC + IC 14,180,569

Retrofit multiplier560% of TCI 8,508,342

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 28,888,911

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 37.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization 484,289

Water 0.28 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization 89,522

WW Treat Neutralization 1.69 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization 442,176

Lime 90.33 $/ton, 29 lb/hr, Annual Operating Hours, 93% utilization 9,703

Total Annual Direct Operating Costs 1,113,462

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 283,611

Property tax (1% total capital costs) 1% of total capital costs (TCI) 141,806

Insurance (1% total capital costs) 1% of total capital costs (TCI) 141,806

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,726,909

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,346,795

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,460,257

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU022 Wet Scrubber 9/1/2006 Page 20 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 8: 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 772,000 8.55 0.7 - 1,103.2 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 29,336 gpm 1 60 0.7 - 472.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 724 gpm 1 60 0.7 - 11.7 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Total 1587.6

Reagent Use & Other Operating Costs

Caustic Use 30.00 lb/hr SO2 2.50 lb NaOH/lb SO2 75.00 lb/hr Caustic

Lime Use 30.00 lb/hr SO2 0.96 lb Lime/lb SO2 28.88 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

29,336 gpm

Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 724 gpm

Evaporation Loss4 = 137.66 gpm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Supervisor 15% of Op. NA 15% of Operator Costs 3,623

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, Annual Operating Hours

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 1587.6 kW-hr 11,811,923 484,289 $/kwh, 1,588 kW-hr, Annual Operating Hours, 93% utilization

Water 0.28 $/kgal 724.4 gpm 323,362 89,522 $/kgal, 724 gpm, Annual Operating Hours, 93% utilization

WW Treat Neutralization 1.69 $/kgal 586.7 gpm 261,912 442,176 $/kgal, 587 gpm, Annual Operating Hours, 93% utilization

Lime 90.3 $/ton 28.9 lb/hr 107 9,703 $/ton, 29 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

E:\BART\HTC\HTC Control Costs.xls

EU022 Wet Scrubber 9/1/2006 Page 21 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 9: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M

Desgin Capacity 360 MMBtu/hr Standardized Flow Rate 654,869 scfm @ 32o F

Expected Utiliztion Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4%

Annual Interest Rate 7.0% Actual Flow Rate 772,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs EPRI Correlation

 Purchased Equipment (A) 28,544,643

 Purchased Equipment Total (B) SCR Only 2,643,899

 Installation - Standard Costs 15% of purchased equip cost (B) SCR Only 4,678,281

 Installation - Site Specific Costs 6,200,000

 Installation Total 33,367,982

 Total Direct Capital Cost, DC 35,866,823

 Total Indirect Capital Costs, IC 9% of purchased equip cost (B) 9,413,148

Total Capital Investment (TCI) = DC + IC SCR + Reheat 80,957,276

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 31,608,726

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 11,038,886

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 42,647,613

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,497.7 111.6 0.31 415.2 2,082.6 20,478

Notes & Assumptions

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

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 Control Efficiency = 80% reduction

12 Site specific electricity costs

13 Catalyst replacement every 3 years. This requires an additional 2 week outage per 3 year outage cycle, annualized to 4.7 days.

E:\BART\HTC\HTC Control Costs.xls

EU020 SCR EU020 SCR 22 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 9: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 26,802,482

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,742,161

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 28,544,643

Indirect Installation

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

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

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

Site Specific-Other 9% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 4,678,281

Total Plant Cost D A + B + C 35,866,823

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

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 881,976

Inventory Capital (I) Reagent Vol * $/gal 299,172

Total Capital Investment (TCI) = DC + IC D + E + F + G + I 45,279,971

Retrofit multiplier3

60% of TCI 27,167,982

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 78,647,953

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

NA for capital recovery cost because costs are included as annual operating costs.

