Minntac BART Report September 8, 2006

Transcription

1 Minntac BART Report September 8, 2006 Minntac BART Report September 8, 2006 Table of Contents 1. Executive Summary...iv 2. Introduction A BART Eligibility B BART Determinations Streamlined BART Analysis A Indurating Furnaces B PM-Only Taconite MACT Emission Units C Sources of fugitive PM that are subject to MACT standards D Non-MACT Units and Fugitive Sources (PM only) E Other Combustion Units F Visibility Impact Modeling for Negligible Impacts Baseline Conditions and Visibility Impacts for BART Eligible Units A MPCA Subject-to-BART Modeling B Facility Baseline Emission Rates C Facility Baseline Modeling Results BART Analysis for BART Eligible Emission Units A Indurating Furnace A.i Sulfur Dioxide Controls A.i.a STEP 1 Identify All Available Retrofit Control Technologies A.i.b STEP 2 Eliminate Technically Infeasible Options A.i.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies A.i.d STEP 4 Evaluate Impacts and Document the Results A.i.e STEP 5 Evaluate Visibility Impacts A.ii Nitrogen Oxide Controls A.ii.a STEP 1 Identify All Available Retrofit Control Technologies A.ii.b STEP 2 Eliminate Technically Infeasible Options A.ii.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies A.ii.d STEP 4 Evaluate Impacts and Document the Results A.ii.e STEP 5 Evaluate Visibility Impacts B External Combustion Sources B.i Nitrogen Oxide Controls B.i.a STEP 1 Identify All Available Retrofit Control Technologies B.i.b STEP 2 Eliminate Technically Infeasible Options Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc i

2 Minntac BART Report September 8, B.i.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies B.i.d STEP 4 Evaluate Impacts and Document the Results B.i.e STEP 5 Evaluate Visibility Impacts Visibility Impacts A Post-BART Modeling Scenarios B Post-BART Modeling Results Select BART A Indurating Furnaces B External Combustion Sources...84 List of Tables Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis...14 Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data...15 Table 3-3 De Minimis Visibility Modeling Results...16 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data..20 Table 4-2 Baseline Visibility Modeling Results...21 Table 5-1 Indurating Furnace SO 2 Control Technology Availability, Applicability, and Technical Feasibility...32 Table 5-2 Indurating Furnace SO 2 Control Technology Effectiveness...32 Table 5-3 Indurating Furnace SO 2 Control Cost Summary...34 Table 5-4 Indurating Furnace Post-BART SO 2 Control - Predicted 24-hour Maximum Emission Rates...37 Table 5-5 Indurating Furnace Post-BART SO 2 Modeling Scenarios - Visibility Modeling Results39 Table 5-6 Indurating Furnace NO x Control Technology Availability, Applicability, and Technical Feasibility...53 Table 5-7 Indurating Furnace NO x Control Technology Effectiveness...54 Table 5-8 Indurating Furnace NO x Control Cost Summary...55 Table 5-9 Indurating Furnace NO x Control Technology Impacts Assessment...57 Table 5-10 Indurating Furnace Post- BART NO X Control - Predicted 24-hour Maximum Emission Rates...60 Table 5-11 Indurating Furnace Post-BART NO X Modeling Scenarios - Visibility Modeling Results61 Table 5-12 Boiler NO x Control Technology Availability, Applicability, and Technical Feasibility70 Table 5-13 Boiler NO x Control Technology Effectiveness...71 Table 5-14 Boiler NO x Control Cost Summary...72 Table 5-15 Boiler Post-BART NO X Control - Predicted 24-hour Maximum Emission Rates...75 Table 5-16 Boiler Post-BART NO X Modeling Scenarios - Visibility Modeling Results...76 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results...80 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc ii

3 Minntac BART Report September 8, 2006 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 NO X Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac Appendix E Indurating Furnace Applicable and Available Retrofit Technologies Appendix F Summary of Relevant Economic Feasibility ($/ton) Control Costs Appendix G Process Heating Boiler Applicable and Available Retrofit Technologies Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc iii

4 Minntac BART Report September 8, Executive Summary U.S. Steel Corporation s Minnesota Ore Operations (Minntac) is located in northern Minnesota, with taconite mining and processing facilities near Mountain Iron, Minnesota. This report describes the background and methods for the selection of the Best Available Retrofit Technology (BART) as proposed by Minntac for its taconite processing plant. Within the pellet making process, there are many pieces of equipment with pollution control devices to reduce emissions. Based on the regulatory definitions and the details provided in this report, Minntac s BART-eligible units include emission units that were installed within the BART time window ( ). These BART-eligible units include the indurating furnaces, heating boilers, minor combustions sources, and several material handling and storage units for ore, product, and additives. Preliminary visibility modeling conducted by the MPCA found that the BART-eligible air emissions from Minntac cause or contribute to visibility impairment in a federally protected Class I area, therefore making the facility subject-to-bart. As a subject-to-bart facility, a BART analysis was required to determine BART for the affected emission units. Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include a streamlined approach for BART analyses 1. The streamlined approach allows both the states and the facilities to focus their resources on the main contributors to visibility impairment. As described in section 3 of this document, the emissions from several of the sources at this facility meet the criteria for a streamlined analysis. The streamlined analysis includes the specific provision that compliance with the Taconite MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions as equivalent to BART. This provision is applicable to all indurating furnaces, ore crushing and handling operations, and finished pellet handling operations that are subject to BART. The Taconite MACT standard includes requirements for performance testing and continuous parametric monitoring for compliance demonstration. After completion of the streamlined analysis, the focus of the BART analysis was the NO x emissions from four heating boilers and the SO 2 and NO x emissions from the five indurating furnaces. The four boilers that underwent the BART analysis are relatively small, and have limited hours of operation and utilization. The Indurating Furnaces operate with existing control equipment which include: wet 1 Federal Register 70, no. 128 (July 6, 2005): and Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc iv

5 Minntac BART Report September 8, 2006 scrubbers for each of the five stacks designed to control of particulate matter (PM) with collateral control of sulfur dioxide (SO 2 ); ported kilns on two of the furnaces designed for energy efficiency with collateral control of nitrogen oxides (NO x ); and low-no x burners installed on the preheat section of one of the furnaces. Guidelines included in 40 CFR 51 Appendix Y and MPCA Attachments 2 and 3 were used to determine BART for these sources. A dispersion modeling sequence of CALMET, CALPUFF, and CALBART was used to assess the visibility impacts of the baseline emissions and after the application of candidate BART controls. Visibility impacts were evaluated in the selection of BART. Other criteria that the BART rules require to be considered include the availability of control technologies, cost of control, energy and environmental impacts, existing pollution control technology in use at the source, and the remaining useful life of the source. Based on the consideration of all of the above criteria, Minntac proposes no additional controls, emission limits, or monitoring requirements for the NO x emissions from four heating boilers. This is based on the conclusion that low-nox burners were the only control technology that meet the cost screening threshold, but the technology did not provide significant improvement in the visibility modeling. In addition, the control cost for this technology is higher than the anticipated level for a BART analysis. It is also important to note that due to the relatively small size of the boilers and the low hours of operation, the actual visibility impact of the boilers is small. Based on consideration of all of the above criteria, Minntac proposes the following as BART for SO 2 and NO X for the Indurating Furnaces: BART for SO 2 : o SO 2 emissions will be controlled by the existing wet scrubbers, which will be operated as required in accordance with provisions of the Taconite MACT. o SO 2 emission limit for the Indurating Furnace on Line 3 will be determined based on upcoming performance testing to determine the actual emission rate from the furnace with the addition of the new scrubber. A proposed SO 2 limit for the furnace in the draft PSD permit for Minntac does not reflect the recently installed wet scrubber. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc v

6 Minntac BART Report September 8, 2006 o SO 2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the limits which are based on using the existing wet scrubbers and reflect air dispersion modeling results for regional haze as proposed in the draft PSD permit: Line 4 = 182 lbs/hr Line 5 = 182 lbs/hr Line 6 = 284 lbs/hr Line 7 = 284 lbs/hr o Compliance will be initially be demonstrated by a performance test at each furnace. o Continuous compliance will be demonstrated by continuous monitoring of scrubber water flow rate and scrubber pressure drop, which are the same parameters that will be monitored under the Taconite MACT. The operating limits will be determined based on the MACT compliance test and will be based on a 24-hour block average. Therefore, the compliance demonstration will be consistent with the Taconite MACT. BART for NO x : o NO x emissions will be controlled as follows: Line 3: Existing combustion controls and fuel blending. Line 3 does not currently use burners in its pre-heat section, and therefore low-no x burners cannot be applied at this furnace. Line 4: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. Line 5: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc vi

7 Minntac BART Report September 8, 2006 Line 6: Operation of low-no x burners on the pre-heat section (installed as replacement and reconfigured burners in April 2006), existing combustion controls, and fuel blending. Line 7: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. o NO x emission limits will be proposed by the facility 12-months after the installation of the low-no x burners to allow the facility sufficient time for process and emissions monitoring using NO x CEMS to determine the actual emission rates under a variety of operating conditions. Although the facility anticipates a significant reduction in NO x emissions with the installation of the low-no x burners, the actual emissions reduction cannot be determined until the burners are operated under a variety of operation conditions. o Initial and continuous compliance will be demonstrated after the appropriate emission limits have been determined. Compliance will be demonstrated using the NO x CEMS and will be based on a 30-day rolling average. The schedule for implementation of these controls, specifically installation of low-no x burners and subsequent testing to demonstrate the appropriate BART emission limit, is within the 5-year timeframe required for BART implementation. In addition, Minntac will continue to evaluate energy efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission rates. Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for the installation of low-no x burners, the proposed BART controls will result in visibility improvement on the 98 th percentile day of approximately deciviews (dv) when burning gas in the kiln and dv when burning solid fuels in the kiln. This is a visibility improvement of approximately 7% compared to the baseline (pre-bart) operating conditions. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc vii

8 Minntac BART Report September 8, Introduction To meet the Clean Air Act s requirements, the U.S. Environmental Protection Agency (U.S. EPA) published regulations to address visibility impairment in our nation s largest national parks and wilderness ( Class I ) areas in July This rule is commonly known as the Regional Haze Rule [64 Fed. Reg (July, 1999) and 70 Fed. Reg (July 6, 2005), and] and is found in 40 CFR part 51, in through Within its boundary, Minnesota has two Class I areas the Boundary Water Canoe Area Wilderness and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility impairment in other states Class I areas, such as Michigan s Isle Royale National Park and Seney Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward reaching the 2018 visibility goal for each of the state s Class I areas. One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART) analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to determine if a technology should be installed to improve visibility in Class I areas. The chosen technology is referred to as the BART controls, or simply BART. The SIP must require BART on all BART-eligible sources and mandate a plan to achieve natural background visibility by Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi Nugget (Nugget), which are illustrated in the figure, are not currently constructed or in operation. The SIP must also include milestones for establishing reasonable progress towards the visibility improvement goals and plans for the first five-year period. Upon submission of the Regional Haze SIP, states must make the requirements for BART sources federally enforceable through rules, administrative orders or Title V permit amendments. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 1

9 Minntac BART Report September 8, 2006 Figure 2-1 Minnesota s BART Geography The Minnesota SIP will address the 2 PSD Class I Areas [Voyageurs National Park (VPN) and Boundary Waters Canoe Area (BWCA)] and BART-eligible units illustrated above. (Source MPCA BART-Strategy October 4, 2005) By definition, reasonable progress means that the 20 best-visibility days must get no worse, and the 20 worst-visibility days must become as good as the 20 worst days under natural conditions. Assuming a uniform rate of progress, the default glide path would require 1 to 2 percent improvement per year in visibility on the 20 worst days. The state must submit progress reports every five years to establish their advancement toward the Class I area natural visibility backgrounds. If a state feels it may be unable to adopt the default glide path, a slower rate of improvement may be proposed on the basis of cost or time required for compliance and non-air quality impacts. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 2

10 Minntac BART Report September 8, A BART Eligibility BART eligibility is established on the basis of three criteria. In order to be BART-eligible, sources must meet the following three conditions: 1. Contain emission units in one or more of the 26 listed source categories under the PSD rules (e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250 MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning plants, sulfur recovery plants, etc.); 2. Were in existence on August 7, 1977, but were not in operation before August 7, 1962; 3. Have total potential emissions greater than 250 tons per year for at least one visibilityimpairing pollutant from the emission units meeting the two criteria above. Under the BART rules, large sources that have previously installed pollution-control equipment required under another standard (e.g., MACT, NSPS and BACT) are required to conduct visibility analyses to determine if the source is subject-to-bart. Installation of additional controls may be required to further reduce emissions of visibility impairing pollutants such as PM, PM 10, PM 2.5, SO 2, NO x, and possibly Volatile Organic Compounds (VOCs) and ammonia. Sources built before the implementation of the Clean Air Act (CAA), which had previously been grandfathered, may also have to conduct such analyses and possibly install controls, even though they have been exempted to date from any other CAA requirements. Once BART eligibility is determined, a source must then determine if it is subject-to-bart. A source is subject-to-bart if emissions cause or contribute to visibility impairment at any Class I area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that do not cause or contribute to visibility impairment are exempt from BART requirements, even if they are BART-eligible. 2.B BART Determinations Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source was previously part of a group BART determination, individual BART determinations must be made for each source. The BART analysis takes into account six criteria and is analyzed using five steps. The criteria that comprise the engineering analysis include: the availability of the control technology, Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 3

11 Minntac BART Report September 8, 2006 existing controls at a facility, the cost of compliance, the remaining useful life of a source, the energy and non-air quality environmental impacts of the technology, and the visibility impacts. 2 The five steps of a BART analysis are: Step 1 - Identify all Control Technologies The first step in the analysis is to identify all available retrofit control technologies for each applicable emission unit. U.S. EPA is very specific about the criteria to be met for a technology to be considered available. In preambles to the interim and final rules U.S. EPA defines available as follows: Available retrofit technologies are those air pollution control technologies with a practical potential for application to the emissions unit and the regulated pollutant under evaluation. Air pollution control technologies can include a wide variety of available methods, systems, and techniques for control of the affected pollutant. Technologies required as BACT or LAER are available for BART purposes and must be included as control alternatives. The control alternatives can include not only existing controls for the source category in question, but also take into account technology transfer of controls that have been applied to similar source categories or gas streams. Technologies which have not yet been applied to (or permitted for) full scale operations need not be considered as available; we do not expect the source owner to purchase or construct a process or control device that has not been demonstrated in practice. 3 Step 2 - Eliminate Technically Infeasible Options In the second step, the technical feasibility of each control option identified in step one is evaluated by answering three specific questions: 1. Is the control technology available to the specific source which is undergoing the BART analysis? The U.S. EPA states that a control technique is considered available to a specific source if it has reached the stage of licensing and commercial availability CFR 51 Appendix Y 3 Federal Register 70, No. 128 (July 6, 2005): Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 4

