# Hibbing Taconite Analysis of B est 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 Impa cts for BART Eligible Units ...............................................11 4.A MPCA Subject-to-BART Modeling .........................................................................................11 4.B Facility Baselin e Modeling ..................................................................................................... ..12 4.C Facility Baseline M odeling 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.................................................................................................4 3
7. Select BART.................................................................................................................... ...................44

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# List of Tables

Table 3-1 Summary Table of BART-Eligible Units Subj ect to a Streamlined BART Analysis.... 10 Table 4-1 Baseline Conditions Modeling Input Data a nd the Basis for 24-hour Emissions Data . 13 Table 4-2 Baseline Visibility Modeling Results........................................................................... 17 Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availa bility, Applicability, and Technical Feasibility.................................................................................................... 23 Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness ......................................... 24 Table 5-3 SO 2 

# Control Cost Summary ......................................................................................... 25 Table 5-4 Indurating Furnace NO x 

# Control Technology – Availa bility, Applicability, and Technical Feasibility.................................................................................................... 39 Table 5-5 Indurating Furnace NO x 

# Control Technology Effectiveness......................................... 40 Table 5-6 NO x 

# 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 Av ailable 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 th e Iron Range in northern Minnesota, with mining and processing facilities near the towns of Chis holm and Hibbing. At its facility, HTC mines and processes iron ore to produce pellets used in stee l making. Within the pellet making process, there are many pieces of equipment with pollution cont rol devices to reduce em issions. 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 handlin g and/or storage units for as ore, product, and additives. Preliminary visibility modeling condu cted 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 re port describes the background and methods for the
selection of the Best Av ailable Retrofit Te chnology (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 contro l equipment on the furnace lines includes a wet scrubber designed to control of part iculate matter (PM); however some collateral cont rol of sulfur dioxide (SO 2 

# ) is also achieved. A dispersion mode ling sequence of CALM ET, CALPUFF, and CALPOST was used to assess the visibility impacts of the baseline emissions 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 crit eria, HTC establishes the following as BART:

• SO 2 

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

• NO x 

# emissions will be reduced by energy efficiency projects implemented after the BART baseline date. In fall of 2005, the Line 3 pr oject was implemented, wh ich 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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# reductions on Line 2 are expected to be 12%. Because a portion of NO x 

# formed during the indurating process is fuel bound NO x 

# , it is reasonable to expect that because fuel usage was reduced, the amount of NO x 

# emissions are also reduced. In addition, because the changes reduced hot spots in the furnaces and provi ded a more even temperature distribution throughout the furnaces, NO x 

# 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) standard 1



# .
The proposed BART controls will result in visibility improvements of 13% on the worst visibility days and reduce the number of days that the visi bility contribution from HTC is above 0.5 deciviews (dv) by 31 days. The NO x 

# reductions at HTC represent a signifi cant contribution to the default glide path goal of improving visibility by one to two pe rcent per year. This leve l 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 impair ment in our nation’s largest national parks and wilderness (“Class I”) areas in July 1999. This rule is commonly known as the “Regional Haze Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 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 ar eas – the Boundary Waters Canoe Area Wilderness and Voyageurs National Park. In addition, emissi ons from Minnesota may contribute to visibility impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney Wilderness Area. By December 2007, MPCA mu st submit to U.S. EPA a Regional Haze State Implementation Plan (SIP) that identifies sources that cause or contribute to vi sibility impairment in these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward reaching the 2018 visibility goal for each of the state’s Class I areas.

One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put in place between 1962 and 1977 must conduct a Be st Available Retrofit Technology (BART) analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to determine if a technology should be installed to improve visibility in Class I areas. The chosen technology is referred to as the BART controls, or simply BART. The SIP must require BART on all BART-eligible sources and manda te a plan to achieve natural background visibility by 2064. Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. 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 fo r BART sources enforceable through rule s, administrative or ders or Title V permit amendments.

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



# By definition, reasonable progress means that the vi sibility 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 pa th 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-ai r quality impacts. 

# 2.A BART Eligibility BART eligibility is established on the basis of thre e criteria. In order to be BART-eligibl e, sources must meet the following three conditions:

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# 1. Contain emission units in one or more of the 26 listed source categorie s under the PSD rules (e.g., taconite ore processing plants, fossil-fue l-fired steam electric plants larger than 250 MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning plants, sulfur recovery plants, etc.);
2. Were in existence on August 7, 1977, but we re not in operation be fore August 7, 1962;
3. Have total potential emissions greater than 250 tons per year for at least one visibilityimpairing pollutant from the emission units meeting the two criteria above.

Under the BART rules, large sources that have previously installed pollution-control equipment required under another standard (e.g., MACT, N SPS and BACT) will be required to conduct visibility analyses. Installation of additional controls may be required to further reduce emissions of visibility impairing pollutants such as PM, PM 10 

# , PM 2.5 

# , SO 2 

# , NO x 

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

Once BART eligibility is determined, a source must then determine if it is “subject to BART.” A source is subject to BART if emissions “cause or contribute” to visibility impairment at any Class I area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that
do not cause or contribute to visibi lity impairment are exempt from BART requirements, even if they are BART-eligible.



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

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# source, the energy and non-air quality environmenta l 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 emissi on 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 licensi ng and commercial sales stages of development. Similarly, we do not expect a source owner to conduct extended trials to learn how to a pply 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 availabl e 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 in feasible technologies are eliminated from further consideration. Commercial availability is not a sufficient basis for concluding that a technology is a pplicable and technically feasible. If a technology is commercially availabl e, 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 analys is documents the impacts of each remaining control technology option. The economic analysis compares dollar per ton of pollutant removed for each technology. In addition it includes incremental dollar per ton cost analysis to illustrate the economic effectiveness of one technology in relation to the others. Finally, Step Four includes an as sessment of energy impacts and other non-air quality environmental impacts.

Economic impacts were analyzed using th e procedures found in the U.S. EPA Air
Pollution Control Cost Manual – Sixth Ed ition (EPA 452/B-02-001). Equipment cost
estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model
version 7.5 were used. Vendor cost estima tes for this project were used when applicable. The source of the control equipment cost data are noted in each of the control cost analysis worksheets as found in Appendix A.

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

# , including receptor grid, meteorological data, and other factors used for this part of the analysis were provided by the Minnesota Pollution Control Agency. The model outputs, including the 98th percentile dV value and the number of days the facility contri butes more than a 0.5 deciview (dV) of visibility impairment at each of the Class I areas, are used to establish the degree of improvement that can be reasonably attributed to each technology.

The final step in the BART analysis is to select the “best” alternative using the results of steps 1 through 5. In addition, the U.S. EPA and MPCA guidance states that th e “affordability” of the controls should be considered, and specifically states:

5 

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

.