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 1,179,719

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 9,489 kW-hr, 8000 hr/yr, 93% utilization 2,894,422

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 64.71 Catalyst Replacement 4,956,497

NA NA - 

Ammonia 0.12 $/lb, 8,816 lb/hr, 8000 hr/yr, 93% utilization 7,910,014

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 17,051,743

Indirect Operating Costs

Overhead 60% of total labor and material costs 106,138

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,572,959

Property tax (1% total capital costs) 1% of total capital costs (TCI) 786,480

Insurance (1% total capital costs) 1% of total capital costs (TCI) 786,480

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 7,423,810

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 10,675,866

Total Annual Cost (Annualized Capital Cost + Operating Cost) 27,727,609

E:\BART\HTC\HTC Control Costs.xls

EU020 SCR EU020 SCR 23 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 9: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 4,244 Plant Cap kW A 435,325

Est power platn eff 35% Unc Nox lb/mmBtuB 1.55 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 435,325 Capital Cost $/kW D $61.57 $26,802,481.70 Total SCR Equipment

Uncontrolled Nox t/y 2,497.7 Fixed O&M E $176,896.38

Annual Operating Hrs 8000 Variable O&M F $779,288.84

Uncontrolled Nox lb/mmBtu 1.550 Ann Cap Factor G 0.82

Heat Input mmBtu/hrH 6,000

SCR Capital Cost

Duty 4,244 MMBtu/hr Catalyst Area 2,047 ft2979 f (h SCR)

Q flue gas 1,965,552 acfm Rx Area 2,355 -15 f (h NH3

)

NOx Cont Eff 80% Rx Height 48.5 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 1.55 lb/MMBtu n layer 36 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 38.4 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 37 layers 55,148,785 f (vol catalyst)

Temperature 120 Deg F h SCR 191 ft f (h SCR)

Catalyst Volume 229,787 ft3

New/Retrofit R N or R 

Electrical Use

Duty 4,244 MMBtu/hr kW

NOx Cont Eff 80% Power 9,488.7

NOx in 1.55 lb/MMBtu

n catalyst layers 37 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 9488.7

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

2557 lb/hr Neat 1177.7 gal/hr

29% solution Volume 14 day inventory 395,704 gal $299,172 Inventory Cost

8816 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.31

Nitrous Oxides (NOx) 2,497.7 1.6 558.00

Actual dscf/MMBtu 108,457

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 4,244 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 1,179,719 % of Total Capital Investment

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 9488.7 kW-hr 70,595,665 2,894,422 $/kwh, 9,489 kW-hr, 8000 hr/yr, 93% utilization

Cat. Replacement [14] 65 $/ft3 76,596 4,956,497 Catalyst Replacement

7 Ammonia 0.12 $/lb 8816 lb/hr 65,589,231 7,910,014 $/lb, 8,816 lb/hr, 8000 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

E:\BART\HTC\HTC Control Costs.xls

EU020 SCR EU020 SCR 24 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 10: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 1

Emission Unit Number EU 020 Stack/Vent Number SV021M-SV024M Chemical Engineering

Desgin Capacity 360 MMBtu/hr Standardized Flow Rate 654,869 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 120 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.4% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 772,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 702,786 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 737,840

 Purchased Equipment Total (B) 22% of control device cost (A) 896,476

 Installation - Standard Costs 30% of purchased equip cost (B) 268,943

 Installation - Site Specific Costs NA

 Installation Total 268,943

 Total Direct Capital Cost, DC 1,165,419

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 277,908

Total Capital Investment (TCI) = DC + IC 2,309,322

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,556,983

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 363,020

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,920,003

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 

E:\BART\HTC\HTC Control Costs.xls

EU020 Reheat EU020 Reheat 25 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 10: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 737,840