12 Minntac BART Report September 8, 2006 However, the U.S. EPA further states that they do not expect a source owner to conduct extended trials to learn how to apply a technology on a totally new and dissimilar source type Is the control technology an applicable technology for the specific source which is undergoing the BART analysis? In general, a commercially available control technology, as defined in question 1, will be presumed applicable if it has been used on the same or a similar source type. If a control technology has not been demonstrated on a same or a similar source type, the technical feasibility is determined by examining the physical and chemical characteristics of the pollutant-bearing stream and comparing them to the gas stream characteristics of the source types to which the technology has been applied previously Are there source-specific issues/conditions that would make the control technology not technically feasible? This question addresses specific circumstances that preclude its application to a particular emission unit. This demonstration typically includes an evaluation of the characteristics of the pollutant-bearing gas stream and the capabilities of the technology. This also involves the identification of un-resolvable technical difficulties. However, when the technical difficulties are merely a matter of increased cost, the technology should be considered technically feasible and the technological difficulty evaluated as part of the economic analysis. 6 It is also important to note that vendor guarantees can provide an indication of technical feasibility but the U.S. EPA does not consider a vendor guarantee alone to be sufficient justification that a control option will work. Conversely, the U.S. EPA does not consider the lack of a vender guarantee as sufficient justification that a control option or emission limit is technically infeasible. In general, the decisions on technical feasibility should be based on a combination of the 4 Federal Register 70, No. 128 (July 6, 2005): IBID 6 IBID Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 5

13 Minntac BART Report September 8, 2006 evaluation of the chemical and engineering analysis and the information from vendor guarantees. 7 Step 3 - Evaluate Control Effectiveness In step three, the remaining controls are ranked based on the control efficiency at the expected emission rate (post-bart) as compared to the emission rate before addition of controls (pre-bart) for the pollutant of concern. Step 4 - Evaluate Impacts and Document Results In the fourth step, an engineering analysis documents the impacts of each remaining control technology option. The economic analysis compares dollar per ton of pollutant removed for each technology. In addition it includes incremental dollar per ton cost analysis to illustrate the economic effectiveness of one technology in relation to the others. Finally, step four includes an assessment of energy impacts and other non-air quality environmental impacts. Economic impacts were analyzed using the procedures found in the U.S. EPA Air Pollution Control Cost Manual Sixth Edition (EPA 452/B ). Equipment cost estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA s Air Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model version 7.5 were used. Vendor cost estimates for this project were used when applicable. The source of the control equipment cost data are noted in each of the control cost analysis worksheets as found in Appendix A. Step 5 - Evaluate Visibility Impacts The fifth step requires a modeling analysis conducted with U.S. EPA -approved models such as CALPUFF. The modeling protocol 8, including receptor grid, meteorological data, and other factors used for this part of the analysis were provided by the Minnesota Pollution Control Agency. The model outputs, including the 98th percentile deciview (dv) value and the number of days the facility contributes more than a 0.5 dv of visibility impairment at each of the Class I areas, are used to establish the degree of improvement that can be reasonably attributed to each technology. 7 IBID 8 MPCA. October 10, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to BART in the State of Minnesota. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 6

14 Minntac BART Report September 8, 2006 The final step in the BART analysis is to select the best alternative using the results of steps 1 through 5. When selecting the best alternative, the U.S. EPA and MPCA guidance states that the affordability of the controls should be considered, and specifically states: 1. Even if the control technology is cost effective, there may be cases where the installation of controls would affect the viability of plant operations. 2. There may be unusual circumstances that justify taking into consideration the conditions of the plant and the economic effects requiring the use of a given control technology. These effects would include effects on product prices, the market share, and profitability of the source. Where there are such unusual circumstances that are judged to affect plant operations, you may take into consideration the conditions of the plant and the economic effects of requiring the use of a control technology. Where these effects are judged to have severe impacts on plant operations you may consider them in the selection process, but you may wish to provide an economic analysis that demonstrates, in sufficient detail for public review, the specific economic effects, parameters, and reasoning. (We recognize that this review process must preserve the confidentiality of sensitive business information). Any analysis may also consider whether competing plants in the same industry have been required to install BART controls if this information is available. 9 To complete the BART process, the analysis must establish enforceable emission limits that reflect the BART requirements and requires compliance within a reasonable period of time. 10 Those limits must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in December of In addition, the analysis must include requirements that the source employ techniques that ensure compliance on a continuous basis 11 which could include the incorporation of other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR 64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If technological or economic limitations make measurement methodology for an emission unit 9 MPCA. March Guidance for Facilities Conducting a BART Analysis. Page MPCA. March Guidance for Facilities Conducting a BART Analysis. Page IBID Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 7

15 Minntac BART Report September 8, 2006 infeasible, the BART limit can instead prescribe a design, equipment, work practice, operation standard, or combination of these types of standards. 12 Compliance with the BART emission limits will be required within 5 years of U.S. EPA approval of the Minnesota SIP. 12 IBID Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 8

16 Minntac BART Report September 8, 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 13. The streamlined approach will allow both states and the facilities to focus their resources on the main contributors to visibility impairment. The following outlines the MPCA-approved streamlined BART analysis for taconite facilities and presents the results of the streamlined approach in Table A Indurating Furnaces The indurating furnace is a source 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 furnace is subject to the taconite MACT standard [40 CFR Part 63 Subpart RRRRR-NESHAPS: Taconite Iron Ore Processing] for the PM emissions. MPCA s guidance for conducting a BART review states that MPCA will rely on MACT standards to represent BART level of control for those visibility impairing pollutants addressed by the MACT standard unless there are new technologies subsequent to the MACT standard, which would lead to cost-effective increases in the level of control. 14 Since the MACT standard was established very recently and becomes effective in 2006, the technology analysis is up-to-date. As a result, BART will be presumed to be equivalent to MACT for PM and no further analysis will be required to establish BART for PM for these sources. A full BART analysis will be conducted for NO x and SO 2 where applicable. 3.B PM-Only Taconite MACT Emission Units In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations. These sources operate near ambient temperature, only emit PM, and do not emit NO x or SO 2. The Ore Crushing and Handling sources and the Finished Pellet Handling sources operate with control equipment to meet the applicable MACT limits (0.008 gr/dscf for existing sources and gr/dscf for new sources). The Pellet Cooler sources are excluded from additional control under the MACT standard due to the large size of the particles and the relatively low concentration of particle emissions. 15 Therefore, the emissions from the pellet coolers are considered to have a negligible 13 Federal Register 70, no. 128 (July 6, 2005): and MPCA. March Guidance for Facilities Conducting a BART Analysis. Page Federal Register 67, no. 143 (December 18, 2002): Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 9

17 Minntac BART Report September 8, 2006 impact on visibility impairment, and no control requirements under the MACT standard is consistent with the intention of the BART analysis. Since the MACT standard was established recently and will become effective in 2006, the technology analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be presumed to be equivalent to MACT according to MPCA guidance. No further analysis will be required to establish BART for these sources. 3.C Sources of fugitive PM that are subject to MACT standards The taconite MACT standard also regulates fugitive PM emissions (fugitive PM emissions from non- MACT sources are addressed in section 3.D). These sources operate at ambient temperature, only emit PM, and do not emit NO x or SO 2. Taconite MACT fugitive sources include the following: Stockpiles (includes, but is not limited to, stockpiles of uncrushed ore, crushed ore, or finished pellets), Material Transfer Points, Plant Roadways, Tailings basins, Pellet loading areas, and Yard areas. Control of emissions from these fugitive PM sources is maintained through a fugitive control plan, as required by the MACT standard and as required by the facility s Title V air permit. The fugitive control plans consist of monitoring, primary controls, and contingent measures to prevent or mitigate fugitive PM emissions. The controls and measures are site specific and are appropriate to seasonal and weather conditions. Since the MACT standard was established recently and will become effective in 2006, the technology analysis is up-to-date. Again, for these units subject to a MACT standard, BART will be presumed to be equivalent to MACT according to MPCA guidance. No further analysis will be required to establish BART for these sources. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 10

18 Minntac BART Report September 8, D Non-MACT Units and Fugitive Sources (PM only) A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard. They include units such as: Bentonite storage and handling Additive storage and handling Concentrate storage and handling Coal and/or solid fuel storage and handling Considering all PM emissions which are subject to the BART standard, the PM emissions from the above units typically represent approximately 1% of PM emissions from the facility, which are subject-to-bart. Relative to NO x and SO 2, PM is not a major visibility impairing pollutant. The point source emission units are controlled by either baghouses or scrubbers, which are technologies that achieve high levels of control for PM. Since these units already have control equipment for PM emissions, and since the PM emissions from these sources are small relative to the total PM emissions that are subject to the BART standard, additional control of these sources can be presumed to have minimal impact on visibility improvement in Class I areas. For the controlled sources, existing controls will be considered BART consistent with direction from MPCA in the May 18, 2006 meeting, and no further analysis will be required to establish BART for these sources. If any sources do not have existing controls, the facility will conduct an analysis for these sources to demonstrate that the impact on visibility in Class I areas is negligible. The procedure for the analysis is detailed in section 3.F of this document. Assuming that the modeling demonstrates that the sources have a negligible impact on visibility in Class I areas and no further analysis will be required to establish BART for these sources. 3.E Other Combustion Units This facility has several other combustion units that are subject-to-bart. The combustion units are sources of three visibility impairing pollutants: NO x, SO 2, and PM. The remaining combustion sources include process heaters, boilers, emergency generators, air compressors, and fire pumps. It is important to note that the emissions from the indurating furnaces represent the vast majority of emissions of all visibility impairing pollutants, with the all other emission units contributing less than 1% of the total emissions of each pollutant from sources that are subject-to-bart. The emissions from all the remaining sources are small relative to the total emissions that are subject to the BART standard. Additional control of these sources can be presumed to have minimal impact on visibility improvement in Class I areas. As directed by MPCA in the May 18, 2006 meeting, the existing Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 11

19 Minntac BART Report September 8, 2006 operations for emergency generators and fire pumps will be considered BART. This facility has conducted an analysis for the remaining sources to demonstrate that the impact on visibility is negligible. The procedure for the analysis is detailed in section 3.F of this document. For the sources for which the modeling demonstrates negligible impact on visibility in Class I areas, no further analysis will be required to establish BART for these sources. 3.F Visibility Impact Modeling for Negligible Impacts As described in section 3.D and 3.E of this document, this facility contains several sources that are assumed to have a negligible impact on visibility in Class I areas. In order to confirm this assumption, a modeling analysis was conducted to determine the impact of the emissions from these sources on visibility in Class I areas. The analysis consisted of the following: (1) Conduct air dispersion modeling for uncontrolled BART-eligible emission units and fugitive sources for the facility, as described in sections 3.D and 3.E above. The modeling was conducted based on MPCA modeling protocol 16. One modeling analysis was conducted. The modeling was conducted on a focused grid (as previously agreed to with MPCA) which is based on the facility impacts as presented by MPCA in Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota (March 2006). (2) Count the days with a 98 th percentile (21 over 3-yrs, 7 each year) change in visibility greater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5 deciviews) at the modeled receptors with in the boundaries of each Class I area assessed over the 3-year period (3) If the modeled emission sources result in a 98 th percentile change in visibility less than or equal to 0.05 deciviews, the point and fugitive sources will be considered to not cause or contribute to visibility impairment in Class I areas. Therefore, the existing operations will be considered BART. No further analysis will be required to establish BART for these sources. 16 MPCA. October 10, Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to- BART in the State of Minnesota. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 12

20 Minntac BART Report September 8, 2006 (4) If the modeled emissions result in a 98 th percentile change in visibility greater than or equal to 0.05 deciviews, a full BART analysis will be conducted on the emission sources. The de minimis modeling input data is presented in Table 3-2. A summary of the results of the de minimis modeling is presented in Table 3-3. The details of the de minimis modeling are presented in Appendix C. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 13

21 Minntac BART Report September 8, 2006 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 14

22 Minntac BART Report September 8, 2006 Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 15

23 Minntac BART Report September 8, 2006 Table 3-3 De Minimis Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 16

24 Minntac BART Report September 8, Baseline Conditions and Visibility Impacts for BART Eligible Units As indicated in U.S. EPA s final BART guidance 17, one of the factors to consider when determining BART for an individual source is the degree of visibility improvement resulting from the retrofit technology. The visibility impacts for this facility were determined using CALPUFF, a U.S. EPA approved model. The CALPUFF program models how a pollutant contributes to visibility impairment with consideration for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions between the visibility impairing pollutants 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 baseline conditions. Per MPCA guidance, the baseline, or pre-bart conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect the maximum 24-hour actual emissions A MPCA Subject-to-BART Modeling In order to determine which sources are Subject-to-BART in the state of Minnesota, the MPCA completed modeling of the BART-eligible emission units at various facilities in Minnesota in accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF, as detailed in the Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota, finalized in March The modeling by MPCA was conducted using emission rate information submitted by the facility. The emissions were reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions during a 24-hour period under steady-state operating conditions during periods of high capacity utilization. The results of the modeling were presented in the document titled Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota, finalized in March The modeling conducted by MPCA demonstrated that this facility is subject-to-bart. 17 Federal Register 70, no. 128 (July 6, 2005): MPCA. March Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page 8. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 17

25 Minntac BART Report September 8, 2006 It is important to note that the MPCA subject-to-bart modeling only included the induration furnace sources. This is due to the fact that this facility contains 375 BART-eligible emission units, which would have added increased complexity to the modeling. However, the modeling results of only the indurating furnaces demonstrated that the facility is subject-to-bart. 4.B Facility Baseline Emission Rates Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated. On behalf of this facility and the other Minnesota taconite facilities, Barr Engineering proposed changes to the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are presented in Appendix B. The MPCA has given verbal approval to the proposed changes to the modeling protocol. Consistent with MPCA modeling and as agreed upon in the MPCA-approved changed to the modeling protocol, only the induration furnaces were required to be modeled for this facility. However, the NO x emissions from Boilers #1, #2, #4 and #5 were also added to the visibility model as these sources are also subject to a full BART analysis for NO x. In addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to confirm that the emission rates represent the maximum steady-state operating conditions during periods of high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect the highest emission rate as measured during a representative stack test, as opposed to the emission rate as measured during the most recent stack test. The baseline emission rates from the following sources were adjusted using this criteria: o Line 3 Rotary Kiln (EU 225 / SV 103) - NO x and SO 2 o Line 4 Rotary Kiln (EU 261 / SV 118) - NO x and SO 2 o Line 5 Rotary Kiln (EU 280 / SV 127) - NO x and SO 2 o Line 6 Rotary Kiln (EU 315 / SV 144) - NO x and SO 2 o Line 7 Rotary Kiln (EU 334 / SV 151) - NO x and SO 2 The MPCA visibility impairment modeling evaluated the impacts of the maximum 24-hour emissions of SO 2, NO x, and PM. However, it is important to note that the worst-case SO 2 emissions scenario is based on solid fuel operation and the worst-case NO x emissions scenario is based on natural gas Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 18

26 Minntac BART Report September 8, 2006 operation. Therefore, baseline modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln. The facility baseline data reflecting these changes is summarized in the Table 4-1. The full modeling analysis is presented in Appendix C. 4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol also describes the post processing elements of the analysis. 19 The CALBART output files provide the following two methods to assess the expected post-bart visibility improvement: 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 20, 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 impairment contribution, or reasonably attributed visibility impairment, can be gauged by assessing the number of days on which a source exceeds a visibility impairment threshold of 0.5 dv. A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table, the modeling of the revised baseline emissions confirms that the facility is considered to contribute to visibility impairment in Class I areas because the modeled 98 th percentile of the baseline conditions exceeds the threshold of 0.5 dv. The results of this modeling are also utilized in the post-bart modeling analysis in section 6 of this document. The full modeling analysis is presented in Appendix C. 19 MPCA. March Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of Minnesota. Page MPCA. March Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the State of Minnesota. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 19