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# 1. Even if the control technology is cost effective, there may be cases where the installation of controls would affect the viability of plant operations.

2. There may be unusual circumstances that justify taking into consideration the conditions of the plant and the economic effects requiri ng the use of a given control technology. These effects would include effects on product prices, the market share, and profitability of the source. Where there are such unusual circumstances that are judged to affect plant operations, you may take into consid eration the conditions of the plant and the economic effects of requiring the use of a control technology. Where these effects are judged to have severe impacts on plant operatio ns you may consider them in the selection process, but you may wish to provide an economic analysis that demonstrates, in sufficient detail for public review, the sp ecific economic effects, parameters, and reasoning. (We recognize that this review process must pres erve the confidentiality of sensitive business information). Any analysis may also consider whether competing plants in the same industry have been requi red to install BART controls if this information is available. 6



# To complete the BART process, the analysis must “establish enforceable emission limits that reflect the BART requirement s and requires compliance with in a reasonable period of time 7 

# .” Those limits must be developed for inclusion in the state implem entation plan (SIP) that is due to U.S. EPA in December of 2007. In addition, the analysis mu st include requirements that the source “employ techniques that ensure compliance on a continuous basis 8 

# .” which could include the incorporation of other regulatory requirements for the source, incl uding Compliance Assurance Monitoring (40 CFR 64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If technological or economic limitations make m easurement methodology for an emission unit infeasible, the BART limit can “instead prescrib e a design, equipment, work practice, operation standard, or combination of these types of standards 9 

# .”

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 analyses 10 

# . The streamlined approach wi ll allow both states and the
facilities to focus their resources on the main c ontributors 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: NO x 

# , SO 2 

# , and PM.
Relative to NO x 

# and SO 2 

# , PM is not a major visibility impairing pollutant. Further, the indurating furnaces are subject to the taconite MACT standard 11 

# 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 th e 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 w ill be conducted for NO x 

# and SO 2 

# where applicable.


# 3.B PM-Only Taconite MA CT Emission Units In addition to the indurating furnaces, the taconite MACT standard also re gulates PM emissions from ore handling operations, additive storage and hand ling operations, and finished pellet handling operations. These sources operate near ambient temperature, only emit PM, and do not emit NO x 

# or SO 2 

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

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

# 3.C Sources of Fugitive PM that ar e Subject to MACT standards
The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from nonMACT sources are addressed in section 3.D). 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 fugi tive PM are not subject to a MACT standard. They include units such as:

• Bentonite storage and handling

• Limestone storage
Considering all PM emissi ons which are subject to the BART standard, the PM emissions from the above units typically represent less than 2.5% of PM emissions from the facility, which are subject to
BART. Relative to NO x 

# and SO 2 

# , PM is not a major visibility impairing pollutant.

The point source emission units are controlled by baghouses, which is a te chnology 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. Fo r 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 sc reening modeling demonstration of negligible visibility impacts for fugitive sources and combus tion 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 Limit 1 

# Existing Limit Expressed As lbs/day 2 

# 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 guidance 13 

# , 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 facil ity were determined usi ng 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, oz one and meteorological data. Additionally, the interactions betw een the visibility impairing pollutants NO x 

# , SO 2, 

# PM 2.5 

# and
PM 10 

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

In order to determine the visibility improvement resulting from the retrofit technology, the source
must first be modeled at baseli ne conditions. Per MP CA guidance, the basel ine, or pre-BART conditions, shall represent the aver age emission rate in units of pounds per hour (lbs/hr) and reflect
the maximum 24-hour actual emissions 14



# . 

# 4.A MPCA Subject-to-BART Modeling In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA completed modeling of the BART-eligible emission units at various facili ties in Minnesota in accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF,
as detailed in the “Best Available Retrofit Te chnology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesot a,” finalized in March 2006. The modeling by MPCA was conducted using em ission rate information submitted by the facility. The emissions were reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions during a 24-hour period under steady -state operating conditions dur ing periods of high capacity utilization. The results of the modeling were presented in the document titled “Results of Best Available Retrofit Technology (BART) Modeling to Determine S ources Subject-to-BART in the State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that this facility is subject-to-BART.

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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# 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, Ba rr Engineering proposed changes to the modeling protocol. The changes, as subm itted to MPCA on May 16, 2006 are presented in Appendix B.

In addition, the maximum 24-hour emission rates we re re-ev aluated internally within HTC and adjusted, as appropriate, to confirm that the emission rates represent the maximum steady-state operating conditions during periods of high capaci ty utilization. The maximum 24-hour emission rates were adjusted to reflect changes at the fa cility 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 NO x 