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

Instrumentation 10% of control device cost (A) 73,784

MN Sales Taxes 6.5% of control device cost (A) 47,960

Freight 5% of control device cost (A) 36,892

Purchased Equipment Total (B) 22% 896,476

Installation

Foundations & supports 8% of purchased equip cost (B) 71,718

Handling & erection 14% of purchased equip cost (B) 125,507

Electrical 4% of purchased equip cost (B) 35,859

Piping 2% of purchased equip cost (B) 17,930

Insulation 1% of purchased equip cost (B) 8,965

Painting 1% of purchased equip cost (B) 8,965

Installation Subtotal Standard Expenses 30% 268,943

Site Preparation, as required Included in SCR 0

Buildings, as required Included in SCR 0

Site Specific - Other Included in SCR 0

Total Site Specific Costs NA

Installation Total 268,943

Total Direct Capital Cost, DC 1,165,419

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 89,648

Construction & field expenses 5% of purchased equip cost (B) 44,824

Contractor fees 10% of purchased equip cost (B) 89,648

Start-up 2% of purchased equip cost (B) 17,930

Performance test 1% of purchased equip cost (B) 8,965

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 26,894

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 277,908

Total Capital Investment (TCI) = DC + IC 1,443,327

Retrofit multiplier3

60% of TCI 865,996

Total Capital Investment (TCI) Retrofit Installed 2,309,322

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,309,322

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 2,860 kW-hr, 8000 hr/yr, 93% utilization 872,494

Natural Gas 7.41 $/mscf, 4,110 scfm, 8000 hr/yr, 93% utilization 13,596,717

Total Annual Direct Operating Costs 14,556,983

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 46,186

Property tax (1% total capital costs) 1% of total capital costs (TCI) 23,093

Insurance (1% total capital costs) 1% of total capital costs (TCI) 23,093

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 217,984

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 363,020

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,920,003

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU020 Reheat EU020 Reheat 26 of 42
Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Equipment Life

Replacement Parts & Equipment:

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 772,000 19 0.6 2,860.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 772,000 23 0.6 3,462.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2860.3

Operating Cost Calculations

Reagent Use & Other Operating Costs Oxidizers - NA

Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 

Operating Labor

48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 3,623 15% of Operator Costs

Maint Labor 

Maintenance

60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Electricity 

Utilities, Supplies, Replacements & Waste Management

0.041 $/kwh 2860.3 kW-hr 21,280,334 872,494 $/kwh, 2,860 kW-hr, 8000 hr/yr, 93% utilization

Natural Gas 7.41 $/mscf 4,110 scfm 1,834,915 13,596,717 $/mscf, 4,110 scfm, 8000 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

EU020 Reheat

E:\BART\HTC\HTC Control Costs.xls

EU020 Reheat 27 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 10: NOx Control - Selective Catalytic Reduction with Reheat

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

Auxiliary Fuel Use Equation 3.19 

Twi 120 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 561 Deg F - Temperature of waste gas out of heat recovery

Tfo 309 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 702,786 scfm - Flow of waste gas 

Qaf 4,110 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 706,897 scfm Flue Gas Cost in 1989 $'s $618,834

Current Cost Using CHE Plant Cost Index $737,840

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)

E:\BART\HTC\HTC Control Costs.xls

EU020 Reheat EU020 Reheat 28 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 11: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 2

Emission Unit Number EU 021 Stack/Vent Number SV025M-SV028M Chemical Engineering

Desgin Capacity 360 MMBtu/hr Standardized Flow Rate 674,379 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 120 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.1% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 795,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 672,448 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Year

 Direct Capital Costs EPRI Correlation 1998

 Purchased Equipment (A) 2005 26,715,086

 Purchased Equipment Total (B) 0% of control device cost (A) SCR Only 28,451,567

 Installation - Standard Costs 9% of purchased equip cost (B) SCR Only 2,643,899

 Installation - Site Specific Costs 6,200,000

 Installation Total 33,271,915

 Total Direct Capital Cost, DC 35,759,785

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 45,119,858

Total Capital Investment (TCI) = DC + IC SCR + Reheat 78,666,631

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 29,221,312

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 11,000,707

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 40,222,018

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,143.5 92.6 0.26 344.5 1,799.1 22,357

Notes & Assumptions

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

2 For Calculation purposes, duty reflects increased flow rate, not actual duty.

3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2

4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43

5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31

8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46

11 Control Efficiency = 80% reduction 

12 Site-specific electricity cost, 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.

E:\BART\HTC\HTC Control Costs.xls

EU021 SCR EU021 SCR 29 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 11: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 26,715,086

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,736,481

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 28,451,567

Indirect Installation

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

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

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

Site Specific-Other 9% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 4,664,320