27 Minntac BART Report September 8, 2006 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 20

28 Minntac BART Report September 8, 2006 Table 4-2 Baseline Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 21

29 Minntac BART Report September 8, BART Analysis for BART Eligible Emission Units BART eligible sources at this facility can be divided into groups based upon type of process. The Minntac facility had two types of processes which were required to undergo a full BART analysis: Indurating Furnaces for NO x and SO 2 (Section 5.A) o Line 3 Rotary Kiln (EU 225 / SV 103) o Line 4 Rotary Kiln (EU 261 / SV 118) o Line 5 Rotary Kiln (EU 282 / SV 127) o Line 6 Rotary Kiln (EU 315 / SV 144) o Line 7 Rotary Kiln (EU 334 / SV 151) External Combustion Sources for NO x (Section 5.B) o Utility Plant Heating Boiler #1 (EU 001 / SV 001) o Utility Plant Heating Boiler #2 (EU 002 / SV 002) o Utility Plant Heating Boiler #4 (EU 004 / SV 004) o Utility Plant Heating Boiler #5 (EU 005 / SV 005) 5.A Indurating Furnace Soft or green pellets are oxidized and heat-hardened in the induration furnace. The induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. This facility has five grate/kiln induration furnaces, in which the pellets are dried on a grate and then transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation section of the induration furnace is designed to operate at 2,400 ºF and higher. This temperature is required to meet taconite pellet product specifications. Fuel combustion in the induration furnace is carried out at approximately 15% to 18% oxygen to provide sufficient oxygen for pellet oxidation. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 22

30 Minntac BART Report September 8, 2006 Air is used for combustion, pellet cooling, and as a source of oxygen for pellet oxidation. Due to the high-energy demands of the induration process, induration furnaces have been designed to recover as much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and preheat zones are heated with the hot gases generated in the pellet hardening/oxidation section and the pellet cooler sections. Each of these sections is designed to maximize heat recovery within process constraints. The pellet coolers are also used to preheat combustion air so more of the fuel s energy to be directed to the process instead of heating ambient air to combustion temperatures. The five grate/kiln induration furnaces at this facility utilize the following fuels: Line 3 Rotary Kiln (EU 225 / SV 103) natural gas, biomass, and fuel oil Line 4 Rotary Kiln (EU 261 / SV 118) natural gas, biomass, and fuel oil Line 5 Rotary Kiln (EU 282 / SV 127) natural gas, biomass, and fuel oil Line 6 Rotary Kiln (EU 315 / SV 144) natural gas, biomass, fuel oil and coal Line 7 Rotary Kiln (EU 334 / SV 151) natural gas, biomass, fuel oil and coal Emissions from the induration furnaces are controlled as follows: PM / PM 10 : PM emissions are controlled by a wet scrubbers with water used as the scrubbing solution. The PM emissions from the indurating furnace are subject to the taconite MACT standard. are regulated by the Taconite MACT. As addressed in section 3.A, BART will be presumed to be equivalent to MACT for PM and no further analysis will be required to establish BART for PM for these sources. On lines 4, 5, 6 and 7, the water from the scrubber passes through the scrubber once, with some of the discharge water being used immediately used as process water in the concentrator with the remainder of the water being discharged to the tailings basin. The wet scrubbers are designed to remove PM and are considered a high efficiency PM wet scrubbers and will be evaluated as such within this BART analysis. The Line 3 wet scrubber was installed after the BART baseline period and started operation on June The scrubber is a recirculating scrubber with the scrubber blowdown water being treated before being discharged to the tailings basin. The wet scrubber is designed to Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 23

31 Minntac BART Report September 8, 2006 remove PM and is considered a high efficiency PM wet scrubber and will be evaluated as such within this BART analysis. Since the scrubber was installed after the baseline date, the emissions in the post-bart modeling analysis were adjusted to account for the improved removal efficiency. SO 2 : SO 2 emissions are controlled as collateral SO 2 reductions by the existing wet scrubbers. Therefore, the existing wet scrubbers are considered a low-efficiency SO 2 scrubbers and will be evaluated as such within this BART analysis. NO X : NO X is controlled through existing combustion practices and fuel switches (lower NO x emissions when burning solid fuels). NO X emissions are monitored using NO X continuous emissions monitoring systems (CEMS). Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac submitted a report to MPCA presenting an analysis of the NO X emissions from Line 7 before and after the installation of the ports. This report is presented in Appendix D. As described in the report, the NO X emissions from the kiln decreased by approximately 5% when burning natural gas. However, no emission reduction was noted when burning solid fuels. When evaluating the use of air injection ports for the reduction of NO X emissions, it is important to note that solid fuels are typically burned in the furnaces and therefore, the actual improvement in NO X emissions would be significantly less than 5% estimate. In April 2006, replacement and reconfigured burners were installed into the preheat section of Line 6. The burners were installed as an energy efficiency project. However, after installation of the burners, the emissions from the kiln were evaluated using the data from the NO x CEMS. This evaluation showed a reduction in NO X emissions from the kiln of approximately 10% when the preheat section was in operation. Since the low-no X burners were installed after the baseline date, the emissions in the post-bart modeling analysis were adjusted to account for the reduced emissions from Line 6. Additional information regarding the post-bart modeling is presented in Step 5 of this BART analysis. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 24

32 Minntac BART Report September 8, A.i Sulfur Dioxide Controls 5.A.i.a STEP 1 Identify All Available Retrofit Control Technologies Step 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the technology as it was understood at that time. In regards to the availability of the technology with respect to Step 1 of the BART analysis, the list has not changed from the information submitted at that time. The comprehensive list of control technologies is presented in Appendix E. 5.A.i.b STEP 2 Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as available in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions: 1. Is the control technology available to the specific source which is undergoing the BART analysis? 2. Is the control technology an applicable technology for the specific source which is undergoing the BART analysis? 3. Are there source-specific issues/conditions that would make the control technology not technically feasible? A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the technology as it was understood at that time. As work on this evaluation progressed, additional information became apparent regarding the limited scope and scale of some of the technology applications. Appendix E presents the current status of the availability and applicability of each technology. The following section describes retrofit SO 2 control technologies that were identified as available and applicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace. Wet Walled Electrostatic Precipitator (WWESP) An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the flue gas stream. The suspended particles are given an electrical charge by passing through a high Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 25

33 Minntac BART Report September 8, 2006 voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and collected on oppositely charged collector plates. Particles on the collector plates are released by rapping and fall into hoppers for collection and removal. A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry ESP and uses a water spray to remove particulate matter from the collection plates. For 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 the induration furnaces at this facility currently employ a wet scrubbers designed for removal of particulate matter, the scrubbers also perform as low efficiency SO 2 wet scrubbers. The addition of a WWESP would act as a polishing SO 2 control device and would experience reduced control efficiency due to lower SO 2 inlet concentrations. A control efficiency as a polishing WWESP ranges from 30-80% dependent upon the process specific operating parameters. Based on the definitions contained within this report, a WWESP is considered an available technology for SO 2 reduction for this BART analysis. 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 typically used as scrubbing agents. Most FGD wet scrubbers recirculate the scrubbing solution, which minimizes the wastewater discharge flow. However, higher concentrations of solids exist within the recirculated wastewater. For a wet scrubber to be considered a high efficiency 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 can have a control efficiency of 30% or lower. A low efficiency SO 2 could be a venturi rod scrubber design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used for PM control at taconite facilities, will also remove some of the SO 2 from the flue gas as collateral emission reduction. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 26

34 Minntac BART Report September 8, 2006 Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following equations: 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 scrubbing 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 requires less equipment as compared to lime or limestone scrubbers. If lime or limestone is used as the reagent for SO 2 removal, additional equipment is needed for preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air injection blower is needed to supply the oxygen for the second reaction to occur. The normal SO 2 control efficiency range for SO 2 scrubbers on coal-fired utility boilers with low excess air is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency scrubbers. The highest control efficiencies can be achieved when SO 2 concentrations are the highest. Unlike coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper oxidation of the pellet. The excess air dilutes the SO 2 concentration and creates higher flow rates to control. Additionally, the varying sulfur concentration within the ore 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 previously stated, wet scrubbers are currently in place on the furnaces exhausts and are believed to remove 15% to 30% of the SO 2 in the exhaust based on Barr s experience and testing which has 27 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc

35 Minntac BART Report September 8, 2006 been completed. Taking into consideration the removal of SO 2 from the low-efficiency primary PM scrubber as well as a high efficiency SO 2 polishing wet scrubber, an estimated overall efficiency of the control train would then be approximately 80%. In theory, the SO 2 removal efficiency of the existing scrubbers could be improved through the additions of caustic, lime, or limestone in the scrubber water to raise the ph. The existing scrubber on lines 4-7 currently operates at approximately a neutral ph. However, the scrubbers, piping, pumps and water tanks were not designed to operate at a higher ph so corrosion of the system would be a concern. The addition of the chemicals and increased SO 2 removal would create additional solids and sulfates in the scrubber discharged to the tailings basin which would require substantial and expensive treatment to maintain an acceptable water quality which could be discharged through the existing NPDES permit. The new scrubber on Line 3 is a recirculating scrubber which operates at a ph which is typically less than 7. The scrubber was operated temporarily at a higher ph, but plugging and other operational problems resulted and the scrubber was returned to the current operating ph. Based on these concerns, the improvement of SO 2 removal efficiency of the existing scrubbers is not a practical solution and is not considered further in this report. Based on the information contained within this report, a wet scrubber is considered an available technology for SO 2 reduction for this BART analysis. Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection) Lime/limestone injection 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 through 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 exhausted at or near their dew points. Gases leaving the induration furnace are currently treated for removal of particulate matter using a wet scrubber. The exhaust temperature is typically in the range of 100 F to 150 F and is saturated with water. For comparison, a utility boiler exhaust operates at 350 F or higher and is not saturated with water. Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with moisture and plug both the filters and the dust removal system. Although this may be an available and applicable control option, it is not technically feasible due to the high moisture content and will not be further evaluated in this report. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 28

36 Minntac BART Report September 8, 2006 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 baghouse filter cake would become saturated with moisture and plug both the filters and the dust removal system. In addition, because of the moisture in the exhaust, the lime slurry would not dry properly and it would plug up the dust collection system. Similarly to the dry sorbent injection control option, this is an available and applicable control option, but is not technically feasible due to the high moisture content. This option will not be further evaluated in this report. Energy Efficiency Projects Energy efficiency projects provide opportunities for a facility to reduce their fuel consumption, which results in lower operating costs. Typically reduced fuel usage translates into reduced air emissions. An example of an energy efficiency project would be to use waste heat to preheat incoming make-up air or pellet feed. Each project is very dependent upon the fuel usage, process equipment, type of product and many other variables. Due to the increased price of fuel, this facility has already implemented several energy efficiency projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission reductions. It would be impossible to assign a general potential emission reduction for the energy efficient category. Due to the uncertainty and generalization of this category, this will not be further evaluated in this report. However, it should be noted that the facility will continue to evaluate and implement energy efficiency projects as they arise. Alternate Fuels As described within the energy efficiency description, increased price of fuel has pushed taconite facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources. These fuel sources come in all forms solid, liquid and gas. To achieve reduction of SO 2 emissions through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal, and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one visibility impairment pollutant (SO 2 ) for another (NO x ), as induration furnaces typically emit 29 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc

37 Minntac BART Report September 8, 2006 significantly less NO x when burning solid fuels. Therefore, if this option is pursued, the impact on emissions of all visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the net benefit of a particular alternative fuel. It is also important to note that U.S. EPA s intent is for facilities to consider alternate fuels as their option, not to direct the fuel choice. 21 Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in this report. However, similar to energy efficiency, the facility will continue to evaluate and implement alternate fuel usage as the feasibility arises. Coal Processing Pre-combustion coal processing techniques have been proposed as one strategy to reduce uncontrolled SO 2 emissions. Coal processing technologies are being developed to remove moisture and potential contaminants from the coal prior to use. These processes typically employ both mechanical and thermal means to increase the quality of coal by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine enters a first stage separator where it is crushed and screened to remove large rock and rock material. 22 The processed coal is then passed on to an intermediate storage facility prior to being sent to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks into the thermal processors where steam is injected. Moisture in the coal is released under these conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock and sulfur-bearing pyrites. After treatment, the coal is discharged into a second pressurized lock. The second pressurized lock is vented into a water condenser to return the processor to atmospheric pressure and to flash cool the coal. Water, removed from the process at various points, and condensed process steam are reused within the process or treated prior to being discharged. 21 Federal Register 70, no. 128 (July 6, 2005): The coal processing description provided herein is based on the K-Fuel process under development by KFx, Inc. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 30

38 Minntac BART Report September 8, 2006 To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coalfired boiler. Using processed fuels at a taconite plant would require research, test burns, and extended trials to identify potential impacts on plant systems, including the furnaces, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis. Coal drying is currently being explored at a coal-fired utility in North Dakota as a potential viable option a pre-combustion control for SO 2 reduction. In the process, raw coal is crushed and screened to remove rocks and other impurities, such as pyretic sulfur. The crushed coal is then thermally processed to remove excess moisture. For this option to be viable, excess heat or low pressure steam must be available to dry the coal. Since this heat source is not available at this facility, coal drying is not feasible and will not be further evaluated in this report. Step 2 Conclusion Based upon the determination within Step 2, the remaining SO 2 control technologies that are available and applicable to the indurating furnace process are identified in Table 5-1. The technical feasibility as determined in Step 2 is also included in Table 5-1. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 31

39 Minntac BART Report September 8, 2006 Table 5-1 Indurating Furnace SO 2 Control Technology Availability, Applicability, and Technical Feasibility Step 1 Step 2 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? SO 2 Pollution Control Technology Wet Walled Electrostatic Precipitator (WWESP) Y Y Y Y Secondary Wet Scrubber Y Y Y Y Modifications to Existing Wet Scrubbing (Low Efficiency) Y Y N N Dry Sorbent Injection Y Y Y N Spray Dry Absorption Y Y Y N Energy Efficiency Projects Y Y Y N Alternative Fuels Y Y Y N (not required by BART) Coal Processing Y Y Y N 5.A.i.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies Table 5-2 describes the expected control efficiency from each of the remaining feasible control options. WWESP and wet scrubbing control options listed in Table 5-2 would be considered polishing control devices since wet scrubber currently operate as primary control. Table 5-2 Indurating Furnace SO 2 Control Technology Effectiveness SO 2 Pollution Control Technology Approximate Control Efficiency Wet Walled Electrostatic Precipitator (WWESP) 80% Secondary Wet Scrubber 60% Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 32