# 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 analy sis is presented in Appendix C.Table 4-1 Baseline Conditions Modeling Input Dataand the Basis for 24-hour Emissions DataEmissionUnit ID(Emission)UnitDescriptionSO2Max. 24-hr ActualEmissions (lb/day)BasisforSO224-hrActualEmissionsNOxMax.24-hrActualEmissions(lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.5 24-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM10 24-hrActualEmissionsStack No.StackEasting(utm)StackNorthing(utm)HeightofOpeningfromGround(ft)BaseElevationfromGround(ft)Stacklength,widthorDiameter (ft)FlowRateat Exit(acfm)ExitTemp(oF)3.AInduratingFurnacesEU020PelletInduratingFurnace LineNo 1720A13,392A01,128SV021M-SV024M502391.005258098.001191,6309193,000(perstack)90-120EU021PelletInduratingFurnace LineNo 2912A11,112A0864SV025M-SV028M502448.005258105.001191,6309198,750(perstack)90-120EU022PelletInduratingFurnace LineNo 31,032A12,624A01,056SV029M-SV032M502491.005258114.001191,6309206,750(perstack)90-1203.BPM-OnlyTaconiteMACTEmissionUnitsEU001Phase IApronFeeder (1stLevel)N/AN/A016SV001M401,730214,000-16,00065-85EU002Phase IIApronFeeder (1stLevel)N/AN/A016SV002M401,730217,000*72EU003Phase IPrimary OreConveyor -(6th Level)N/AN/A0SV003M611,730331,00064EU004Phase IIPrimary OreConveyor -(6th Level)N/AN/A021SV003M611,730331,00064E:\BART\HTC\HTC BART Report Final.doc13EmissionUnit ID(Emission)UnitDescriptionSO2Max. 24-hr ActualEmissions (lb/day)BasisforSO224-hrActualEmissionsNOxMax.24-hrActualEmissions(lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.5 24-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM10 24-hrActualEmissionsStack No.StackEasting(utm)StackNorthing(utm)HeightofOpeningfromGround(ft)BaseElevationfromGround(ft)Stacklength,widthorDiameter (ft)FlowRateat Exit(acfm)ExitTemp(oF)EU005Line No. 1Mill FeedConveyorN/AN/A015SV004M611,690212,000-14,00065-90EU006Line No. 2Mill FeedConveyorN/AN/A015SV005M611,690212,000-14,00065-90EU007Line No. 3Mill FeedConveyorN/AN/A015SV006M611,690212,000-14,00065-90EU008Line No. 4Mill FeedConveyorN/AN/A015SV007M611,690212,000-14,00065-90EU009Line No. 5Mill FeedConveyorN/AN/A015SV008M611,690212,000-14,00065-90EU010Line No. 6Mill FeedConveyorN/AN/A015SV009M611,690212,000-14,00065-90EU011Line No. 7Mill FeedConveyorN/AN/A015SV010M611,690212,000-14,00065-90EU012Line No. 8Mill FeedConveyorN/AN/A015SV011M611,690212,000-14,00065-90EU013Line No. 9Mill FeedConveyorN/AN/A015SV012M611,690213,000*73*EU018Phase IHearth LayerBinN/AN/A072SV017M1091,630434,000*72*EU018Phase IHearth LayerFeedN/AN/A018SV019M1091,630426,000*80*EU019Phase IIHearth LayerBinN/AN/A072SV018M1091,630433,000-38,00080-90EU019Phase IIHearth LayerFeedN/AN/A018SV020M1061,630418,000-23,00080-90E:\BART\HTC\HTC BART Report Final.doc14EmissionUnit ID(Emission)UnitDescriptionSO2Max. 24-hr ActualEmissions (lb/day)BasisforSO224-hrActualEmissionsNOxMax.24-hrActualEmissions(lb/day)BasisforNOx24-hrActualEmissionsPM2.5Max.24-hrActualEmissions(lb/day)BasisforPM2.5 24-hrActualEmissionsPM10Max.24-hrActualEmissions(lb/day)BasisforPM10 24-hrActualEmissionsStack No.StackEasting(utm)StackNorthing(utm)HeightofOpeningfromGround(ft)BaseElevationfromGround(ft)Stacklength,widthorDiameter (ft)FlowRateat Exit(acfm)ExitTemp(oF)EU023PelletMachineDischargeLine No 1N/AN/A050SV033M1161,630590,000-105,00075-85EU024PelletMachineDischargeLine No 2N/AN/A050SV034M1161,630590,000-105,00075-85EU025PelletMachineDischargeLine No 3N/AN/A050SV035M1161,630559,00069EU026Pellet HearthLayerScreeningN/AN/A086SV036M1171,630426,00068EU027PelletTransferHouseN/AN/A065SV037M651,630323,000713.DNon-MACTEmissionUnits andFugitiveSources(PM-Only)EU016Phase IBentoniteDay BinsN/AN/A08SV015M1091,630314,00074EU017Phase IIBentoniteDay BinsN/AN/A08SV016M1091,630313,800-14,20070-90EU028BentoniteStorage Silo- EastN/AN/A00SV038M751,60512,80060-70EU029BentoniteStorage Silo- WestN/AN/A00SV039M831,60514,20060-70EU033LimestoneStorage SiloN/AN/A00SV04300000E:\BART\HTC\HTC BART Report Final.doc15E:\BART\HTC\HTC BART Report Final.doc16Basis for 24-hour Actual EmissionsA. Representative Stack Tests; 2004-2005. Fuel: Natural GasB. Permit LimitC. Maximum Hourly PTED. Emission Factor Calculation

# 4.C Facility Baselin e Modeling Results The Minnesota BART modeling protocol 15 

# describes the CALPUFF model inputs, including the meteorological data set and background atmospheri c ammonia and ozone concentrations, along with the functions of CALPOST post pr ocessing. The CALPOST output fi les provide the following two methods to assess the expected pos t-control visibility improvement:

• 98 th 

# Percentile: As defined by federal guidance and as stated in the MPCA’s document which identifies the Minnesota facilities that are subject to BART 16 

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

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

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

• Number of Days Exceeding 0.5 dV: The severity of the visibility impair ment contribution, or reasonably attributed visibility impairment, can be gauged by assessing the number of days on which a source exceeds a visibility impairment threshold of 0.5 dV.

A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table, this facility is considered to contribute to visibi lity impairment in Class I areas because the modeled
98 th 

# percentile of the baseline c onditions exceeds the threshold of 0.5 dV. The results of this modeling are also utilized in the post-control mo deling 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 98 th 

### Percentile

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

### Percentile

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

### Percentile

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

### Percentile

Value (deciview) No. of days exceeding 0.5 deciview 

# BWCA 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 HT C 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 pellet s move through the entire furnace on a traveling grate. The pellet hardening and oxidation zone of th e 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 % ex cess air to provide sufficient oxygen for pellet oxidation.

Due to the high-energy demands of the induration pr ocess, 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 bac kup. 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 efficien cy PM wet scrubber. Since collateral SO 2 

# reductions occur within the existing wet scrubber, it is considered a low efficiency SO 2 

# scrubber and will be evaluated as such within this BART analysis . The lines do not have add-on controls for NO x 

# . NO x 

# 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 pot ential retrofit control technologies that were evaluated. Many emerging technol ogies have been identified that are not currently commercially available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the technology as it was understood at that time. As work on this evaluation progressed, new information became apparent of the limited scope and scale of some of the technology applications. Appendix D presents the current status of the avai lability and applicability of each technology.

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 SO 2 

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

# control technologies that were identified as available and applicable in the original submittal and discusses aspects of th ose technologies that dete rmine whether or not the technology is technically feas ible for indurating furnaces.

Wet Walled Electrostatic Precipitator (WWESP) An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the flue gas stream. The suspended pa rticles are given an electrical charge by passing through a high voltage DC corona region in whic h gaseous ions flow. The charged particles are attracted to and collected on oppositely charged collec tor plates. Particles on the coll ector plates are released by rapping and fall into hoppers for collection and removal.