Total Plant Cost D A + B + C 35,759,785

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

Pre Production Costs (G) 2% of (D+E)) 879,836

Inventory Capital Reagent Vol * $/gal 248,237

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 45,119,858

Retrofit multiplier360% of TCI 27,071,915

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 78,391,773

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 1,175,877

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 8,948 kW-hr, 8000 hr/yr, 93% utilization 2,729,381

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 64.71 Catalyst Replacement 4,645,603

NA NA - 

Ammonia 0.12 $/lb, 7,315 lb/hr, 8000 hr/yr, 93% utilization 6,563,327

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 15,225,278

Indirect Operating Costs

Overhead 60% of total labor and material costs 105,792

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,567,835

Property tax (1% total capital costs) 1% of total capital costs (TCI) 783,918

Insurance (1% total capital costs) 1% of total capital costs (TCI) 783,918

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 7,399,629

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 10,641,091

Total Annual Cost (Annualized Capital Cost + Operating Cost) 25,866,370

E:\BART\HTC\HTC Control Costs.xls

EU021 SCR EU021 SCR 30 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 11: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 4,244 Plant Cap kWA 435,325

Est power platn eff 35% Unc Nox lb/mmBtu B 1.29 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 435,325 Capital Cost $/kW D $61.37 $26,715,086.02 Total SCR Equipment

Uncontrolled Nox t/y 2,143.5 Fixed O&M E $176,319.57

Annual Operating Hrs 8000 Variable O&MF $772,486.47

Uncontrolled Nox lb/mmBtu 1.286 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

SCR Capital Cost

Duty 4,244 MMBtu/hr Catalyst Area 2,047 ft2921 f (h SCR)

Q flue gas 1,965,552 acfm Rx Area 2,355 -15 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 48.5 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 1.29 lb/MMBtu n layer 34 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 36.1 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 35 layers 51,689,603 f (vol catalyst)

Temperature 120 Deg F h SCR 181 ft f (h SCR)

Catalyst Volume 215,373 ft3

New/Retrofit R N or R 

Electrical Use

Duty 4,244 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 8,947.6

NOx in 1.29 lb/MMBtu

n catalyst layers 35 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 8947.6

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

2121 lb/hr Neat 977.2 gal/hr

29% solution Volume 14 day inventory 328,335 gal $248,237 Inventory Cost

7315 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.26

Nitrous Oxide 2,143.5 1.3 463.00

Actual dscf/MMBtu 108,457

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 4,244 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 1,175,877 % of Total Capital Investment

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 8947.6 kW-hr 66,570,279 2,729,381 $/kwh, 8,948 kW-hr, 8000 hr/yr, 93% utilization

Cat. Replacement [14] 65 $/ft3 71,791 4,645,603 Catalyst Replacement

7 Ammonia 0.12 $/lb 7315 lb/hr 54,422,606 6,563,327 $/lb, 7,315 lb/hr, 8000 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

E:\BART\HTC\HTC Control Costs.xls

EU021 SCR EU021 SCR 31 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 12: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 2

Emission Unit Number EU 021 Stack/Vent Number SV025M-SV028M Chemical Engineering

Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 674,379 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 120 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,000 Hours Moisture Content 7.1% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 795,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 672,448 scfm @ 68o F

Dry Std Flow Rate 650,745 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 729,745

 Purchased Equipment Total (B) 22% of control device cost (A) 886,641

 Installation - Standard Costs 30% of purchased equip cost (B) 265,992

 Installation - Site Specific Costs NA

 Installation Total 265,992

 Total Direct Capital Cost, DC 1,152,633

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 274,859

Total Capital Investment (TCI) = DC + IC 2,283,986

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 13,996,033

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 359,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,355,648

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 

E:\BART\HTC\HTC Control Costs.xls

EU021 Reheat EU021 Reheat 32 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 12: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 729,745