40 Minntac BART Report September 8, A.i.d STEP 4 Evaluate Impacts and Document the Results As illustrated in Table 5-2 above, the technically feasible control technologies remaining provide varying levels of emission reduction. Therefore, it is necessary to consider the economic, energy, and environmental impacts to better differentiate as presented below. Economic Impacts Table 5-3 details the expected costs associated with installation of a secondary wet scrubber or a wet walled electrostatic precipitator (WWESP) after the existing scrubber on each stack. Equipment design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models. Capital costs were based on recent vendor quotations. The cost for that unit was scaled to each stack s flow rate using the 6/10 power law as shown in the following equation: Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6 Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours per year (EPA default value). Operating costs of consumable materials, such as electricity, water, and chemicals were established based on the U.S. EPA control cost manual 23 and engineering experience, and were adjusted for the specific flow rates and pollutant concentrations. Due to space considerations, 60% of the total capital investment was included in the costs to account for a retrofit installation. 24 After discussions with facility staff and management, it was determined the space surrounding the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. Additionally, the structural design of the existing building would not support additional equipment, such as an SO 2 scrubber or WWESP, on the roof. Therefore, the cost estimates provide for additional site-work and construction costs to accommodate the new equipment within the facility. A site-specific estimate for site work, foundations, and structural steel was added to arrive at the total retrofit installed cost of the control technology. The site specific estimate was based on recent actual retrofit costs for installation of a secondary wet scrubber at the facility. The detailed cost analysis is provided in Appendix A. 23 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 24 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 33

41 Minntac BART Report September 8, 2006 Table 5-3 Indurating Furnace SO 2 Control Cost Summary Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 34

42 Minntac BART Report September 8, 2006 Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective air pollution controls in the electric utility industry for large power plants are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix F. This cost-effective threshold is also an indirect measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for proposing BART in lieu of developing industry and site specific data. The annualized pollution control cost value was used to determine whether or not additional impacts analyses would be conducted for the technology. If the control cost was less than a screening threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are evaluated. MPCA set the screening level to eliminate technologies from requiring the additional impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 25. Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts. The cost of SO 2 control for both of the technically feasible technologies is greater than $12,000 per ton of pollutant removed. This cost is higher than the MPCA-directed annualized cost screening level and is far in excess of any cost that is considered to be cost effective for BART. Therefore, these alternatives are removed from further consideration in this analysis. Energy and Environmental Issues Because the cost of SO 2 controls for Minntac is so high and does not meet a reasonable definition of cost effective technology, these alternatives are removed from further consideration in this analysis. 5.A.i.e STEP 5 Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality impacts, when determining BART for an individual 25 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 35

43 Minntac BART Report September 8, 2006 source. The baseline, or pre-bart, visibility impacts modeling was presented in section 4 of this document. Because the cost of SO 2 controls is so high and does not meet a reasonable definition of cost effective technology, visibility impacts were not modeled for SO 2. However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline period and started operation on June The scrubber is considered a high efficiency scrubber for PM and a low efficiency scrubber for SO 2. Since the scrubber was installed after the baseline date, the emissions in the post-bart modeling analysis must be adjusted to account for the improved removal efficiency. Also as previously stated, replacement and reconfigured burners were installed into the preheat section of Line 6 on April 2006 which reduced the NO X emissions from the kiln of approximately 10% when the preheat section was in operation. Since the low-no X burners were installed after the baseline date, the emissions in the post-bart modeling analysis must also be adjusted to account for the reduced emissions from Line 6. Therefore, the visibility impacts modeling presented in this section represent the post-baseline (i.e. post-bart) current operations of the facility. Predicted 24-Hour Maximum Emission Rates Consistent with the use of the highest daily emissions for baseline, or pre-bart, visibility impacts, the post-bart emissions to be used for the visibility impacts analysis should also reflect a maximum 24-hour average projected emission rate. In the visibility impacts modeling analysis, the emissions from the Line 3 indurating furnaces were adjusted to account for the new wet scrubber and the emissions from the Line 6 indurating furnace was adjusted to account for replacement and reconfigured low-no x burners which have been installed in the preheat section. The emissions from all other Subject-to-BART sources were not changed. Table 5-4 provides a summary of the modeled SO 2, NO X, and PM 24-hour maximum emission rates for the post-baseline (i.e. post-bart) current operations. Similar to the modeling for the baseline or pre-bart operating conditions, modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 36

44 Minntac BART Report September 8, 2006 Table 5-4 Indurating Furnace Post-BART SO 2 Control - Predicted 24-hour Maximum Emission Rates Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 37

45 Minntac BART Report September 8, 2006 Post-BART Visibility Impacts Modeling Results Results of the post-bart visibility impacts modeling for current operations are presented in Table 5-5. The results summarize 98th percentile dv value and the number of days the facility contributes more than a 0.5 dv of visibility impairment at each of the Class I areas. As illustrated in tables 5-5, the current operation of the facility results in a visibility improvement of dv when burning natural gas in the kiln and dv when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline or pre-bart emissions. A summary of visibility impacts for the total facility BART analysis are presented in Section 6. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 38

46 Minntac BART Report September 8, 2006 Table 5-5 Indurating Furnace Post-BART SO 2 Modeling Scenarios - Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 39

47 Minntac BART Report September 8, 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: Fuel bound nitrogen compounds in the fuel are oxidized in the combustion process to NO x. 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 Step 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the technology as it was understood at that time. In regards to the availability of the technology with respect to Step 1 of the BART analysis, the list has not changed from the information submitted at that time. The comprehensive list of control technologies is presented in Appendix E. 5.A.ii.b STEP 2 Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as available in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions: 1. Is the control technology available to the specific source which is undergoing the BART analysis? 2. Is the control technology an applicable technology for the specific source which is undergoing the BART analysis? Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 40

48 Minntac BART Report September 8, Are there source-specific issues/conditions that would make the control technology not technically feasible? A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the technology as it was understood at that time. As work on this evaluation progressed, additional information became apparent regarding the limited scope and scale of some of the technology applications. Appendix E presents the current status of the availability and applicability of each technology. The following section describes retrofit NO x control technologies that were identified as available and applicable in the May 9 submittal and discusses aspects of those technologies that determine whether or not the technology is technically feasible for the indurating furnace. External Flue Gas Recirculation (EFGR) External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures thereby reducing thermal 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 level in the combustion zone reduces flame temperatures; which in turn reduces NO x emissions. For this technology to be effective, the combustion conditions must have the ability to be controlled at the burner tip. The typical NO x control efficiency range for EFGR on a boiler is 30% to 50%. Application for EFGR technology in taconite induration is problematic for three reasons: 1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so it can be used as a diluent for oxygen for flame temperature reduction. Taconite waste gas has much higher oxygen level; thus use of taconite waste gas for EFGR would be equivalent to adding combustion air instead of an inert gas. 2. The oxidation zone of induration furnaces needs to be above 2,400 o F in order to meet product specifications. Existing burners are designed to meet these process conditions. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 41

49 Minntac BART Report September 8, 2006 Application of EFGR would reduce flame temperatures. Lower flame temperatures would reduce furnace temperatures to the point that product quality could be jeopardized. 3. Application of EFGR technology increases flame length. Dilution of the combustion reactants increases the reaction time needed for fuel oxidation to occur; so, flame length increases. Therefore, application of EFGR could result in flame impingement on furnace components. That would subject those components to excessive temperatures and cause equipment failures. Although this may be an available and applicable control option, it is not technically feasible due to the high oxygen content of the flue gas and will not be further evaluated in this report. Low-NO x Burners Low-NO x burner (LNB) technology utilizes advanced burner design to reduce NO x formation through the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a staged combustion process that is designed to split fuel combustion into two zones, primary combustion and secondary combustion. This analysis utilizes the staged fuel design in the cost analysis because lower emission rates can be achieved with staged fuel burner than with a staged air burner. In the primary combustion zone of a staged fuel burner, 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, nitrogen compounds are preferentially converted to molecular nitrogen (N 2 ) over nitric oxide (NO). If LNB were to be applied in the indurating section of the furnace, the reduced flame temperatures associated with LNB would adversely affect taconite pellet product quality. In addition, the oxygen concentration cannot be controlled at the burner tip in the induration section of the furnace. Therefore, LNB is not feasible in the induration section of the permit. However, the use LNB in the pre-heat section of the furnace is feasible and NO x reductions could be credited for that section of the furnace. However, the NO x emissions from the pre-heat section cannot be measured separately from the total furnace NO x emissions, so the actual emission reduction from the burners is unknown. However, in April 2006 replacement and reconfigured burners were installed into the preheat section of Line 6. The burners were installed as an energy efficiency project. After installation of the burners, the emissions from the kiln were evaluated using the data Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 42

50 Minntac BART Report September 8, 2006 from the NO x CEMS. This analysis showed a reduction in NO X emissions from the kiln of approximately 10% when the preheat section was in operation. Based on this information, a 10% reduction was assumed for the installation of low-no x burners on the preheat sections of lines 4, 5, and 7 (Line 3 does not currently use burners in the preheat section). However, due to differences in design and operation of the various kilns, the 10% reduction should only be treated as an estimate as the actual emissions reduction would not be known until after installation and testing. Low-NO x burners will be considered an available and applicable technology for lines with preheat sections. It is also important to note that there are other methods being developed for low 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 was also being investigated. This technique has already been successfully used for reducing NO x emissions from gas turbines. The water injection technique shows promise for high temperature applications, but will not be further investigated in this report as the technology is still in the research and development phase. Induced Flue Gas Recirculation Burners Induced flue gas recirculation burners, also called ultra low-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 previously noted, taconite furnaces are designed to operate with oxygen levels of approximately 15% to 18%. At these oxygen levels, flue gas recirculation is ineffective at NO x reduction, and it would adversely affect combustion because excessive amounts of oxygen would be injected into the flame pattern. In addition, IFGR relies on convective flow of flue gas through the burner and requires burners to be up-fired; meaning that the burner is mounted in the furnace floor and the flame rises up. Furthermore, IFGR is not feasible in the kiln because the reduced flame temperatures associated with IFGR could adversely affect taconite pellet product quality. Although this may be an available and applicable control option, it is not technically feasible due to the high oxygen content of the flue gas and will not be further evaluated in this report. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 43

51 Minntac BART Report September 8, 2006 Energy Efficiency Projects Energy efficiency projects provide opportunities for a facility to reduce their fuel consumption, which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution emissions. An example of an energy efficiency project could be to preheat incoming make-up air or pellet feed. Each project is very dependent upon the fuel usage, process equipment, type of product and many other variables. Due to the increased price of fuel, this facility has already implemented several energy efficiency projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission reductions. It would be impossible to assign a general potential emission reduction for the energy efficient category. Due to the uncertainty and generalization of this category, this will not be further evaluated in this report. However, it should be noted that the facility will continue to evaluate and implement energy efficiency projects as they arise. Ported Kilns Ported kilns are rotary kilns that have air ports installed at specified points along the length of the kiln. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln bed. Ports are installed about the circumference of the kiln. Each port is equipped with a closure device that opens when it is at the bottom position to inject air in the pellet bed, and closed when it rotates out of position. The purpose of air injection is to provide additional oxygen for pellet oxidation. The oxidation reaction extracts enough heat to offset the heat loss associated with air injection. Air injection reduces the overall energy use of the kiln and produces a higher quality taconite pellet. Air injection also prevents carry over of the oxidation reaction into the pellet coolers. Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac submitted a report to MPCA presenting an analysis of the NO X emissions from Line 7 before and after the installation of the ports. This report is presented in Appendix D. As described in the report, the NO X emissions from the kiln decreased by approximately 5% when burning natural gas. However, no emission reduction was noted when burning solid fuels. When evaluating the use of air injection ports for the reduction of NOx emissions, it is important to note that solid fuels are typically burned in the furnaces and therefore, the actual improvement in NOX emissions would be significantly less than 5% estimate. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 44

52 Minntac BART Report September 8, 2006 Alternate Fuels As described within the energy efficiency description, increased price of fuel has pushed taconite facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources. These fuel sources come in all forms solid, liquid and gas. To achieve reduction of SO 2 emissions through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal, and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one visibility impairment pollutant (SO 2 ) for another (NO x ), as induration furnaces typically emit significantly less NO x when burning solid fuels. Therefore, if this option is pursued, the impact on emissions of all visibility pollutants must be quantified and the cumulative visibility impact modeled to determine the net benefit of a particular alternative fuel. It is also important to note that U.S. EPA s intent is for facilities to consider alternate fuels as their option, not to direct the fuel choice. 26 Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in this report. However, similar to energy efficiency, the facility will continue to evaluate and implement alternate fuel usage as the feasibility arises. Process Optimization with NO x CEMS or Other Parametric Monitoring MPCA guidance lists NO x CEMS as a work practice/operational change for controlling NO x emissions 27. 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 would be measured using the NO x CEMS. If NO x CEMS are not installed, it may also be possible to measure the impact of the process changes using parametric monitoring. As part of the negotiation of the draft PSD permit, Minntac has installed NO x CEMS on all five indurating furnaces. The use of the NO x CEMS has resulted in lower emissions being reported in the annual emissions inventory. However, this decrease may be due to having actual emission data available for the report rather than using the emissions from stack tests which were conducted at 26 Federal Register 70, no. 128 (July 6, 2005): MPCA. March Guidance for Facilities Conducting a BART Analysis. Page 4. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 45

53 Minntac BART Report September 8, 2006 worst-case operating conditions. In addition, the NO x CEMS has allowed Minntac to quantify the emissions rates for all fuel combinations. Although the NO x CEMS has allowed the facility to use better data for reporting, the facility has not yet identified specific operating parameters which can be controlled to reduce emissions without sacrificing unit efficiency or product quality. Based upon this information, there is no indication that further emission reductions would be achieved through the use of the process optimization, using NO x CEMS as a control technology. Therefore, process 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 located downstream of the furnace area of the combustion process. The two main techniques in commercial service include the selective non catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a number of different process systems in each of these categories of control techniques. In addition to these treatment systems, there are a large number of other processes being developed and tested on the market. These approaches involve innovative techniques of chemically reducing, absorbing, or adsorbing 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 are described below. Non-Selective Catalytic Reduction (NSCR) A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied primarily in natural gas combustion applications. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 46

54 Minntac BART Report September 8, 2006 NSCR is often referred to as three-way conversion catalyst because it simultaneously reduces NO x, unburdened hydrocarbons (UBH), and carbon monoxide (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 combustion applications. This is due in large part to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration furnaces or similar combustion equipment. Therefore, this technology will not be further evaluated in this report. Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction SCR is a post-combustion 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 following chemical reaction: 4 NO + 4 NH 3 + O 2 4 N H 2 O (1) 2 NO NH 3 + O 2 3 N 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 temperature range of about 570 F 850 F for a normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and corrosion problems. A high temperature zeolite catalyst is also available; it can operate in the 600 F to 1000 F temperature range. However, these catalysts are very expensive. Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia increases during load changes due to the instability of the temperature in the catalyst bed as well as at low loads because of the low gas temperature. Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) control process as described below with a preheat process step to reheat the flue gas stream up to 47 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc

55 Minntac BART Report September 8, 2006 SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink (packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the preheating process. RSCR operates with several packed bed/scr reactor vessels. Gas flow alternates between vessels. Each of the vessels alternates between preheating/treating and heat recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95% versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to 70%. To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant would require research, test runs, and extended trials to identify potential issues related to catalyst selection, and impacts on plant systems, including the furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of a demonstration project. The timeline required to perform such a demonstration project would likely be two years to develop and agree on the test plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and report on the results. The results would not be available within the time window for establishing emission limits to be incorporated in the state implementation plan (SIP) by December There are several concerns about the technical feasibility and applicability of SCR on an indurating furnace: The composition of the indurating furnace flue gas is significantly different from the composition of the flue gas from the boilers that utilize SCR; The taconite dust is highly erosive and can cause significantly equipment damage. R-SCR has a number of valves which must be opened and closed frequently to switch catalyst/heat recovery beds. These valves could be subject to excessive wear in a taconite application due to the erosive nature of the taconite dust; SCR has not been applied downstream of a wet scrubber. Treating a stream saturated with water may present design problems in equipment sizing for proper heat transfer and in corrosion protection; Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 48