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

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

# absorber.

The SO 2 

# control efficiency for a WWESP is dependent upon various process specific variables, such
as SO 2 

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

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

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

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

# reduction for this BART analysis. It is commercially available and has been
demonstrated to be effective for SO 2 

# removal on indurating furnaces.

Wet Scrubbing (High and Low Efficiency) Wet scrubbing, when applied to remove SO 2 

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

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

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

# 19

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

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

# . Typical high efficiency SO 2 

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

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

# could be a venturi rod scrubber design using water as a scrubbing solvent. Venturi r od scrubbers, which are frequently used for PM control at taconite facilities, wi ll also remove some of the SO 2 

# from the flue gas as collateral
emission reduction.

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

CaCO 3 

# + SO 2 

# → CaSO 3 

# • 1/2 H2O + CO 2 

# CaSO 3 

# •1/2 H 2 

# O + 3H 2 

# O + O 2 

# → 2 CaSO 4 

# •2 H 2 

# O

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

Ca(OH) 2 

# +SO 2 

# → CaSO 3 

# • 1/2 H 2 

# O + 1/2 H 2 

# O Ca(OH) 2 

# + SO 2 

# + 1/2 O 2 

# + H 2 

# O → CaSO 4 

# •2 H 2 

# O

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

# removal reactions are as
follows:

Na+ + OH- + SO 2 

# + → Na 2 

# SO 3 

# 2Na+ + 2OH- + SO 2 

# + → Na 2 

# SO 3 

# + H 2 

# O

Caustic scrubbing produces a liquid waste, and minimal equipment is needed as compared to lime or
limestone scrubbers. If lime or limest one is used as the reagent for SO 2 

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

The normal SO 2 

# control efficiency range for SO 2 

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

# concentrations are the highest.

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

# 20

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

# concentration as well as creates higher flow rates to control. Additionally, the varying sulfur con centration within the pellet causes fluctuations of
the SO 2 

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

# control efficiency
of the wet scrubber.

As stated in the beginning of this section, wet scrubbers are currently in place on the furnace
exhausts and are believed to remove 15 to 30% of the SO 2 

# in the exhaust based on Barr’s experience and testing we have completed. Taking into consideration the removal of SO 2 

# from the lowefficiency primary PM scrubber as well as a high efficiency SO 2 

# 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 SO 2 

# removal, but this not a practical solution. Given the space limitations and equipmen t 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 SO 2 

# reduction for this BART analysis.

Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) Lime/limestone injecti on is a post-combustion SO 2 

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

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

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

# control efficiency range for dry SO 2 

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

Induration waste gas streams are high in water content and are exhauste d at or near their dew points. Gases leaving the induration furna ce are currently treated for remova l of particulate matter using a wet scrubber 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 ex haust operates at 350 °F or higher
and is not saturated with water. Under induration furnace waste ga s conditions, the baghouse filter cake would become saturated with moisture and pl ug both the filters and the dust removal system. Although this may be an available an d 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 SO 2 

# is absorbed by the slurry, forming CaSO 3 

# /CaSO 4 

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

# , the term flue-gas desulfurization (FGD) may also be used.

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

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 ef ficiency 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 NO x 

# emissions. Therefore, this option is not applicable for SO 2 

# reductions at HTC.

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

# 22

# Alternate Fuels As described within the energy efficiency description, unpredicta ble pricing and availability of certain fuels has pushed companies to evaluate alternat e 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# reductions at HTC.

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

# control technologies that are available and applicable to the indurating furnace process are identified in Tabl e 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1.

Table 5-1 Indurating Furnace SO 2 

# Control Technology – Availability, Applicability, and Technical Feasibility



# SO 2 

# Pollution Control Technology Available? Applicable? Technically Feasible? 

# Wet Scrubbing (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 scr ubber currently exists. The low efficiency wet scrubbing option would optimize the existing PM wet scrubber to enhance SO 2 

# control efficiency, if possible.

Table 5-2 Indurating Furnace SO 2 

# Control Technology Effectiveness

SO 2 

# Pollution Control Technology Approximate Control Efficiency
Wet Walled Electrostatic Precipitator (WWESP) 80

Secondary Wet Scrubber 60

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 contro l remaining provide varying levels of emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental impacts to better differentiate as presented below.

Economic Impacts Table 5-3 details the expected costs associated with installation of 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 rece nt vendor quotation. The cost fo r that unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the following equation:

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



# Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs we re 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 manual 18 

# 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 disc ussions with facility staff, it was determined the space surrounding th e furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. Additionally, the structural design of the existing building woul d not support additional equipment on the roof. Therefore, the cost estimates provide for additional site-work and construction costs to accommodate the new equipment within the facility. A site-s pecific estimate for si te work, foundations, and
structural steel was added to arrive at the total re trofit installed cost of the control technology. The site specific estimate was based on Barr’s experience with similar projects. See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix A.

Table 5-3 SO 2 

# 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.

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# 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 modeli ng was conducted and energy and ot her impacts were evaluated. Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other sim ilar regulatory programs like Clean Air In terstate Rule (CAI R), cost-effective air pollution controls are in the range $1,000 to $1,3 00 per ton removed as illu strated in Appendix E. However, MPCA has set a screening level for annu alized air pollution control cost of $8,000 to $12,000 20 

# 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 SO 2 

# control for HTC is greater than $30,000 per ton of pollutant remove d. 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 SO 2 

# controls for HTC is so high and does not meet a reasonable definition of cost effective technology, these alternatives are remove d 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 fro m the retrofit technology, in comb ination with other factors such as economic, energy and other non-air quality impa cts, when determining BART for an individual source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. The economic impacts of controls for SO 2 

# are not reasonably cost effective, so visibility impacts were not modeled for SO 2 

# controls. Refer to Table 4-2 for a summary of the modeled 24-
hour maximum emission ra tes and their computational basis for the existing controls for SO 2 

# . Table 4-1 provides a summary of the SO 2 

# , NO x 

# , and PM 10 

# 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 NO x 

# it is important to understand how NO x 

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

# production occurs: thermal, fuel and prompt NO x 

# .

• Fuel bound NO x 

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

process.

• Thermal NO x 

# production arises from the thermal dissociation of nitrogen and oxygen
molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.
Thermal NO x 

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

• Prompt NO x 

# is a form of thermal NO x 

# which is generated at the flame boundary. It is the result of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NO x 

# are emitted as prompt NO x 

# .
The majority of NO x 

# is emitted as NO. Minor amounts of NO 2 

# are formed in the heater, the balance
of NO 2 

# 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 NO x 

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

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

# emission reduction. Within Step 1, the technical feasibility of the control option was also discussed and determined. The following describes retrofit NO x 

# control technologies that were iden tified as available and applicable in the original submittal and discusses aspects of those technologies that de termine whether or not the technology is technically f easible for indurating furnaces.

External Flue Gas Recirculation (EFGR) External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures thereby reducing thermal NO x 

# formation. In an external flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is
mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen

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

# 27

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

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

The normal NO x 

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

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

1. The process exhaust gas in an induration fu rnace typically has an oxygen concentration that is close to the concentration of oxyge n 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 fu rnaces needs to be above 2,400 o 

# F in order to meet product specifications. Existing burners are de signed to meet these process conditions. Application of EFGR would reduce flame te mperatures. Lower flame temperatures would reduce furnace temperatures to the poin t that product quality could be jeopardized.