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

Instrumentation 10% of control device cost (A) 72,975

MN Sales Taxes 6.5% of control device cost (A) 47,433

Freight 5% of control device cost (A) 36,487

Purchased Equipment Total (B) 22% 886,641

Installation

Foundations & supports 8% of purchased equip cost (B) 70,931

Handling & erection 14% of purchased equip cost (B) 124,130

Electrical 4% of purchased equip cost (B) 35,466

Piping 2% of purchased equip cost (B) 17,733

Insulation 1% of purchased equip cost (B) 8,866

Painting 1% of purchased equip cost (B) 8,866

Installation Subtotal Standard Expenses 30% 265,992

Site Preparation, as required Included in SCR 0

Buildings, as required Included in SCR 0

Site Specific - Other Included in SCR 0

Total Site Specific Costs NA

Installation Total 265,992

Total Direct Capital Cost, DC 1,152,633

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 88,664

Construction & field expenses 5% of purchased equip cost (B) 44,332

Contractor fees 10% of purchased equip cost (B) 88,664

Start-up 2% of purchased equip cost (B) 17,733

Performance test 1% of purchased equip cost (B) 8,866

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 26,599

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 274,859

Total Capital Investment (TCI) = DC + IC 1,427,491

Retrofit multiplier360% of TCI 856,495

Total Capital Investment (TCI) Retrofit Installed 2,283,986

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,283,986

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 2,945 kW-hr, 8000 hr/yr, 93% utilization 898,488

Natural Gas 7.41 $/mscf, 3,933 scfm, 8000 hr/yr, 93% utilization 13,009,773

Total Annual Direct Operating Costs 13,996,033

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 45,680

Property tax (1% total capital costs) 1% of total capital costs (TCI) 22,840

Insurance (1% total capital costs) 1% of total capital costs (TCI) 22,840

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 215,592

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 359,615

Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,355,648

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU021 Reheat EU021 Reheat 33 of 42
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Insert attachment name> Emission Control Cost Analysis

<Insert Table Name>: - Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 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 795,000 19 0.6 2,945.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 795,000 23 0.6 3,565.6 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 2945.5

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 3,623 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 2945.5 kW-hr 21,914,334 898,488 $/kwh, 2,945 kW-hr, 8000 hr/yr, 93% utilization

Natural Gas 7.41 $/mscf 3,933 scfm 1,755,705 13,009,773 $/mscf, 3,933 scfm, 8000 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

E:\BART\HTC\HTC Control Costs.xls

EU021 Reheat EU021 Reheat 34 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 12: NOx Control - Selective Catalytic Reduction with Reheat

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

Auxiliary Fuel Use Equation 3.19 

Twi 120 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 561 Deg F - Temperature of waste gas out of heat recovery

Tfo 309 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 672,448 scfm - Flow of waste gas 

Qaf 3,933 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 676,381 scfm Flue Gas Cost in 1989 $'s $612,045

Current Cost Using CHE Plant Cost Index $729,745

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)

E:\BART\HTC\HTC Control Costs.xls

EU021 Reheat EU021 Reheat 35 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 13: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 3

Emission Unit Number EU 022 Stack/Vent Number SV029M-SV032M

Desgin Capacity 360 MMBtu/hr Standardized Flow Rate 701,524 scfm @ 32o F

Expected Utiliztion Rate 93% Temperature 120 Deg F

Expected Annual Hours of Operation 8,000 Hours Moisture Content 8.5%

Annual Interest Rate 7.0% Actual Flow Rate 827,000 acfm

Expected Equipment Life 20 yrs Standardized Flow Rate 752,855 scfm @ 68o F

Dry Std Flow Rate 689,013 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 27,816,716

 Purchased Equipment Total (B) SCR Only 29,624,802

 Installation - Standard Costs 9% of purchased equip cost (B) SCR Only 2,643,899

 Installation - Site Specific Costs 6,200,000

 Installation Total 34,138,755

 Total Direct Capital Cost, DC 37,109,006

 Total Indirect Capital Costs, IC 9,455,585

Total Capital Investment (TCI) = DC + IC SCR + Reheat 83,052,744

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 29,360,788

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 11,324,519

Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 40,685,307

Emission Control Cost Calculation

Baseline Predicted Limit Cont. Emis. Cont Emis Reduction Cont Cost

Pollutant Emis. T/yr lb/hr lb/MMBtu T/yr T/yr $/Ton Rem

Nitrous Oxides (NOx) 2,247.1 111.6 0.31 415.2 1,832.0 22,208

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

E:\BART\HTC\HTC Control Costs.xls

EU022 SCR EU022 SCR 36 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 13: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 27,816,716