56 Minntac BART Report September 8, 2006 SCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by the local environment and have adverse impact. The impact of SCR on mercury emissions needs to be studied to determine whether or not mercury oxidation is a problem and to identify mitigation methods if needed. Recalling U.S. EPA s intention regarding available technologies to be considered for BART, as mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to learn how to apply a control technology to a completely new and significantly different source type. Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this BART analysis. However, SCR with reheat through a conventional duct burner (rather than using a regenerative heater) has been successfully implemented more widely and in higher airflow applications and will be carried forward in this analysis as available and applicable technology that is reasonably expected to be technically feasible. Low Temperature Oxidation (LTO) The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 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 forms nitric acid vapor as it contacts the water vapor in the flue gas (4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The nitrates are removed from the scrubbing system and discharged to an appropriate water treatment system. Commercially available LTO systems include Tri-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) Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 49

57 Minntac BART Report September 8, 2006 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) 2NaOH + 2NO 2 + ½ O 2 2NaNO 3 + H2O (2) Tri-NO x is a multi-staged wet scrubbing process in industrial use. Several process columns, each assigned a separate processing stage, are involved. In the first stage, the incoming material is quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO 2. Subsequent stages reduce NO 2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Another possible advantage of the Tri-NO x process is that concurrent scrubbing of sulfuric acid mist can be achieved. 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 are typically no higher than 300 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 lime or caustic. Ozone for LoTOx is generated on site with an electrically powered ozone generator. The ozone generation rate is controlled to match the amount needed for 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 review includes determining if the technology would apply to the process being reviewed. This would include a review and comparison of the chemical and physical properties required. Although it appears that the chemistry involved in the LTO technology applies to an indurating furnace, the technology has not been demonstrated on a taconite pellet indurating furnace. This raises uncertainties about how or whether the technology will transfer. The second component of the technical feasibility review includes determining if the 50 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc

58 Minntac BART Report September 8, 2006 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 ,000 acfm, which is quite small, compared to the indurating furnace flue gas flow rates of more than 500,000 acfm. This large scale-up is contrary to good engineering practices and could be problematic in maintaining the current removal efficiencies. In addition, only two of BOC s LoTOx installations are fully installed and operational applications. Therefore, although this is an emerging technology, the limited application means that it has not been demonstrated to be an effective technology in widespread application. There are several other concerns about the technical feasibility and applicability of LTO on an indurating furnace: The composition of the indurating furnace flue gas is significantly different than the composition of the flue gas from the boilers and process heaters that utilize LTO; The taconite dust in the flue gas is primarily magnetite (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 being generated which may change the reaction kinetics; consequently, this would necessitate either an increase in the amount of ozone generated or a decrease in the estimated control efficiency; The ozone that would be injected into the flue gas would react with the 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 also be a source of nitrate discharge to the tailings basin which would change the facility water chemistry which could cause operational problems and would likely cause additional problems with National Pollutant Discharge Elimination System (NPDES) discharge limits and requirements. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 51

59 Minntac BART Report September 8, 2006 In addition, application of this technology has not been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high moisture content. Using LTO at a taconite plant would require research, test runs, and extended trials to identify potential issues related to design for high airflows and impacts on plant systems, including the furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of a demonstration project. The timeline required to perform such a demonstration project would likely be two years to develop and agree on the test plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and report on the results. The results would not be available within the time window for establishing emission limits to be incorporated in the state implementation plan (SIP) by December Recalling U.S. EPA s intention regarding available technologies to be considered for BART, as mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to learn how to apply a control technology to a completely new and significantly different source type. Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for this application and will not be evaluated further. Step 2 Conclusion Based upon the determination within Step 2, the remaining NO x control technologies that are available and applicable to the indurating furnace process are identified in Table 5-4. The technical feasibility as determined in Step 2 is also included in Table 5-6. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 52

60 Minntac BART Report September 8, 2006 Table 5-6 Indurating Furnace NO x Control Technology Availability, Applicability, and Technical Feasibility SO 2 Pollution Control Technology External Flue Gas Recirculation (EFGR) Step 1 Step 2 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? Y Y N --- Low-NO x Burners Y Y Y (preheat Y section) Induced Flue Gas Recirculation Burners Y Y N --- Energy Efficiency Projects Y Y Y N Ported Kilns Y Y Y Y Alternative Fuels Y Y N Process Optimization using NO x CEMS Non-Selective Catalytic Reduction (NSCR) Selective Catalytic Reduction (SCR) with conventional reheat N (not required by BART) Y Y Y N Y N Y Y Y Y Regenerative SCR Y N Selective Non-Catalytic Reduction (SNCR) Low Temperature Oxidation (LTO) Y N Y N Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 53

61 Minntac BART Report September 8, A.ii.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies Table 5-7 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2. Table 5-7 Indurating Furnace NO x Control Technology Effectiveness NO x Pollution Control Technology SCR with Conventional Reheat Approximate Control Efficiency 80% Low-NO x Burners 10% Ported Kilns 5% 5.A.ii.d STEP 4 Evaluate Impacts and Document the Results Table 5-8 details the expected costs associated with installation of SCR with conventional reheat, low NO x burners, ported kilns, and a combination of low-no x burners and ported kilns. Equipment design was based on the maximum 24-hour emissions, vendor estimates (when available), and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that unit was scaled to each stack s flow rate using the 6/10 power law as shown in the following equation: Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B) 0.6 Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S. EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours per year. Operating costs of consumable materials, such as electricity, water, and chemicals were established based on the U.S. EPA control cost manual 28 and engineering experience, and were adjusted for the specific flow rates and pollutant concentrations. 28 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 54

62 Minntac BART Report September 8, 2006 Table 5-8 Indurating Furnace NO x Control Cost Summary Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 55

63 Minntac BART Report September 8, 2006 Due to space considerations, 60% 29 of the total capital investment was included in the costs to account for a retrofit installation. After a tour of the facility and discussions with facility staff, it was determined the space surrounding the furnaces is congested and the area surrounding the building supports vehicle and rail traffic to transport materials to and from the building. Additionally, the structural design of the existing building would not support additional equipment on the roof. Therefore, the cost estimates provide for additional site-work and construction costs to accommodate the new equipment within the facility. A site-specific estimate for site work, foundations, and structural steel was added to arrive at the total retrofit installed cost of the control technology. The site specific estimate was based on Barr s experience with similar projects. See Appendix C for an aerial photo of the facility. The detailed cost analysis is provided in Appendix A. Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective air pollution controls in the electric utility industry for large power plants are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix F. This cost-effective threshold is also an indirect measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for proposing BART in lieu of developing industry and site specific data. The annualized pollution control cost value was used to determine whether or not additional impacts analyses would be conducted for the technology. If the control cost was less than a screening threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are evaluated. MPCA set the screening level to eliminate technologies from requiring the additional impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 30. Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts. 29 U.S. EPA, CUE Cost Workbook Version 1.0. Page Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 56

64 Minntac BART Report September 8, 2006 The cost of NO x control for using SCR with conventional reheat is far in excess of any cost that is considered to be cost effective for BART, or even for BACT. Therefore, this technology is not carried forward in the analysis. The costs for ported kilns, low-no x burners, and ported kilns with low-no x burners, where appropriate, are below the MPCA recommended screening threshold of $12,000 per ton, and therefore are carried forward in the BART analysis. Energy and Environmental Issues The energy and non-air quality impacts for ported kilns, low-no x burners, and ported kilns with low- NO x burners, where appropriate, are presented in Table 5-9. Table 5-9 Indurating Furnace NO x Control Technology Impacts Assessment Control Technology Energy Impacts Other Impacts Ported Kilns None None Low-NO x Burners Improved efficiency of preheat section Ported Kilns with Improved efficiency Low-NO x Burners of preheat section None None 5.A.ii.e STEP 5 Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality impacts, when determining BART for an individual source. The baseline, or pre-bart, visibility impacts modeling was presented in section 4 of this document. However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline period and started operation in June The scrubber is considered a high efficiency scrubber for PM and a low efficiency scrubber for SO 2. Since the scrubber was installed after the baseline date, the emissions in the post-bart modeling analysis must be adjusted to account for the improved removal efficiency. Also as previously stated, replacement and reconfigured burners were installed into the preheat section of Line 6 which reduced the NO X emissions from the kiln of approximately 10% when the preheat section was in operation. Since the low-no X burners were installed after the baseline date, the emissions in the post-bart modeling analysis must also be adjusted to account for Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 57

65 Minntac BART Report September 8, 2006 the reduced emissions from Line 6. Therefore, the visibility impacts modeling presented in this section represent the post-baseline (i.e. post-bart) current operations of the facility. Predicted 24-Hour Maximum Emission Rates Consistent with the use of the highest daily emissions for baseline, or pre-bart, visibility impacts, the post-bart emissions to be used for the visibility impacts analysis should also reflect a maximum 24-hour average projected emission rate. Similar to the modeling for the baseline or pre- BART operating conditions, modeling was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling. In the visibility impacts modeling analysis, the emissions were adjusted as follows: Line 3 indurating furnaces emissions were adjusted to account for the new wet scrubber and the emissions; Line 6 indurating furnace emissions were adjusted to account for the replacement and reconfigured low-no x burners which have been installed in the preheat section. The emissions during current operations for all indurating furnaces were adjusted for each control technology, as appropriate; and The emissions from all other Subject-to-BART sources were not changed. Table 5-10 provides a summary of the modeled SO 2, NO X, and PM 24-hour maximum emission rates for the post-baseline (i.e. post-bart) current operations. Post-BART Visibility Impacts Modeling Results Results of the post-bart visibility impacts modeling for current operations are presented in Table The results summarize 98th percentile dv value and the number of days the facility contributes more than a 0.5 dv of visibility impairment at each of the Class I areas. As illustrated in tables 5-11, post-bart modeled visibility improvements are as follows: The current operation of the facility results in a visibility improvement of dv when burning natural gas in the kiln and dv when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline emissions. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 58

66 Minntac BART Report September 8, 2006 The installation of ported kilns on lines 3, 4, and 5 could result in a visibility improvement of dv when burning natural gas in the kiln, which represents a 5% improvement from the baseline when burning natural gas in the kiln. Since ported kilns do not reduce emissions when burning solid fuels, there is no additional visibility improvement for that scenario compared to current operations. It is very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation. The installation of low-no x burners on the preheat sections of lines 4, 5, and 7 results in a visibility improvement of dv when burning natural gas in the kiln, and dv when burning solid fuels in the kiln. Both of these values represent a 7% improvement compared to the baseline emissions. The combined installation of ported kilns on lines 3, 4, and 5 and low-no x burners on lines 4, 5, and 7 results in a visibility improvement of dv when burning natural gas in the kiln and dv when burning solid fuels in the kiln. Since ported kilns do not reduce emissions when burning solid fuels, it is again very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation and the visibility improvement for normal operation is only due to the low-nox burners on the preheat sections of lines 4, 5, and 7. A summary of visibility impacts for the total facility BART analysis are presented in Section 6. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 59

67 Minntac BART Report September 8, 2006 Table 5-10 Indurating Furnace Post- BART NO X Control - Predicted 24-hour Maximum Emission Rates Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 60

68 Minntac BART Report September 8, 2006 Table 5-11 Indurating Furnace Post-BART NO X Modeling Scenarios - Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 61

69 Minntac BART Report September 8, B External Combustion Sources Five utility plant heating boilers are subject-to-bart at this facility. As shown in section 4, the five boilers underwent a streamlined analysis for SO 2 and PM and one of the boilers underwent a streamlined analysis for NO x. Therefore, the remaining four boilers require a full BART analysis for NO X. The utility plant heating boilers are permitted to burn natural gas and fuel oil. The boilers are generally operated on a seasonal basis to provide heat to the facility. The highest emitting days are typically cold days in which the facility has a high heat demand and on which a natural gas curtailment occurs which requires the burning of the higher-emitting fuel oil. 5.B.i Nitrogen Oxide Controls To be able to control NO x it is important to understand how NO x is formed. There are three mechanisms by which NO x production occurs: Fuel bound nitrogen compounds in the fuel are oxidized in the combustion process to NO x. 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. Conditions for formation of thermal NO x exist primarily in the burner flame. 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.B.i.a STEP 1 Identify All Available Retrofit Control Technologies With some understanding of how NO x is formed, available and applicable control technologies were evaluated. Step 1 identifies a comprehensive list of all potential retrofit control technologies that were evaluated. Many emerging technologies were identified that are not currently commercially Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 62

70 Minntac BART Report September 8, 2006 available. Appendix G presents the current status of the availability and applicability of each technology. 5.B.i.b STEP 2 Eliminate Technically Infeasible Options Step 2 eliminates technically infeasible options which were identified as available in Step 1. As stated in section 2.B of this document, the technical feasibility of each option is determined by answering three specific questions: 1. Is the control technology available to the specific source which is undergoing the BART analysis? 2. Is the control technology an applicable technology for the specific source which is undergoing the BART analysis? 3. Are there source-specific issues/conditions that would make the control technology not technically feasible? The following describes retrofit NO x control technologies that were identified as available and applicable and discusses aspects of those technologies that determine whether or not the technology is technically feasible for indurating furnaces. External Flue Gas Recirculation (EFGR) External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures thereby reducing thermal 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 level in the combustion zone reduces flame temperatures; which in turn reduces NO x emissions. For a boiler to accommodate EFGR, air ducts and registers need to be able to withstand higher temperatures and flow rates, burners must be able to produce a stable flame with the flue gas added, and the firebox must be able to accommodate longer flame length to avoid flame impingement. Based on conversations with utility plant staff, the existing equipment cannot meet these requirements. Therefore, this option is not technically feasible and will not be further evaluated in this report. Low NO x Burners (LNB) Low-NO x burner (LNB) technology utilizes advanced burner design to reduce NO x formation through the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged combustion process that is designed to split fuel combustion into two zones. In the primary zone, NO x formation Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 63

71 Minntac BART Report September 8, 2006 is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen levels limit flame temperatures resulting in less NO x formation. The primary zone is then followed by a secondary zone in which the incomplete combustion products formed in the primary zone act as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce flame temperature to reduce NO x formation. In the secondary zone, combustion products formed in the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO x formation. Low NO x burners typically achieve NO x emission reductions of 25% - 50% for process boilers. LNB is a technology commonly used on boilers and is considered a available and applicable technology. Overfire Air (OFA) Overfire air diverts a portion of the total combustion air from the burners and injects it through separate air ports above the top level of burners. OFA is the typical NO x control technology used in boilers and is primarily geared to reduce thermal NO x. Staging of the combustion air creates an initial fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of thermal NO x by lowering combustion temperature and limiting the availability of oxygen in the combustion zone where NO x is most likely to be formed. LNB is a technology commonly used on boilers and is considered a available and applicable technology. In addition, OFA can also be used in combination with LNB. Induced Flue Gas Recirculation Burners Induced flue gas recirculation burners, also called ultra low-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 50-75%. This technology is considered an available and applicable technology. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 64