3. Application of EFGR technology increases flame length. Dilution of the combustion reactants increases the reaction time needed for fuel oxidation to occur; so, flame length increases. Therefore, application of EFGR could result in flame impingement on furnace components. That would subject those compone nts to excessive temperatures and cause equipment failures.

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

Low- NO x 

# Burners

Low- NO x 

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

# formation through the restriction of oxygen, flame temperatur e, and/or residence ti me. LNB is typically a staged combustion process that is designed to split fuel combustion into two zones, primary combustion and secondary combustion. 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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# 28

# In the primary combustion zone of a staged fuel burner, NO x 

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

# formation. In the secondary combustion zone, incomplete combustion products formed in the primary zone act as reducing agents. In a reducing atmosphere, nitrog en compounds are preferentially converted to molecular nitrogen (N2) over nitric oxide (NO).

The estimated NO x 

# control efficiency for low NO x 

# burners in high temperature applications is 10%. Application of low NO x 

# 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 NO x 

# burners which are not yet commercially available. Some incorporate various fuel dilution techniques to reduce flame temperatures; such as mixing an inert gas like CO 2 

# with natural gas. Water injection to cool the burner peak flame temperature is also being investigated. This technique has already been successfully used for reducing NO x 

# emissions from gas turbines and a straight grate taconite indurating furnace in the Netherlands, but is not ye t commercially available. The water injection technique shows promise for high te mperature 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 reci rculation burners, also called ultra low- NO x 

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

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

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

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

# reduction, and it would adversely affect
combustion because excessi ve amounts of oxygen would be inject ed into the flame pattern. In addition, IFGR relies on convectiv e flow of flue gas through the burner and requires burners to be up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. Furthermore, IFGR is not feasible because the reduced flame temperatures associated with IFGR would adversely affect taconite pellet product quality.

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

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 pe llet 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 NO x 

# . The project involved a change to the two combustion chamber upper air inlet ducts on each furnace line to allow fo r 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. Th is air was needed because of interference of the lower burners’ flame pattern by the existing sw irling action and uneven airflow in the combustion
chambers. Because this at omizing 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 impl emented 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 NO x 

# is formed from the fuel used in the indurating process, HTC can expect a reduction in NO x 

# emissions as a direct result of these projects.

HTC continues to evaluate a nd 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 addi tional oxygen for pellet oxidation. The oxidation reaction extracts enough heat to offset the heat lo ss associated with air in jection. Air injection reduces the overall energy use of the kiln and produ ces a higher quality taconite pellet. Air injection also prevents carry over of the oxidati on reaction into the pellet coolers.

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# Ported kilns are applicable to grate kilns but not to straight grate indurating fu rnaces, 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, unpredicta ble pricing and availability of certain fuels has pushed companies to evaluate alternat e fuel sources. These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of NO x 

# 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 proce ss would emit significantly less NO x 

# . Switching natural gas usage to coal or other solid fuels exchanges one visibility impairment pollutant (NO x 

# ) for another (SO 2 

# ). Therefore, if this option is pursued, the impact on emissions of all visibi lity impairing pollutants must be quantified and the cumulative visibility im pact 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 fu rnace 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 sa wdust is very limited a nd supply cannot be relied upon to meet production needs. In addition, the co st 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 NO x 

# CEMS or Other Parametric Monitoring MPCA guidance lists “NO x 

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

# emissions 22 

# . Based on conversations with MPCA staff, this work practice would include process adjustments, or optimization, to minimize NO x 

# emissions. The impact of the process adjustments

21 

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

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# 31

# would be measured using the NO x 

# CEMS. This approach has been used in the electric utility industry to fine tune NO x 

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

• 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
NO x 

# formation.

• At some operations, the operating parameters which generally influence the rate of NO x 

# generation such as flame temperature, fuel usage and excess air are relatively constant during operation of the furnace, independent of proces s operation variability. This indicates that NO x 

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

# emissions.

• Process optimization for NO x 

# reductions on an induration fu rnace is not a proven technology and is not commercially av ailable as a method of NO x 

# control. To date, NO x 

# CEMS have not been documented as a control technology for i nduration furnaces. To meet the available and applicable BART analysis cr iteria, documentation of the control technology is needed.

• To the best of our knowledge, there are no documented evaluations of NO x 

# emission reductions for induration furnaces by optimizing the process using either NO x 

# CEMS or parametric monitoring. We understand the re ductions 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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# 32

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

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

Post Combustion Controls

NO x 

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

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

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

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

NSCR is often referred to as “thr ee-way conversion” catalyst because it simultaneously reduces NO x 

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

# emission reductions of 90 percent. In order to operate properly, the combustion process must be near stoichiometric conditions. Under this condition, in the presence of a catalyst, NO x 

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

# ) and carbon dioxide (CO 2 

# ). The most important reactions for NO x 

# removal

are:

2CO + 2NO → 2CO 2 

# + N 2 

# (1)

[UBH] + NO → N 2 

# + CO 2 

# + H 2 

# O (2)

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

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# 33

# 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 NO x 

# control technology in which ammonia (NH 3 

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

# is removed through the fo llowing chemical reaction:

4 NO + 4 NH 3 

# + O 2 

# → 4 N 2 

# + 6 H 2 

# O (1)
2 NO 2 

# + 4 NH 3 

# + O 2 

# → 3 N 2 

# + 6 H 2 

# O (2)

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

# decomposition. SCR requires a temperat ure range of about 570°F – 850°F for a normal catalyst. At temperature ex ceeding approximately 670oF, the oxidation of ammonia begins to become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and corrosion problems.

A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F temperature range. However, these catalysts are very expensive.

Ammonia slip from the SCR system is usually le ss than 3 to 5 ppm. The emission of ammonia increases during load changes due to the instability of the temperature in the catalyst bed as well as at low loads because of the low gas temperature.

Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) control process as described below with a preheat process step to reheat the flue gas stream up to SCR catalyst operating temperatures. The prehea ting process combines use of a thermal heat sink (packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow alternates between vessels. Each of the vessels alternates between preheating/treating and heat

recovery.

The benefits of RSCR are:

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

# and particulate controls.

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# 34

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

• Application of RSCR after SO 2 

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

There are several other concerns about the techni cal 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 st ream saturated with water may present design problems in equipmen t 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 pe rform such a demonstration project would likely be two years to develop and agree on the test pl an, obtain permits for the trial, commission the equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and

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# 35

# report on the results. The result s would not be available within the time window for establishing emission limits to be incorporated in the state implementation plan (SIP) by December 2007.

Recalling U.S. EPA’s intention re garding “available” technologies to be considered for BART, as mentioned in Section 2.B, facility owners are not expected to unde rgo extended trials in order to learn how to apply a control technology to a comple tely new and significantly different source type. Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this BART analysis.