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) 1,808,087

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 29,624,802

Indirect Installation

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

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

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

Site Specific-Other 9% Replacement Power, two weeks 2,643,899

Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899

Project Contingeny ( C) 15% of (A + B) 4,840,305

Total Plant Cost D A + B + C 37,109,006

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

Pre Production Costs (G) 2% of (D+E)) 906,820

Inventory Capital Reagent Vol * $/gal 316,765

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 46,564,591

Retrofit multiplier360% of TCI 27,938,755

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 80,703,346

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr 96,600

Supervisor 15% 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.50 % of Total Capital Investment 1,210,550

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 10,047 kW-hr, 8000 hr/yr, 93% utilization 3,064,634

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Cat. Replacement [14] 64.51 Catalyst Replacement 1,011,517

NA NA - 

Ammonia 0.12 $/lb, 9,334 lb/hr, 8000 hr/yr, 93% utilization 8,375,176

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 13,772,967

Indirect Operating Costs

Overhead 60% of total labor and material costs 110,154

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,614,067

Property tax (1% total capital costs) 1% of total capital costs (TCI) 807,033

Insurance (1% total capital costs) 1% of total capital costs (TCI) 807,033

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 7,617,825

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 10,956,113

Total Annual Cost (Annualized Capital Cost + Operating Cost) 24,729,080

E:\BART\HTC\HTC Control Costs.xls

EU022 SCR EU022 SCR 37 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 13: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Equivalent Duty 4,494 Plant Cap kWA 460,925

Est power platn eff 35% Unc Nox lb/mmBtu B 1.55 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 460,925 Capital Cost $/kW D $60.35 $27,816,715.78 Total SCR Equipment

Uncontrolled Nox t/y 2,247.1 Fixed O&M E $183,590.32

Annual Operating Hrs 8000 Variable O&MF $818,783.80

Uncontrolled Nox lb/mmBtu 1.550 Ann Cap Factor G 0.82

Heat Input mmBtu/hr H 6,000

SCR Capital Cost

SCR Capital Cost per EPRI Method 76,792,214

Duty 4,494 MMBtu/hr Catalyst Area 2,168 ft2

979 f (h SCR)

Q flue gas 2,081,140 acfm Rx Area 2,493 -17 f (h NH3

)

NOx Cont Eff 80% (as faction) Rx Height 49.9 ft 0 f (h New) new= -728, Retrofit = 0

NOx in 1.55 lb/MMBtu n layer 36 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 38.4 ft 127 f (h Bypass)

Fuel Sulfur 0.67 wt % (as %) n total 37 layers 58,391,904 f (vol catalyst)

Temperature 120 Deg F h SCR 191 ft f (h SCR)

Catalyst Volume 243,300 ft3

New/Retrofit R N or R 

Electrical Use

Duty 4,494 MMBtu/hr kW

NOx Cont Eff 80% (as faction) Power 10,046.7

NOx in 1.55 lb/MMBtu

n catalyst layers 37 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 10046.7

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft3 Density

2707 lb/hr Neat 1246.9 gal/hr

29% solution Volume 14 day inventory 418,974 gal $316,765 Inventory Cost

9334 lb/hr

Design Basis Baseline Emis. Baseline Emis.Max Emis. (Model) Control Eff (%) Cont. Emis (lb/MMBtu)

T/yr lb/MMBtu lb/hr 80% 0.31

Nitrous Oxides (NOx) 2,247.1 1.6 526.00

Actual dscf/MMBtu 114,836

Method 19 Factor dscf/MMBtu 9,200

Adjusted Duty 4,494 MMBtu/hr

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 2.0 hr/8 hr shift 2,000 96,600 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 15% of Operator Costs 14,490

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 1,210,550 % of Total Capital Investment