72 Minntac BART Report September 8, 2006 Energy Efficiency Projects Energy efficiency projects provide opportunities for a company to reduce their fuel consumption. Typically reduced fuel usage translates into reduced pollution emissions. An example energy efficiency project would be to reduce steam consumption which would decrease fuel burning requirements. Each project is very dependent upon the fuel usage, process equipment, type of product and many other variables. Due to the increased price of fuel, Minntac has already implemented several energy efficiency projects. Each project carries its own fuel usage reductions and potentially emission reductions. It would be impossible to assign a general potential emission reduction for the energy efficient category. Due to the uncertainty and generalization of this category, this will not be further evaluated in this report. However, it should be noted that Minntac will continue to evaluate and implement energy efficiency projects as they arise. Alternate Fuels The increased price of fuel has pushed companies to evaluate alternate fuel consumption and available fuel sources. These fuel sources come in all forms solid, liquid and gas. The heating boilers at Minntac are capable of burning natural gas and fuel oil. Since the boilers do not burn solid fuels, the options for alternate fuels are limited. Normal operation is on natural gas which is generally the lowest emitting fuel for a boiler. It is also important to note that U.S. EPA s intent is for facilities to consider alternate fuels as their option, not to direct the fuel choice. 31 Therefore, due to the uncertainty of alternative fuel costs, the limited options available, the fact that natural gas is the typical fuel burned in the boilers and the fact that BART is not intended to mandate a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in this report However, similar to energy efficiency, Minntac will continue to evaluate and implement alternate fuel usage as the feasibility arises. 31 Federal Register 70, no. 128 (July 6, 2005): Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 65

73 Minntac BART Report September 8, 2006 Post Combustion Controls NO x can be controlled using add-on systems located downstream of the boiler combustion process. The two main techniques in commercial service include the selective non catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a number of different process systems in each of these categories of control techniques. In addition to these treatment systems, there are a large number of other processes being developed and tested on the market. These approaches involve innovative techniques of chemically reducing, absorbing, or adsorbing 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) system is a post combustion add-on exhaust gas treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied primarily in natural gas combustion applications. NSCR is often referred to as three-way conversion catalyst because it simultaneously reduces NO x, unburdened hydrocarbons (UBH), and carbon monoxide (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 combustion applications. This is due in large part to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to liquid fuels. Since the highest emitting days occur while burning fuel oil, this technology will not be further evaluated in this report. Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction SCR is a post-combustion 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 following chemical reaction: Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 66

74 Minntac BART Report September 8, NO + 4 NH 3 + O 2 4 N H 2 O (1) 2 NO NH 3 + O 2 3 N 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 temperature range of about 570 F 850 F for a normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and corrosion problems. A high temperature zeolite catalyst is also available; it can operate in the 600 F 1000 F temperature range. However, these catalysts are very expensive. Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia increases during load changes due to the instability of the temperature in the catalyst bed as well as at low loads because of the low gas temperature. Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR) control process as described below with a preheat process step to reheat the flue gas stream up to SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink (packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the preheating process. RSCR operates with several packed bed/scr reactor vessels. Gas flow alternates between vessels. Each of the vessels alternates between preheating/treating and heat recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95% versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to 70%. SCR and R-SCR have both been applied to boilers. Although there may be concerns about the actual applicability of the technology to the boilers at this facility, the technologies will be considered feasible for the purposes of this report. Selective Non-Catalytic Reduction (SNCR) In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to convert NO to molecular nitrogen, N 2, and water. SNCR control efficiency is typically 25% - 60%. Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The relevant reactions are as follows: Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 67

75 Minntac BART Report September 8, 2006 NO + NH 3 + ¼O 2 N 2 + 3/2H 2 O (1) NH 3 + ¼O 2 NO + 3/2H 2 O (2) At temperature ranges of 1470 to 1830 F reaction (1) dominates. At temperatures above 2000 F, reaction (2) will dominate. This control option is considered feasible. Low Temperature Oxidation (LTO) The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including 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 forms nitric acid vapor as it contacts the water vapor in the flue gas (4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The nitrates are removed from the scrubbing system and discharged to an appropriate water treatment system. Commercially available LTO systems include Tri-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) 2NaOH + 2NO 2 + ½ O 2 2NaNO 3 + H2O (2) Tri-NO x is a multi-staged wet scrubbing process in industrial use. Several process columns, each assigned a separate processing stage, are involved. In the first stage, the incoming material is quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO 2. Subsequent Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 68

76 Minntac BART Report September 8, 2006 stages reduce NO 2 to nitrogen gas, while the oxygen becomes 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 ). 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 lime or caustic. Ozone for LoTOx is generated on site with an electrically powered ozone generator. The ozone generation rate is controlled to match the amount needed for 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. Although only two of BOC s LoTOx installations are fully installed and operational applications, LoTOx has been applied to gas and coal fired boilers. Therefore, although LoTOx is an emerging technology, has limited installations, and there may be concerns about the actual applicability of the technology to the boilers at this facility, the technologies will be considered feasible for the purposes of this report. Step 2 Conclusion Based upon the determination within Step 2, the remaining NO x control technologies that are available and applicable to the indurating furnace process are identified in Table The technical feasibility as determined in Step 2 is also included in Table Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 69

77 Minntac BART Report September 8, 2006 Table 5-12 Boiler NO x Control Technology Availability, Applicability, and Technical Feasibility Step 1 Step 2 Is this a generally available control technology? Is the control technology available to heating boiler? Is the control technology applicable to this specific source? Is it technically feasible for this source? SO 2 Pollution Control Technology External Flue Gas Recirculation (EFGR) Y Y N --- Low-NO x Burners Y Y Y Y Overfired Air Y Y Y Y Induced Flue Gas Recirculation (IFGR) Y Y Y Y Energy Efficiency Projects Y Y Y N Alternative Fuels Y Y Y N Non-Selective Catalytic Reduction (NSCR) Y Y Y N Selective Catalytic Reduction (SCR) Y Y Y Y Regenerative SCR Y Y Y Y Selective Non-Catalytic Reduction (SNCR) Low Temperature Oxidation (LTO) Y Y Y Y Y Y Y Y 5.B.i.c STEP 3 Evaluate Control Effectiveness of Remaining Control Technologies Table 5-13 describes the expected control efficiency from each of the remaining technically feasible control options as identified in Step 2. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 70

78 Minntac BART Report September 8, 2006 Table 5-13 Boiler NO x Control Technology Effectiveness NOx Pollution Control Technology Approximate Control Efficiency LoTOx 90% SCR 80% Low-NO x Burners with IFGR 75% R-SCR 70% Low-NO x Burners with OFA 67% Low-NO x Burners 50% Selective Non-Catalytic Reduction (SNCR) 50% 5.B.i.d STEP 4 Evaluate Impacts and Document the Results Table 5-14 details the expected costs associated with installation of NO x controls. Capital costs were calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates. Vendor estimates for capital costs based on a specific flow rate were scaled to each stack s flow rate using the 6/10 power law to account for the economy of scale. Operating costs were based on 93% utilization and 3,156 operating hours per year, which is based on historic operating records. Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant concentrations. Where applicable, a site-specific estimate for site-work, foundations, and structural steel was added based upon the facility site to arrive at the total retrofit installed cost of the control technology. The detailed cost analysis is provided in Appendix A. Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective air pollution controls in the electric utility industry for large power plants are in the range $1,000 to $1,300 per ton removed as illustrated in Appendix F. This cost-effective threshold is also an indirect measure of affordability for the electric utility industry used by USEPA to support the BART rulemaking process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for proposing BART in lieu of developing industry and site specific data. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 71

79 Minntac BART Report September 8, 2006 Table 5-14 Boiler NO x Control Cost Summary Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 72

80 Minntac BART Report September 8, 2006 The annualized pollution control cost value was used to determine whether or not additional impacts analyses would be conducted for the technology. If the control cost was less than a screening threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are evaluated. MPCA set the screening level to eliminate technologies from requiring the additional impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant 32. Therefore, all air pollution controls with annualized costs less than this screening threshold will be evaluated for visibility improvement, energy and other impacts. The costs of NO x control for SCR, low-nox burners with flue gas recirculation, low-no X burners with overfire air, and SNCR are far in excess of any cost that is considered to be cost effective for BART, or even for BACT. Therefore, these technologies are not carried forward in the analysis. The costs for low-no x burners are below the MPCA recommended screening threshold of $12,000 per ton, and therefore are carried forward in the BART analysis. Energy and Environmental Impacts The energy and environmental impacts for low-no x burners are minimal. 5.B.i.e STEP 5 Evaluate Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality impacts, when determining BART for an individual source. The baseline, or pre-bart, visibility impacts modeling was presented in section 4 of this document. Predicted 24-Hour Maximum Emission Rates Consistent with the use of the highest daily emissions for baseline, or pre-bart, visibility impacts, the post-bart emissions to be used for the visibility impacts analysis should also reflect a maximum 24-hour average project emission rate. The stack parameters (location, height, velocity, and temperature) were assumed to remain unchanged from the baseline modeling. Table 5-15 provides a summary of the modeled NO X 24-hour maximum emission rates for the postbaseline (i.e. post-bart) operating scenario for installing low-no X burners on the four boilers. 32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 73

81 Minntac BART Report September 8, 2006 Post-BART Visibility Impacts Modeling Results Results of the post-bart visibility impacts modeling summarize 98th percentile dv value and the number of days the facility contributes more than a 0.5 dv of visibility impairment at each of the Class I areas. As illustrated in tables 5-16, post-bart modeled visibility improvements are as follows: The installation of low-no x burners on the boilers results in a visibility improvement of dv which is a 0.1% improvement compared to the baseline emissions. Based on these modeling results, the visibility improvement for the installation of low-no x burners on the boilers is basically negligible. A summary of visibility impacts for the total facility BART analysis are presented in Section 6. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 74

82 Minntac BART Report September 8, 2006 Table 5-15 Boiler Post-BART NO X Control - Predicted 24-hour Maximum Emission Rates Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 75

83 Minntac BART Report September 8, 2006 Table 5-16 Boiler Post-BART NO X Modeling Scenarios - Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 76

84 Minntac BART Report September 8, Visibility Impacts As previously stated in section 4 of this document, states are required to consider the degree of visibility improvement resulting from the retrofit technology, in combination with other factors such as economic, energy and other non-air quality, when determining BART for an individual source. The baseline, or pre-bart, visibility impacts modeling was presented in section 4 of this document. The visibility impacts of individual control technologies were presented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. This section of the report evaluates the various BART control scenarios utilizing both SO 2 and NO x controls, and determines the resulting degree of visibility improvement. The intent of this section is to present the modeling scenarios for combinations of SO 2 and NO x controls. However, since there were no control technologies for SO 2 that required visibility impacts analysis, there are no SO 2 /NO x combinations that need to be evaluated. Therefore, no new or additional modeling scenarios are presented in this section. 6.A Post-BART Modeling Scenarios All of the modeling scenario results, as presented in sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e or this report, are presented in Table 6-1. As previously stated, no new or additional modeling scenarios are presented. 6.B Post-BART Modeling Results Results of all post-bart modeling scenarios are presented in Table 6-1. These results were also presented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. As previously stated, no new or additional modeling scenarios are presented. The results summarize 98th percentile dv value and the number of days the facility contributes more than a 0.5 dv of visibility impairment at each of the Class I areas. When reviewing the modeling results for the indurating furnaces, it is important to note the following: Current Operation: o The current operation of the facility results in a visibility improvement of dv when burning natural gas in the kiln and dv when burning solid fuels in the kiln. Both of these values represent a 3% improvement compared to the baseline emissions. 77 Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc

85 Minntac BART Report September 8, 2006 Ported Kilns: o Natural Gas Operation: The installation of ported kilns on lines 3, 4, and 5 results in a visibility improvement of dv when burning natural gas in the kiln, which represents an addition dv compared to the current operation when burning natural gas in the kiln. This is a 5% improvement from the baseline when burning natural gas in the kiln and a 2% improvement from the current operation when burning natural gas in the kiln. o Solid Fuel Operation: Since ported kilns do not reduce emissions when burning solid fuels, there is no additional visibility improvement for that scenario compared to current operations. It is very important to note that normal operation of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no improvement in visibility for ported kilns under normal operation. Low-NO X Burners: o Natural Gas Operation: The installation of low-no x burners on the preheat sections of lines 4, 5, and 7 results in a visibility improvement of dv when burning natural gas in the kiln which represents an addition dv compared to the current operation when burning natural gas in the kiln. This is a 7% improvement from the baseline when burning natural gas and a 4% improvement from the current operation when burning natural gas. o Solid Fuel Operation: The installation of low-no x burners on the preheat sections of lines 4, 5, and 7 results in a visibility improvement of dv when burning solid fuels in the kiln which represents an addition dv compared to the current operation when burning solid fuels in the kiln. This is a 7% improvement from the baseline when burning solid fuels in the kiln and a 4% improvement from the current operation when burning solid fuels in the kiln. Ported Kilns with Low-NO X Burners: o Natural Gas Operation: The combined installation of ported kilns on lines 3, 4, and 5 and low-no x burners on lines 4, 5, and 7 results in a visibility improvement of dv when burning natural gas in the kiln which represents an addition dv Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 78

86 Minntac BART Report September 8, 2006 compared to the current operation when burning natural gas in the kiln. This is a 9% improvement from the baseline when burning natural gas in the kiln and a 6% improvement from the current operation when burning natural gas in the kiln. o Solid Fuel Operation: The combined installation of ported kilns on lines 3, 4, and 5 and low-no x burners on lines 4, 5, and 7 results in a visibility improvement of dv when burning solid fuels in the kiln which represents an addition dv compared to the current operation when burning solid fuels in the kiln. This is a 7% improvement from the baseline when burning solid fuels in the kiln and a 7% improvement from the current operation when burning solid fuels in the kiln. When reviewing the modeling results for the boilers, it is important to note the following: The installation of low-no x burners on the boilers results in a visibility improvement of dv which is a 0.1% improvement compared to the baseline emissions. Based on these modeling results, the visibility improvement for the installation of low-no x burners on the boilers is basically negligible. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 79

87 Minntac BART Report September 8, 2006 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 80

88 Minntac BART Report September 8, Select BART The final step in the BART analysis is to select the best alternative using the results of steps 1 through 5, as presented in section 5 of this report. 7.A Indurating Furnaces Minntac operates five indurating furnaces which are subject-to-bart: Line 3 Rotary Kiln (EU 225 / SV 103) Line 4 Rotary Kiln (EU 261 / SV 118) Line 5 Rotary Kiln (EU 282 / SV 127) Line 6 Rotary Kiln (EU 315 / SV 144) Line 7 Rotary Kiln (EU 334 / SV 151) As presented in section 3 of the report, the PM emissions from the indurating furnaces were subject to a streamlined BART analysis based on the specific provision that compliance with the Taconite MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions is equivalent to BART. The Taconite MACT standard includes requirements for performance testing and continuous parametric monitoring for compliance demonstration. As presented in section 5.A of this report, the five indurating furnaces at Minntac were required to undergo a full BART analysis for NO x and SO 2. As presented in section 5.A of this report, the indurating furnace was required to undergo a full BART analysis for SO 2 and NO x. The selection is based on consideration of all of the criteria presented in MPCA and U.S. EPA guidance for determining BART, as presented in this report. The following technologies were identified as technically feasible and subject to the full BART analysis: new wet scrubbers that control PM and SO 2, add-on secondary wet scrubber to control additional SO 2 control, ported kiln, SCR (with conventional flue gas reheat), and NO x CEMS. The secondary wet scrubber, ported kiln, and SCR alternatives were not proposed as BART for the following reasons: Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 81