SCR with reheat through a conventional duct burn er (rather than using a regenerative heater) has been successfully implemented more widely and 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
NO x 

# . In the system, the NO x 

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

# ® and LoTOx®.

NO + O 3 

# → NO 2 

# + O 2 

# (1)

NO 2 

# + O 3 

# → NO 3 

# + O 2 

# (2)

NO 3 

# + NO 2 

# → N 2 

# O 5 

# (3)

N 2 

# O 5 

# + H 2 

# O → 2HNO 3 

# (4)

HNO 3 

# + NaOH → NaNO 3 

# + H 2 

# O (5)

Low Temperature Oxidation (Tri-NO x ® 

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

# in a primary scrubbing stage. Then NO 2 

# is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:

O 3 

# + NO → O 2 

# + NO 2 

# (1)

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# 36

# 2NaOH + 2NO 2 

# + 1⁄2 O 2 

# → 2NaNO 3 

# + H2O (2)

Tri-NO x ® 

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

# . Subsequent stages reduce NO 2 

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

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

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

# ). NO x 

# concentrations in taconite exhaust at HTC are typically less than 200 ppm. Therefore, Tri-NO x ® 

# 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 NO 2 

# and NO 2 

# to N 2 

# O 5 

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

# O 5 

# is converted to HNO 3 

# in a scrubber, and is removed with li me or caustic. Ozone for LoTOx ® 

# is generated on site with an electrically powered ozone generator. The ozone generation rate is controlled to match the amount
needed for NO x 

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

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

The first component of the technical feasibility revi ew includes determining if the technology would apply to the process being reviewed. This would include a review and comparison of the chemical and physical propertie s required. Although it appears that the chemistry involved in the LTO technology may apply to an indurating furnace, the furnace exhaust contains other ore components that may participate in side reactions. This technol ogy has not been demonstrated on a taconite pellet indurating furnace. This raises uncertainties about how or whether the technology will transfer to a different type of process.

The second component of the technical feasibility re view includes determining if the technology is commercially available. Evaluations of LTO found that it has only been applied to small to medium sized coal or gas fired boiler applications, and has never been demonstrated on a large-scale facility. For example, the current installations of LoTOx ® 

# are on sources with flue gas flow rates from 150 – 35,000 acfm, which is qui te small, compared to the indurating fu rnace flue gas flow rates of up to

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# 37

# 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 scal e-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, th e limited application mean s that it has not been demonstrated to be an effective technology in widespread application.

There are several other concerns about the tec hnical 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 (Fe 3 

# O 4 

# ) which would react with the ozone to form hematite (Fe 2 

# O 3 

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

• The ozone that would be injected into the flue gas would react with the SO 2 

# , converting the
material to SO 3 

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

Application of this technology has not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace exhausts, nor to exha ust streams with similar, high moisture content. Using LTO at a taconite plant would require resear ch, test runs, and extended trials to identify potential issues related to design for high airflows and impacts on plant systems, including the

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# 38

# furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of a demonstration pr oject. The timeline required to perform such a demonstration proj ect would likely be two years to develop and agree on the test plan, obtain permits for the trial, commission the e quipment for the test runs, perform the test runs for a reasonable study period, and evaluate and re port on the results. The results would not be available within the time window for establishing emission limits to be incorporated in the state implementation plan (SIP ) by December 2007.

Recalling U.S. EPA’s intention re garding “available” technologies to be considered for BART, as mentioned in Section 2.B, facility owners are not expected to unde rgo extended trials in order to learn how to apply a control technology to a comple tely new and significantly different source type. Consequently, the technical feasibility of LTO on an indurating furnace is te chnically infeasible for this application and will not be evaluated further.

Step 2 Conclusion Based upon the determination within Step 2, the remaining NO x 

# control technologies that are available and applicable to the indurating furnace process are identified in Tabl e 5-4. The technical feasibility as determined in Step 2 is also included in Table 5-4.

Table 5-4 Indurating Furnace NO x 

# Control Technology – Availability, Applicability, and Technical Feasibility



# NO x 

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

Low- 

# NO x 

# Burners Yes Yes No Induced Flue Gas Recirculation Burners Yes Yes No Energy Efficiency Projects Yes Yes Yes Ported Kilns (Applies to Grate Kilns Only) Yes No No

Alternative Fuels Yes Yes No Process Optimization using 

# NO x 

# CEMS Yes No No Non-Selective Catalytic Reduction (NSCR) Yes No No

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# 39

# NO x 

# 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 NO x 

# Control Technology Effectiveness



# NO x 

# 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 expe cted costs associated wi th installation of SCR with conventional reheat. Capital costs were calculated based on the maxi mum 24-hour emissions, U.S. EPA cost models, and
vendor estimates. Ve ndor estimates for capital costs based on a specific flow rate were scaled to
each stack’s flow rate us ing the 6/10 power law to account for th e economy of scale. Operating costs were based on 93% utilization and 8000 opera ting 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 facil ity 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 sp ecific 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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# 40

# site plan of the facility. Additi onally, the structural design of th e existing building would not support additional equipment on the roof. The detailed cost analysis is provided in Appendix A.

Table 5-6 NO x 

# 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 modeli ng was conducted and energy and ot her impacts were evaluated. Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other sim ilar regulatory programs like Clean Air In terstate Rule (CAI R), cost-effective air pollution controls are in the range $1,000 to $1,3 00 per ton removed as illustrated in Appendix E. However, MPCA has set a screening level for annu alized air pollution control cost of $8,000 to $12,000 per ton of controlled pollutant 23 

# . Therefore, all air pollution control costs analyses and incremental costs will be compared to the higher MPCA-directed annualized cost.

The cost of NO x 

# 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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# 41

# Energy and Environmental Impacts

Because the cost of additional NO x 

# 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 fro m the retrofit technology, in comb ination with other factors such as economic, energy and other non-air quality impa cts, when determining BART for an individual source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document. The economic impacts of add-on controls for NO x 

# are not reasonably cost effective, and the reductions due to the energy efficiency projec ts cannot yet be quantified, so visibility impacts
were not modeled for NO x 

# controls.

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# 42

# 6. Visibility Impacts

As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting fro m the retrofit technology, in comb ination with other factors such as economic, energy and other non-air quality, when determining BART for an individual source. The baseline, or pre-BART, visibil ity impacts modeling was presented in section 4 of this document. The visibility impacts of individual control technologies were presented in Step 5 of section 5 of this document. This section of the report evaluates the various BART control scenarios utilizing both
SO 2 

# and NO x 

# controls, and determines the resultin g degree of visibility improvement.



# 6.A Post-Control Mo deling Scenarios Steps 1-4 of the BART analysis identifi ed the control technologies that were:

• Available and applicable;

• Technically feasible; and

• Below the screening cost threshold for further BART analysis.