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

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 10046.7 kW-hr 74,747,163 3,064,634 $/kwh, 10,047 kW-hr, 8000 hr/yr, 93% utilization

Cat. Replacement [14] 65 $/MW-hr 140.0 mw 112 1,011,517 Catalyst Replacement

7 Ammonia 0.12 $/lb 9334 lb/hr 69,446,318 8,375,176 $/lb, 9,334 lb/hr, 8000 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

E:\BART\HTC\HTC Control Costs.xls

EU022 SCR EU022 SCR 38 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 14: NOx Control - Selective Catalytic Reduction with Reheat

Operating Unit: Pellet Indurating Furnace Line No 3

Emission Unit Number EU 022 Stack/Vent Number SV029M-SV032M Chemical Engineering

Desgin Capacity 190 MMBtu/hr Standardized Flow Rate 701,524 scfm @ 32o F Chemical Plant Cost Index

Expected Utiliztion Rate 93% Temperature 120 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,000 Hours Moisture Content 8.5% 2005 465

Annual Interest Rate 7.0% Actual Flow Rate 827,000 acfm Inflation Adj 1.19

Expected Equipment Life 20 yrs Standardized Flow Rate 752,855 scfm @ 68o F

Dry Std Flow Rate 689,013 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) 750,645

 Purchased Equipment Total (B) 22% of control device cost (A) 912,033

 Installation - Standard Costs 30% of purchased equip cost (B) 273,610

 Installation - Site Specific Costs NA

 Installation Total 273,610

 Total Direct Capital Cost, DC 1,185,644

 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 282,730

Total Capital Investment (TCI) = DC + IC 2,349,398

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,587,821

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 368,406

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,956,227

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 

E:\BART\HTC\HTC Control Costs.xls

EU022 Reheat EU022 Reheat 39 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 14: NOx Control - Selective Catalytic Reduction with Reheat

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 750,645

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

Instrumentation 10% of control device cost (A) 75,064

MN Sales Taxes 6.5% of control device cost (A) 48,792

Freight 5% of control device cost (A) 37,532

Purchased Equipment Total (B) 22% 912,033

Installation

Foundations & supports 8% of purchased equip cost (B) 72,963

Handling & erection 14% of purchased equip cost (B) 127,685

Electrical 4% of purchased equip cost (B) 36,481

Piping 2% of purchased equip cost (B) 18,241

Insulation 1% of purchased equip cost (B) 9,120

Painting 1% of purchased equip cost (B) 9,120

Installation Subtotal Standard Expenses 30% 273,610

Site Preparation, as required Included in SCR 0

Buildings, as required Included in SCR 0

Site Specific - Other Included in SCR NA

Total Site Specific Costs NA

Installation Total 273,610

Total Direct Capital Cost, DC 1,185,644

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 91,203

Construction & field expenses 5% of purchased equip cost (B) 45,602

Contractor fees 10% of purchased equip cost (B) 91,203

Start-up 2% of purchased equip cost (B) 18,241

Performance test 1% of purchased equip cost (B) 9,120

Model Studies of purchased equip cost (B) 0

Contingencies 3% of purchased equip cost (B) 27,361

Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 282,730

Total Capital Investment (TCI) = DC + IC 1,468,374

Retrofit multiplier360% of TCI 881,024

Total Capital Investment (TCI) Retrofit Installed 2,349,398

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,349,398

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 48.30 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 24,150

Supervisor 15% 15% of Operator Costs 3,623

Maintenance

Maintenance Labor 60.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 30,000

Maintenance Materials 100% of maintenance labor costs 30,000

Utilities, Supplies, Replacements & Waste Management

Electricity 0.04 $/kwh, 3,064 kW-hr, 8000 hr/yr, 93% utilization 934,653

Natural Gas 7.41 $/mscf, 4,403 scfm, 8000 hr/yr, 93% utilization 14,565,395

Total Annual Direct Operating Costs 15,587,821

Indirect Operating Costs

Overhead 60% of total labor and material costs 52,664

Administration (2% total capital costs) 2% of total capital costs (TCI) 46,988

Property tax (1% total capital costs) 1% of total capital costs (TCI) 23,494

Insurance (1% total capital costs) 1% of total capital costs (TCI) 23,494

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 221,767

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 368,406

Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,956,227

See Summary page for notes and assumptions

E:\BART\HTC\HTC Control Costs.xls

EU022 Reheat EU022 Reheat 40 of 42
Cleveland Cliffs Incorporated: United Taconite