89 Minntac BART Report September 8, 2006 Ported Kiln Converting the kilns 3, 4 and 5 to ported kilns would result in only an estimated 5% decrease in NO x emissions when burning gas in the kiln and the corresponding impact on visibility is also minimal. It would not result in emissions reductions when burning solid fuel in the kiln, which is the primary fuel used by Minntac. Therefore, the technology will not result in any significant visibility improvement at the Class I areas compared to the current operation. Further, it is not cost effective at an estimated amount of more than $5,000/ton NO x removed. Based on the consideration of all of the criteria presented in the BART analysis, Minntac proposes the following as BART for SO 2 and NO X for the Indurating Furnaces: BART for SO 2 : o SO 2 emissions will be controlled by the existing wet scrubbers, which will be operated as required in accordance with provisions of the Taconite MACT. o SO 2 emission limit for the Indurating Furnace on Line 3 will be determined based on upcoming performance testing to determine the actual emission rate from the furnace with the addition of the new scrubber. A proposed SO 2 limit for the furnace in the draft PSD permit for Minntac does not reflect the recently installed wet scrubber. o SO 2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the limits which are based on using the existing wet scrubbers and reflect air dispersion modeling results for regional haze as proposed in the draft PSD permit: Line 4 = 182 lbs/hr Line 5 = 182 lbs/hr Line 6 = 284 lbs/hr Line 7 = 284 lbs/hr o Compliance will be initially be demonstrated by a performance test at each furnace. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 82

90 Minntac BART Report September 8, 2006 o Continuous compliance will be demonstrated by continuous monitoring of scrubber water flow rate and scrubber pressure drop, which are the same parameters that will be monitored under the Taconite MACT. The operating limits will be determined based on the initial SO 2 compliance test and will be based on a 24-hour block average, consistent with the Taconite MACT. BART for NO x : o NO x emissions will be controlled as follows: Line 3: Existing combustion controls and fuel blending. Line 3 does not currently use burners in its pre-heat section, and therefore low-no x burners cannot be applied at this furnace. Line 4: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. Line 5: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. Line 6: Operation of low-no x burners on the pre-heat section (installed as replacement and reconfigured burners in April 2006), existing combustion controls, and fuel blending. Line 7: Installation of low-no x burners on the pre-heat section, existing combustion controls, and fuel blending. o NO x emission limits will be proposed by the facility 12-months after the installation of the low-no x burners to allow the facility sufficient time for process and emissions monitoring using NO x CEMS to determine the actual emission rates under a variety of operating conditions. Although the facility anticipates a significant reduction in NO x emissions with the installation of the low-no x burners, the actual emissions reduction cannot be determined until the burners are operated under a variety of operation conditions. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 83

91 Minntac BART Report September 8, 2006 o Initial and continuous compliance will be demonstrated after the appropriate emission limits have been determined. Compliance will be demonstrated using the NO x CEMS and will be based on a 30-day rolling average. The schedule for implementation of these controls, specifically installation of low-no x burners and subsequent testing to demonstrate the appropriate BART emission limit, will be within the 5-year time-frame required for BART implementation. In addition, Minntac will continue to evaluate energy efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission rates. Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for the installation of low-no x burners, the proposed BART controls will result in visibility improvement on the 98 th percentile day of approximately dv when burning gas in the kiln and dv when burning solid fuels in the kiln. This is a visibility improvement of approximately 7% compared to the baseline (pre-bart) operating conditions. 7.B External Combustion Sources Minntac operates 5 utility plant heating boilers which are subject-to-bart: o Utility Plant Heating Boiler #1 (EU 001 / SV 001) o Utility Plant Heating Boiler #2 (EU 002 / SV 002) o Utility Plant Heating Boiler #3 (EU 003 / SV 003) o Utility Plant Heating Boiler #4 (EU 004 / SV 004) o Utility Plant Heating Boiler #5 (EU 005 / SV 005) As presented in section 3 of the report, the SO 2 and PM emissions from all five boilers underwent a streamlined BART analysis based on the de minimis modeling results as presented in section 3.F. In addition, the NO x emissions from boiler #3 underwent a streamlined BART analysis for NO x. Based on the consideration of all of the criteria presented in the BART analysis, Minntac proposes no additional controls, emission limits, or monitoring requirements for the NO x emissions from four heating boilers. This is based on the conclusion that the control technologies that meet the cost screening threshold do not provide significant improvement in the visibility modeling. It is also Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 84

92 Minntac BART Report September 8, 2006 important to note that due to the relatively small size of the boilers and the low hours of operation, the actual visibility impact of the boilers is small. Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL doc 85

93 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required 3.A. Indurating Furnaces EU 223 Traveling Grate (Line 3) SV 103 BART Analysis for SO2 + NOx EU 225 Rotary Kiln (Line 3) Incl with EU SV 103 BART Analysis for SO2 + NOx EU 226 Pellet Cooler Secondary Air (Line 3) Incl with EU SV 103 BART Analysis for SO2 + NOx EU 259 Traveling Grate (Line 4) , SV 118 BART Analysis for SO2 + NOx EU 260 Recouperative System Air (Line 4) Incl with EU SV 118 BART Analysis for SO2 + NOx EU 261 Rotary Kiln (Line 4) Incl with EU SV 118 BART Analysis for SO2 + NOx EU 262 Pellet Cooler Secondary Air (Line 4) Incl with EU SV 118 BART Analysis for SO2 + NOx EU 280 Traveling Grate (Line 5) , SV 127 BART Analysis for SO2 + NOx EU 281 Recouperative System Air (Line 5) Incl with EU SV 127 BART Analysis for SO2 + NOx EU 282 Rotary Kiln (Line 5) Incl with EU SV 127 BART Analysis for SO2 + NOx EU 283 Pellet Cooler Secondary Air (Line 5) Incl with EU SV 127 BART Analysis for SO2 + NOx EU 313 Traveling Grate (Line 6) , SV 144 BART Analysis for SO2 + NOx EU 314 Recoup System (Line 6) Incl with EU SV 144 BART Analysis for SO2 + NOx EU 315 Rotary Kiln (Line 6) Incl with EU SV 144 BART Analysis for SO2 + NOx EU 316 Pellet Cooler Secondary Air (Line 6) Incl with EU SV 144 BART Analysis for SO2 + NOx EU 332 Traveling Grate (Line 7) , SV 151 BART Analysis for SO2 + NOx EU 333 Recoup System (Line 7) Incl with EU SV 151 BART Analysis for SO2 + NOx EU 334 Rotary Kiln (Line 7) Incl with EU SV 151 BART Analysis for SO2 + NOx EU 335 Pellet Cooler Secondary Air (Line 7) Incl with EU SV 151 BART Analysis for SO2 + NOx 3.B. PM-Only Taconite MACT Emission Units EU 013 Dump Pocket SV 013 None EU 014 Crusher Incl with EU SV 013 None EU 015 Dump Pocket SV 014 None EU 016 Crusher Incl with EU SV 014 None EU 017 Dump Pocket SV 015 None EU 018 Crusher Incl with EU SV 015 None EU 019 Dump Pocket Incl with EU SV 015 None EU 020 Crusher Incl with EU SV 015 None EU 022 Pre-1969 Panfeeder SV 016 None EU 023 Pre-1969 Panfeeder Incl with EU SV 016 None EU 024 Pre-1969 Panfeeder SV 017 None EU 025 Pre-1969 Panfeeder Incl with EU SV 017 None EU 026 Post-1969 Panfeeder SV 018 None EU 027 Post-1969 Panfeeder Incl with EU SV 018 None EU 034 Ore Transfer From to SV 021 None

94 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 035 Ore Transfer From to Incl with EU SV 021 None EU 036 Ore Transfer From to SV 022 None EU 037 Ore Transfer Fr to Turn Bin Incl with EU SV 022 None EU 038 Ore Transfer Fr to Turn Bin Incl with EU SV 022 None EU 039 Ore Transfer From to Incl with EU SV 022 None EU 040 Ore Transfer From to SV 023 None EU 041 Ore Transfer From to SV 024 None EU 042 Ore Transfer From to Incl with EU SV 024 None EU 043 Ore Transfer From to Incl with EU SV 024 None EU 044 Ore Transfer From to Turn Bin Incl with EU SV 024 None EU 045 Ore Transfer From to Turn Bin Incl with EU SV 024 None EU 046 Ore Transfer From to Turn Bin Incl with EU SV 024 None EU 047 Ore Transfer From to SV 025 None EU 048 Ore Transfer From Stockpile to SV 026 None EU 052 Ore Transfer Fr to or SV 030 None EU 053 Ore Transfer From to Incl with EU SV 030 None EU 054 Secondary Crusher SV 031 None EU 055 Secondary Crusher SV 032 None EU 056 Secondary Crusher SV 033 None EU 057 Secondary Crusher SV 034 None EU 058 Ore Transfer From to SV 035 None EU 059 Ore Transfer From to Incl with EU SV 035 None EU 060 Ore Transfer From to Incl with EU SV 035 None EU 061 Ore Transfer From to SV 036 None EU 062 Ore Transfer From to Incl with EU SV 036 None EU 063 Ore Transfer From to Incl with EU SV 036 None EU 064 Ore Transfer From to Incl with EU SV 036 None EU 065 Ore Transfer From to SV 037 None EU 066 Ore Transfer From to Incl with EU SV 037 None EU 067 Ore Transfer From to Incl with EU SV 037 None EU 068 Ore Transfer From to Incl with EU SV 037 None EU 069 Tertiary Crusher SV 038 None EU 070 Tertiary Crusher SV 039 None EU 071 Tertiary Crusher SV 040 None EU 072 Tertiary Crusher SV 041 None EU 073 Tertiary Crusher SV 042 None

95 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 074 Tertiary Crusher SV 043 None EU 075 Tertiary Crusher SV 044 None EU 076 Tertiary Crusher SV 045 None EU 077 Tertiary Crusher SV 046 None EU 078 Tertiary Crusher SV 047 None EU 079 Tertiary Crusher SV 048 None EU 080 Tertiary Crusher SV 049 None EU 081 Tertiary Crusher SV 050 None EU 082 Tertiary Crusher SV 051 None EU 083 Tertiary Crusher SV 052 None EU 084 Tertiary Crusher SV 053 None EU 085 Ore Transfer From to SV 054 None EU 086 Ore Transfer From to Incl with EU SV 054 None EU 087 Ore Transfer From to Incl with EU SV 054 None EU 088 Ore Transfer From to Incl with EU SV 054 None EU 089 Ore Transfer From to Incl with EU SV 054 None EU 090 Ore Transfer From to Incl with EU SV 054 None EU 091 Ore Transfer From to Incl with EU SV 054 None EU 092 Ore Transfer From to Incl with EU SV 054 None EU 093 Secondary Crusher SV 055 None EU 094 Secondary Crusher SV 056 None EU 095 Secondary Crusher SV 057 None EU 096 Secondary Crusher SV 058 None EU 097 Secondary Crusher SV 059 None EU 098 Ore Transfer From to SV 060 None EU 099 Ore Transfer From to Incl with EU SV 060 None EU 100 Ore Transfer From to Incl with EU SV 060 None EU 101 Ore Transfer From to Incl with EU SV 060 None EU 102 Ore Transfer From to SV 061 None EU 103 Secondary Crusher SV 062 None EU 104 Ore Transfer From to SV 063 None EU 105 Ore Transfer From to Incl with EU SV 063 None EU 106 Secondary Crusher SV 064 None EU 107 Secondary Crusher SV 065 None EU 108 Secondary Crusher SV 066 None EU 109 Secondary Crusher SV 067 None

96 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 110 Secondary Crusher SV 068 None EU 111 Ore Transfer From to SV 069 None EU 112 Ore Transfer From to SV 070 None EU 113 Ore Transfer From to Incl with EU SV 070 None EU 114 Ore Transfer From to SV 071 None EU 115 Ore Transfer From to Incl with EU SV 071 None EU 116 Ore Transfer From to SV 072 None EU 117 Ore Transfer From to Incl with EU SV 072 None EU 118 Ore Transfer From to Incl with EU SV 072 None EU 119 Ore Transfer From to Incl with EU SV 072 None EU 120 Ore Transfer From to Incl with EU SV 072 None EU 121 Ore Transfer From to Incl with EU SV 072 None EU 122 Ore Transfer From to Incl with EU SV 072 None EU 123 Ore Transfer From to Incl with EU SV 072 None EU 124 Ore Transfer From to Incl with EU SV 072 None EU 125 Ore Transfer From to Incl with EU SV 072 None EU 126 Ore Transfer From to Incl with EU SV 072 None EU 127 Ore Transfer From to Incl with EU SV 072 None EU 128 Tertiary Crusher SV 073 None EU 129 Tertiary Crusher SV 074 None EU 130 Tertiary Crusher SV 075 None EU 131 Tertiary Crusher SV 076 None EU 132 Tertiary Crusher SV 077 None EU 133 Tertiary Crusher SV 078 None EU 134 Tertiary Crusher SV 079 None EU 135 Tertiary Crusher SV 080 None EU 136 Tertiary Crusher SV 081 None EU 137 Tertiary Crusher SV 082 None EU 138 Tertiary Crusher SV 083 None EU 140 Ore Transfer From to SV 085 None EU 141 Ore Transfer From to Incl with EU SV 085 None EU 144 Ore Transfer From to SV 087 None EU 145 Ore Transfer From to Incl with EU SV 087 None EU 146 Ore Transfer From to Incl with EU SV 087 None EU 147 Ore Transfer From to Incl with EU SV 087 None EU 155 Ore Transfer From to Bin SV 089 None

97 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 156 Ore Transfer From to Bin Incl with EU SV 089 None EU 157 Ore Transfer From to Bin Incl with EU SV 089 None EU 158 Ore Transfer From to Bin Incl with EU SV 089 None EU 159 Ore Transfer From to Bin Incl with EU SV 089 None EU 160 Ore Transfer From to Incl with EU SV 089 None EU 161 Ore Transfer From to Incl with EU SV 089 None EU 162 Ore Transfer From to Bin SV 090 None EU 163 Ore Transfer From to Bin Incl with EU SV 090 None EU 164 Ore Transfer From to Bin Incl with EU SV 090 None EU 165 Ore Transfer From to Bin Incl with EU SV 090 None EU 166 Ore Transfer From to Bin Incl with EU SV 090 None EU 167 Ore Transfer From to Incl with EU SV 090 None EU 168 Ore Transfer From to Incl with EU SV 090 None EU 169 Ore Transfer From to Bin SV 091 None EU 170 Ore Transfer From to Bin Incl with EU SV 091 None EU 171 Ore Transfer From to Bin Incl with EU SV 091 None EU 172 Ore Transfer From to Bin Incl with EU SV 091 None EU 173 Ore Transfer From to Bin Incl with EU SV 091 None EU 174 Ore Transfer From to Incl with EU SV 091 None EU 175 Ore Transfer From to Incl with EU SV 091 None EU 176 Ore Transfer From to Bin SV 092 None EU 177 Ore Transfer From to Bin Incl with EU SV 092 None EU 178 Ore Transfer From to Bin Incl with EU SV 092 None EU 179 Ore Transfer From to Bin Incl with EU SV 092 None EU 180 Ore Transfer From to Bin Incl with EU SV 092 None EU 181 Ore Transfer From to Incl with EU SV 092 None EU 182 Ore Transfer From to Incl with EU SV 092 None EU 183 Ore Transfer From to Bin SV 093 None EU 184 Ore Transfer From to Bin Incl with EU SV 093 None EU 185 Ore Transfer From to Bin Incl with EU SV 093 None EU 186 Ore Transfer From to Bin Incl with EU SV 093 None EU 187 Ore Transfer From to Bin Incl with EU SV 093 None EU 188 Ore Transfer From to Incl with EU SV 093 None EU 189 Ore Transfer From to Incl with EU SV 093 None EU 190 Ore Transfer From to SV 094 None EU 191 Ore Transfer From to Incl with EU SV 094 None