Step 5 of the BART analysis evaluated the visibility impacts of each of the control technologies that met the requirements of the screening analysis of steps 1-4.

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 effi ciency projects underway at HTC reduce its fuel consumption significantly, although the impact on NO x 

# 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 SO 2 

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

# 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 NO x 

# , the energy efficiency projects recently implemented or soon to be implemented are
concluded to be BART. Ot her add-on controls for NO x 

# are not cost effective. The corresponding
NO x 

# limits would be establis hed following stack testing to confirm the estimated NO x 

# emission
levels.

For PM, requirements compelled by the upcoming MACT standard constitute BART. The corresponding emissions lim it would be equivalent to the li mits 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 

# 44Cleveland Cliffs Incorporated: Hibbing TaconiteBART Report - Appendix A Emission Control Cost AnalysisTable 1: Cost SummaryNOxControl Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Total Annual Cost$/yrPollution ControlCost $/tonSelective Catalytic Reduction (SCR) with ReheatPellet Indurating Furnace Line No 180% 415.2 2,082.6 $80,957,276 $42,647,613$20,478Pellet Indurating Furnace Line No 280% 344.5 1,799.1 $78,666,631 $40,222,018$22,357Pellet Indurating Furnace Line No 380% 415.2 1,832.0 $83,052,744 $40,685,307$22,208SO2Control Cost SummaryControl TechnologyControlEff %ControlledEmissions T/yEmissionReduction T/yrInstalled Capital Cost$Total Annual Cost$/yrPollution ControlCost $/tonWet Walled Electrostatic Precipitator (WWESP)Pellet Indurating Furnace Line No 180%40.4161.8$42,951,640$9,337,928$57,723Pellet Indurating Furnace Line No 280%35.9143.6$43,604,738$9,559,244$66,582Pellet Indurating Furnace Line No 380%37.6150.5$44,500,959$9,848,188$65,434Wet Scrubber (Additional)Pellet Indurating Furnace Line No 160%80.9121.3$28,888,911$4,460,257$36,762Pellet Indurating Furnace Line No 260%80.9121.3$28,888,911$4,460,257$36,762Pellet Indurating Furnace Line No 360%80.9121.3$28,888,911$4,460,257$36,762E:\BART\HTC\HTC Control Costs.xlsCost Summary9/1/2006 Page 1 of 42Cleveland Cliffs Incorporated: Hibbing TaconiteBART Report - Appendix A Emission Control Cost AnalysisTable 2: - Summary of Utility, Chemical and Supply CostsOperating Unit:Pellet Indurating Furnace Line No 1Study Year2006Emission Unit NumberEU 020Stack/Vent NumberSV021M-SV024MOperating Unit:Pellet Indurating Furnace Line No 2Emission Unit NumberEU 021Stack/Vent NumberSV025M-SV028MOperating Unit:Pellet Indurating Furnace Line No 37439.858594Emission Unit NumberEU 022Stack/Vent NumberSV029M-SV032MReferenceItemUnit Cost UnitsCost Year Data SourceNotesOperating Labor48.30 $/hr2006Site Specific - Hibbing Taconite.Maintenance Labor60.00 $/hr2006Site Specific - Hibbing Taconite.Construction Labor Rate.Electricity0.0410 $/kwh2006Site Specific - Hibbing Taconite.Purchased Cost.Natural Gas7.41 $/mscf2006Site Specific - Hibbing Taconite.Indurating cost: $7.41/mcf or $7.30/MMBtuHeating cost: $7.72/mcf or $7.61/MMBtu.Water0.28 $/mgal0.20 1995EPA Air Pollution Control Cost Manual, 6thEd 2002, Section 5 Ch 1, page 1-40.Annual Costs for Packed Tower Absorber Example Problem. '95 costadjusted for 3% inflation.Cooling Water0.28 $/mgal0.23 1999EPA Air Pollution Control Cost Manual, 6thed. Section 3.1 Ch 1.Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and3% inflation.Compressed Air0.32 $/mscf0.25 1998EPA Air Pollution Control Cost Manual 6th Ed2002, Section 6 Chapter 1 .Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%inflation.Wastewater Disposal Neutralization1.69 $/mgal1.50 2002EPA Air Pollution Control Cost Manual 6th Ed2002, Section 2 Chapter 2.5.5.5.Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch3 lists $1.30 - $2.15/1,000 gal.Chemicals & SuppliesLime90.33 $/ton90.33 2006Estimate from Cutler-Magney Company.Oxygen40.00 $/ton2006BOC estimate.Ammonia (29% aqua.)0.12 $/lb0.101 2000EPA Air Pollution Control Cost Manual 6th Ed2002, Section 5 Chapter 2, page 2-50.Annual costs for a retrofit SCR system example problem. '00 costsadjusted for 3% inflation.Caustic305.96 $/ton280 2003 Hawkins Chemical50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflationOtherSales Tax6.5% %Interest Rate7.00% %EPA Air Pollution Control Cost ManualIntroduction, Chapter 2, section 2.4.2.Social (discount) rate used as a default.Operating InformationAnnual Op. Hrs8000 HoursEngineering Estimate.Utilization Rate93%Equipment Life20 yrsEngineering Estimate.Standardized Flow RateSV021M-SV024M654,869 scfm @ 32o FCalculated.SV025M-SV028M674,379 scfm @ 32o FCalculated.SV029M-SV032M701,524 scfm @ 32o FCalculated.E:\BART\HTC\HTC Control Costs.xlsUtility Chem$ Data9/1/2006 Page 2 of 42ReferenceItemUnit Cost UnitsCost Year Data SourceNotesTemperatureSV021M-SV024M120 Deg FBART spreadsheet.Range is 90 - 120 °FSV025M-SV028M120 Deg FBART spreadsheet.Range is 90 - 120 °FSV029M-SV032M120 Deg FBART spreadsheet.Range is 90 - 120 °FMoisture ContentSV021M-SV024M7.4%2005Y:\23\69\951 Hibbing Taconite Stacktest\Hibbtac 05.Average from test results in: SV021-SV024 PM-Lead.SV025M-SV028M7.1%2004Y:\23\69\870 Hibbtac Title V StackTesting\Data\Furnace L2.Average from test results in: SV025 - SV028 6-23-04.SV029M-SV032M8.5%2005Y:\23\69\951 Hibbing Taconite Stacktest\Hibbtac 05 Week Two.Average from test results in: SV029 - SV032 PM-Lead.Actual Flow RateSV021M-SV024M772,000 acfmBART spreadsheet.SV025M-SV028M795,000 acfmBART spreadsheet.SV029M-SV032M827,000 acfmBART spreadsheet.Standardized Flow RateSV021M-SV024M702,786 scfm @ 68o FCalculated.SV025M-SV028M723,724 scfm @ 68o FCalculated.SV029M-SV032M752,855 scfm @ 68o FCalculated.Dry Std Flow RateSV021M-SV024M650,745 dscfm @ 68o FCalculated.SV025M-SV028M672,448 dscfm @ 68o FCalculated.SV029M-SV032M689,013 dscfm @ 68o FCalculated.Max Emis Actual Emissionslb/hr ton/yearPollutantLb/HrTon/yearppmv ppmvNitrous Oxides (NOx)('04&'05 Max plus 10%)SV021M-SV024M558.02,497.7 120 122.22005 plus 10%SV025M-SV028M463.02,143.5 96101.52004 plus 10%SV029M-SV032M526.02,247.1 106 103.82004 plus 10%Sulfur Dioxides (SO2)SV021M-SV024M30.0202.2 57.12004 plus 10%SV025M-SV028M38.0179.5 66.12004 plus 10%SV029M-SV032M43.0188.1 66.22004 plus 10%estimatecalculated valueknown or assumed datarequired dataE:\BART\HTC\HTC Control Costs.xlsUtility Chem$ Data9/1/2006 Page 3 of 42

## Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis Table 3 : SO 2 

## 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 Rate 7439.85859 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) 558.0 2,497.7 0% 2497.7 - NA Sulfur Dioxide (SO 2 ) 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 multiplier 3 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 : SO 2 

## 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 Rate 7439.85859 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) 463.0 2,143.5 0% 2143.5 - NA Sulfur Dioxide (SO 2 ) 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 multiplier 3 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 : SO 2 

## 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 Rate 7439.85859 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) 526.0 2,247.1 0% 2247.1 - NA Sulfur Dioxide (SO 2 ) 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 multiplier 3 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 : SO x 

## 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 Rate 7439.85859 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 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 Rate 2 29,336 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 724 gpm Evaporation Loss 4 = 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 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, 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 : SO x 

## 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 Rate 7439.85859 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 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 Rate 2 29,336 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 724 gpm Evaporation Loss 4 = 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 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, 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 : SO x 

## 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 Rate 7439.85859 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 (SO 2 ) 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 multiplier 5 60% 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 $/ft 3 Amount Required 0 ft 3 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 Rate 2 29,336 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 724 gpm Evaporation Loss 4 = 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 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, 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 : NO x 

## 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.

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## 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 multiplier 3 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

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## 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/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 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/hr

H 6,000 SCR Capital Cost

Duty 4,244 MMBtu/hr Catalyst Area 2,047 ft 2 979 f (h SCR) Q flue gas 1,965,552 acfm Rx Area 2,355 -15 f (h NH 3 ) 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 ft 3 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 H 2 O per layer

Press drop duct 3 in H 2 O Total 9488.7

Reagent Use & Other Operating Costs

Ammonia Use 56.0 lb/ft 3 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 108,457 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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 14,490 15% of Operator Costs 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

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## Cleveland Cliffs Incorporated: Hibbing Taconite BART Report - Appendix A Emission Control Cost Analysis Table 10 : NO x 

## 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

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## 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 multiplier 3 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

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## Cleveland Cliffs Incorporated: United Taconite BART Report - Appendix A Emission Control Cost Analysis Table 10: NOx Control - Selective Catalytic Reduction with Reheat

Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF 0.0944

Replacement Catalyst: Catalyst Equipment Life 3 years CRF 0.3811 Rep part cost per unit 0 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation 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

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 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

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## 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 T wi 120 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

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

T fo 309 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 702,786 scfm - Flow of waste gas

Q af 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)

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## Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis Table 11 : NO x 

## 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.

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## 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 multiplier 3 60% 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

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## 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 kW A 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&M F $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 ft 2 921 f (h SCR) Q flue gas 1,965,552 acfm Rx Area 2,355 -15 f (h NH 3 ) 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 ft 3 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 H 2 O per layer Press drop duct 3 in H 2 O Total 8947.6

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 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 108,457 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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 14,490 15% of Operator Costs 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

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## Cleveland Cliffs Incorporated: Hibbing Taconite BART Report - Appendix A Emission Control Cost Analysis Table 12 : NO x 

## 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

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## 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 multiplier 3 60% 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

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## 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 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation 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

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## 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 T wi 120 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

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

T fo 309 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 672,448 scfm - Flow of waste gas

Q af 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)

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## Cleveland Cliffs Incorporated: Hibbing Taconite

BART Report - Appendix A Emission Control Cost Analysis Table 13 : NO x 

## 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

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## 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 multiplier 3 60% 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

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## 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 kW A 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&M F $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 ft 2 979 f (h SCR) Q flue gas 2,081,140 acfm Rx Area 2,493 -17 f (h NH 3 ) 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 ft 3 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 H 2 O per layer Press drop duct 3 in H 2 O Total 10046.7

Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 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 114,836 dscf/MMBtu Method 19 Factor 9,200 dscf/MMBtu 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 14,490 15% of Operator Costs 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

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## Cleveland Cliffs Incorporated: Hibbing Taconite BART Report - Appendix A Emission Control Cost Analysis Table 14 : NO x 

## 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

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## 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 multiplier 3 60% 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

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## 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 $/ft 3 Amount Required 39 ft 3 Catalyst Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement) Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0

Replacement Parts & Equipment: Equipment Life 3 CRF 0.3811 Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation 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

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## 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 T wi 120 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref 77 Deg F - Reference temperature for fuel combustion calculations FER 70% Factional Heat Recovery % Heat recovery section efficiency

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

T fo 309 Deg F - Temperature of flue gas into of heat recovery

-h caf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air) p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F Q wg 752,855 scfm - Flow of waste gas

Q af 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)

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# Memorandum

To: 

# Margaret McCourtney
From: 

# Andrew Skoglund Subject: 

# Revisions per your comments
Date: 

# May 16, 2006 Project: 

# Taconite Industry BART Clients

c: 

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

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

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

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

Thank you,

Andrew J. Skoglund Barr Engineering Co. (952) 832 - 2685 askoglund@barr.com

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


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

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

## 0 100 Kilometers



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

# Legend
Modeling Domain 

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

Barr Footer: Date: 7/5/2006 1:34:29 PM File: I:\projects\23\00\Minntac.mxd User: ams1000MetersHibbtac Aerial Photo1000Meters

# 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, Final 1 

# , 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 guidance 2 

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

The CALPUFF program models how a pollutant 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 protocol 3 

# 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 guidance 4 

# 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 AnalysisNOx ControlAvailable and Applicable ReviewRevised: August 23, 2006Step 1Step 2This table is part of the Taconite BART Report and should not bedistributed without the full text of the report so that the information isnot taken out of context.

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

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

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

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

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

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

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