BART Report - <Insert attachment name> Emission Control Cost Analysis

<Insert Table Name>: - Summary of Utility, Chemical and Supply Costs

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst: Catalyst

Equipment Life 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 827,000 19 0.6 3,064.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Blower, Catalytic 827,000 23 0.6 3,709.1 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1

Oxidizer Type thermal (catalytic or thermal) 3064.0

Reagent Use & Other Operating Costs Oxidizers - NA

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 93%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 48.30 $/Hr 0.5 hr/8 hr shift 500 24,150 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor 15% of Op. NA 3,623 15% of Operator Costs

Maintenance

Maint Labor 60.00 $/Hr 0.5 hr/8 hr shift 500 30,000 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 30,000 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.041 $/kwh 3064.0 kW-hr 22,796,420 934,653 $/kwh, 3,064 kW-hr, 8000 hr/yr, 93% utilization

Natural Gas 7.41 $/mscf 4,403 scfm 1,965,640 14,565,395 $/mscf, 4,403 scfm, 8000 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

E:\BART\HTC\HTC Control Costs.xls

EU022 Reheat EU022 Reheat 41 of 42
Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis

Table 14: NOx Control - Selective Catalytic Reduction with Reheat

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

Auxiliary Fuel Use Equation 3.19 

Twi 120 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 561 Deg F - Temperature of waste gas out of heat recovery

Tfo 309 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 752,855 scfm - Flow of waste gas 

Qaf 4,403 scfm - Flow of auxiliary fuel

Year 2005 Inflation Rate 3.0%

Cost Calculations 757,258 scfm Flue Gas Cost in 1989 $'s $629,573

Current Cost Using CHE Plant Cost Index $750,645

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)

E:\BART\HTC\HTC Control Costs.xls

EU022 Reheat EU022 Reheat 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

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

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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
N

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Hibbtac Aerial Photo

100

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Meters
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 Hibbing Taconite Company (HTC) 

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. 
Taconite BART Analysis

NOx Control

Available and Applicable Review

Step 1 Step 2

This table is part of the Taconi

distributed 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 i

5 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 Taconi

distributed 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 combustio17 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 Taconi

distributed 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 polluta

destroyed.

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 Taconi

distributed 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 Taconi

distributed 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 ri

giving 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 lis

SO2 control, which lb/MMBtu. Droppeflexibility to require bypasses aren't BABART.

BART(proposed rule)

0.2 lb/MMBtu for N

Recognizes that so

get this level. For t

cost vs. visibility va

CAIR(using IPM) 1000 1500CAIR ( 2009 in 1999$) 900 2400CAIR ( 2015 in 1999$) 1800 3000CAIR (depending on Nat'l emissions) 1200 - 3000 1400- 2100

This was modeled 

Retrofitting Updatinmarginal values.

Kammer_EPA_Decision.doc Kammer Decision over 1000 over 1000

LADCO_MidwestRPO_Boiler Analysis.pdf LADCO/Midwest RPO 1240 to 3822 607 to 4493MANE-VU_BART_Control_Assessment.pdf MANE-VU 200-500 200-1500Bowers_vs_SWAPCA.txt Bowers vs SWAPCA 300 300 1000 1000

954-1134 was rule

for SO2. This did cSections XVII to XI

WRAP 3000EPA - Referenced by Wrap

References EPA-6

<$500/ton, Moderaover $3000/ton

WRAP_Trading_program_methodology.pdf

Avg. Expected Values ($/ton) Limiting/Marginal values ($/ton)

MidwestRPO_rept_referencing_CAIR.pdfFR_Notice_5MAY04_Proposed_Rule.pdfFR_Notice_6JULY05_Final_Rule.pdf

Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\HTC\Appendix E - Table of Costs_per_ton.xls