98 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 192 Ore Transfer From to Incl with EU SV 094 None EU 193 Ore Transfer From to Incl with EU SV 094 None EU 194 Ore Transfer From to Bin SV 095 None EU 195 Ore Transfer From to Bin Incl with EU SV 095 None EU 196 Ore Transfer From to Bin Incl with EU SV 095 None EU 197 Ore Transfer From to Bin Incl with EU SV 095 None EU 198 Ore Transfer From to Bin Incl with EU SV 095 None EU 199 Ore Transfer From to Incl with EU SV 095 None EU 200 Ore Transfer From to Incl with EU SV 095 None EU 201 Ore Transfer From to Bin SV 096 None EU 202 Ore Transfer From to Bin Incl with EU SV 096 None EU 203 Ore Transfer From to Bin Incl with EU SV 096 None EU 204 Ore Transfer From to Incl with EU SV 096 None EU 205 Ore Transfer From to Incl with EU SV 096 None EU 206 Ore Transfer From to Bin Incl with EU SV 096 None EU 207 Ore Transfer From to Bin Incl with EU SV 096 None EU 208 Ore Transfer From to Bin SV 097 None EU 209 Ore Transfer From to Bin Incl with EU SV 097 None EU 210 Ore Transfer From to Bin Incl with EU SV 097 None EU 211 Ore Transfer From to Bin Incl with EU SV 097 None EU 212 Ore Transfer From to Bin Incl with EU SV 097 None EU 213 Ore Transfer From to Incl with EU SV 097 None EU 214 Ore Transfer From to Incl with EU SV 097 None EU 221 Traveling Grate SV 101 None EU 222 Traveling Grate SV 102 None EU 227 L3 Pellet Cooler SV 104 None EU 228 L3 Pellet Cooler Dump Zone SV 105 None EU 229 L3 Feeder 041/046 Belts SV 106 None EU 230 Pellet Trnsfr Fr to or SV 107 None EU 231 Pellet Trnsfr Fr to or Incl with EU SV 107 None EU 232 Pellet Transfer From to SV 108 None EU 233 Pellet Transfer From to Incl with EU SV 108 None EU 234 Pellet Trnsfr Fr to or SV 109 None EU 235 Pellet Trnsfr Fr to or Incl with EU SV 109 None EU 257 Traveling Grate SV 116 None EU 258 Traveling Grate SV 117 None

99 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 263 L4 Pellet Cooler SV 119 None EU 264 L4 Conv. Trans. Feeder SV 120 None EU 265 L4 Pellet Cooler Dump Zone SV 121 None EU 266 Pellet Trnsfr Fr to or SV 122 None EU 267 Pellet Trnsfr Fr to or Incl with EU SV 122 None EU 278 Traveling Grate SV 125 None EU 279 Traveling Grate SV 126 None EU 284 L5 Pellet Cooler SV 128 None EU 285 L5 Conv. Trans. Feeder SV 129 None EU 286 L5 Pellet Cooler Dump Zone SV 130 None EU 287 Pellet Trnsfr Fr to or SV 131 None EU 288 Pellet Trnsfr Fr to or Incl with EU SV 131 None EU 289 Conveyor SV 132 None EU 290 Conveyor SV 133 None EU 291 Conveyor SV 134 None EU 292 Conveyor SV 135 None EU 293 Conveyor SV 136 None EU 294 Conveyor SV 137 None EU 295 Pellet Transfer From to SV 138 None EU 296 Pellet Transfer From to Incl with EU SV 138 None EU 311 Traveling Grate SV 142 None EU 312 Traveling Grate SV 143 None EU 318 Pellet Trnsfr Fr to or SV 146 None EU 319 Pellet Trnsfr Fr to or Incl with EU SV 146 None EU 330 Traveling Grate SV 149 None EU 331 Traveling Grate SV 150 None EU 337 Pellet Trnsfr Fr to or SV 153 None EU 338 Pellet Trnsfr Fr to or Incl with EU SV 153 None EU 339 Pellet Transfer From to SV 154 None EU 340 Pellet Transfer From to SV 155 None EU 341 Conveyor SV 156 None EU 342 Conveyor SV 157 None EU 343 Conveyor SV 158 None EU 344 Conveyor SV 159 None EU 345 Conveyor SV 160 None EU 346 Conveyor SV 161 None

100 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 347 Conveyor SV 162 None EU 348 Conveyor SV 163 None EU 349 Conveyor SV 164 None EU 350 Conveyor SV 165 None EU 351 Conveyor SV 166 None EU 352 Conveyor SV 167 None EU 353 Conveyor SV 168 None EU 354 Conveyor SV 169 None EU 355 Conveyor SV 170 None EU 359 Pellet Transfer From to SV 174 None EU 360 Conveyor SV 175 None EU 361 Pellet Transfer From to SV 176 None EU 362 Conveyor SV 177 None EU 363 Pellet Transfer From to SV 178 None EU 364 Pellet Transfer From to SV 179 None EU 365 Conveyor SV 179 None EU 366 Pellet Hopper SV 180 None EU 397 Line 6 Cooler Vent Stack SV 196 None EU 398 Line 7 Cooler Vent Stack SV 197 None 3.C. Sources of fugitive PM that are subject to MACT standards N/A N/A - Total facility fugitive sources , N/A None 3.D. Non-MACT Units and Fugitive Sources (PM only) Limestone Transfer EU 148 (formerly Ore Transfer From to Bin ) SV 088 None EU 149 Limestone Transfer (formerly Ore Transfer From to Bin ) Incl with EU SV 088 None EU 150 Limestone Transfer (formerly Ore Transfer From to Bin ) Incl with EU SV 088 None EU 151 Limestone Transfer (formerly Ore Transfer From to ) Incl with EU SV 088 None EU 152 Limestone Transfer (formerly Ore Transfer From to Bin ) Incl with EU SV 088 None EU 153 Limestone Transfer (formerly Ore Transfer From to ) Incl with EU SV 088 None EU 154 Limestone Transfer (formerly Ore Transfer From to Bin ) Incl with EU SV 088 None EU 217 Pekay Mixer SV 100 None

101 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 218 Pekay Mixer Incl with EU SV 100 None EU 219 Pekay Mixer Incl with EU SV 100 None EU 220 Pekay Mixer Incl with EU SV 100 None EU 236 Bentonite Bin SV 110 None EU 237 Bentonite Bin Incl with EU SV 110 None EU 238 Bentonite Bin Incl with EU SV 110 None EU 239 Bentonite Day Bin SV 111 None EU 240 Bentonite Day Bin Incl with EU SV 111 None EU 241 Bentonite Day Bin Incl with EU SV 111 None EU 242 Bentonite Day Bin Incl with EU SV 111 None EU 243 Bentonite Unloading Hopper SV 112 None EU 244 Bentonite Storage Bin SV 113 None EU 245 Bentonite Storage Bin Incl with EU SV 113 None EU 246 Bentonite Storage Bin Incl with EU SV 113 None EU 247 Storage Bin SV 114 None EU 248 Storage Bin Incl with EU SV 114 None EU 249 Storage Bin Incl with EU SV 114 None EU 250 Storage Bin Incl with EU SV 114 None EU 251 Storage Bin Incl with EU SV 114 None EU 252 Pekay Mixer SV 115 None EU 253 Pekay Mixer Incl with EU SV 115 None EU 254 Pekay Mixer Incl with EU SV 115 None EU 255 Pekay Mixer Incl with EU SV 115 None EU 256 Pekay Mixer Incl with EU SV 115 None EU 268 Storage Bin SV 123 None EU 269 Storage Bin Incl with EU SV 123 None EU 270 Storage Bin Incl with EU SV 123 None EU 271 Storage Bin Incl with EU SV 123 None EU 272 Storage Bin Incl with EU SV 123 None EU 273 Pekay Mixer SV 124 None EU 274 Pekay Mixer Incl with EU SV 124 None EU 275 Pekay Mixer Incl with EU SV 124 None EU 276 Pekay Mixer Incl with EU SV 124 None EU 277 Pekay Mixer Incl with EU SV 124 None EU 297 Bentonite Storage Bin SV 139 None EU 298 Bentonite Storage Bin Incl with EU SV 139 None

102 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 299 Bentonite Storage Bin Incl with EU SV 139 None EU 300 Bentonite Unloading Hopper Incl with EU SV 139 None EU 301 Storage Bin SV 140 None EU 302 Storage Bin Incl with EU SV 140 None EU 303 Storage Bin Incl with EU SV 140 None EU 304 Storage Bin Incl with EU SV 140 None EU 305 Storage Bin Incl with EU SV 140 None EU 306 Pekay Mixer SV 141 None EU 307 Pekay Mixer Incl with EU SV 141 None EU 308 Pekay Mixer Incl with EU SV 141 None EU 309 Pekay Mixer Incl with EU SV 141 None EU 310 Pekay Mixer Incl with EU SV 141 None EU 320 Storage Bin SV 147 None EU 321 Storage Bin Incl with EU SV 147 None EU 322 Storage Bin Incl with EU SV 147 None EU 323 Storage Bin Incl with EU SV 147 None EU 324 Storage Bin Incl with EU SV 147 None EU 325 Pekay Mixer SV 148 None EU 326 Pekay Mixer Incl with EU SV 148 None EU 327 Pekay Mixer Incl with EU SV 148 None EU 328 Pekay Mixer Incl with EU SV 148 None EU 329 Pekay Mixer Incl with EU SV 148 None EU 367 Coal Unload Hopper SV 181 None EU 368 Coal Hopper Conveyor Incl with EU SV 181 None EU 369 Coal Conv. Feed Incl with EU SV 181 None EU 370 Coal Silo Feed Incl with EU SV 181 None EU 371 Coal Silo Discharge Incl with EU SV 181 None EU 372 Coal Silo Transfer Incl with EU SV 181 None EU 373 Coal Silo Incl with EU SV 181 None EU 374 Coal Conv. Discharge SV 182 None EU 375 Coal Screen Incl with EU SV 182 None EU 376 Coal Reversing Belt Incl with EU SV 182 None EU 377 Day Bin Belt Feed Incl with EU SV 182 None EU 378 Day Bin Belt Discharge Incl with EU SV 182 None EU 379 Coal Pulverizer Incl with EU SV 182 De Minimis Modeling for PM10 EU 380 Coal Pulverizer Incl with EU SV 182 De Minimis Modeling for PM10

103 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 381 Coal Day Bin Incl with EU SV 182 De Minimis Modeling for PM10 EU 382 Coal Day Bin Incl with EU SV 182 De Minimis Modeling for PM10 3.E. Other Combustion Units EU 001 Utility Plant Heating Boiler # SV 001 BART Analysis for NOx De Minimis Modeling for PM10 and SO2 EU 002 Utility Plant Heating Boiler # SV 002 BART Analysis for NOx De Minimis Modeling for PM10 and SO2 EU 003 Utility Plant Heating Boiler # SV 003 BART Analysis for NOx De Minimis Modeling for PM10 and SO2 EU 004 Utility Plant Heating Boiler # SV 004 BART Analysis for NOx De Minimis Modeling for PM10 and SO2 EU 005 Utility Plant Heating Boiler # SV 005 BART Analysis for NOx De Minimis Modeling for PM10 and SO2 EU 006 Utility Plant Diesel Generator SV 006 None EU 008 Utility Plant Diesel Generator SV 008 None EU 009 Utility Plant Diesel Fire Pump SV 009 None EU 010 Mobile Eqp Shop Heating Boiler # SV 010 De Minimis Modeling for SO2 + NOx EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 Incl with EU SV 011 De Minimis Modeling for SO2 + NOx EU 012 Mobile Eqp Shop Diesel Generator SV 012 None EU 028 Coarse Crusher Zinc Furnace SV 019 De Minimis Modeling for SO2, NOx + PM10 EU 032 Coarse Crusher Zinc Furnace SV 020 De Minimis Modeling for SO2, NOx + PM10 EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 Incl with EU SV 020 De Minimis Modeling for SO2, NOx + PM10 EU 051 Crusher Area Diesel Generator SV 029 None EU 142 Fine Crusher Zinc Furnace SV 086 De Minimis Modeling for SO2, NOx + PM10 EU 143 Fine Crusher Zinc Furnace SV 086 De Minimis Modeling for SO2, NOx + PM10 EU 215 Concentrator Area Diesel Generator SV 098 None EU 383 Diesel Generator SV 183 None EU 384 Diesel Generator SV 184 None EU 385 Diesel Generator SV 185 None EU 386 Diesel Generator SV 186 None

104 Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis Emission Unit # Emission Unit Description NOx Max. 24-hr Actual Emissions (lb/day) SO2 Max. 24- hr Actual Emissions (lb/day) PM10 Max. 24- hr Actual Emissions (lb/day) MACT PM Emission Limit * (g/dscf) Stack Number Actions Required EU 387 Air Compressor SV 187 De Minimis Modeling for SO2, NOx + PM10 * The taconite MACT emission limits are based on EPA Method 5 and include the applicable averaging and grouping provisions, as presented in the regulation.

105 Table 3-2: De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data EU # EU Description SO 2 Maximum 24-hr Emission Rate (lbs/day) NO x Maximum 24-hr Emission Rate (lbs/day) PM 2.5 Maximum 24- hr Emission Rate (lbs/day) PM 10 Maximum 24-hr Emission Rate (lbs/day) SV # Stack Easting (utm) Stack Northing (utm) Height of Opening from Ground (ft) Base Elevation of Ground (ft) Stack length, width, or Diameter (ft) Flow Rate at exit (acfm) Exit Temp ( F) Basis for SO hour Actual Emissions Basis for NO x 24- hour Actual Emissions Basis for PM hour Actual Emissions Basis for PM hour Actual Emissions EU 379 Coal Pulverizer SV 182 NA NA n/a n/a n/a AP-42 Emission Factor EU 380 Coal Pulverizer Incl with EU 379 SV 182 NA NA Incl with EU 379 Incl with EU 380 n/a Incl with EU 382 EU 381 Coal Day Bin Incl with EU 379 SV 182 NA NA Incl with EU 379 Incl with EU 380 n/a Incl with EU 382 EU 382 Coal Day Bin Incl with EU 379 SV 182 NA NA Incl with EU 379 Incl with EU 380 n/a Incl with EU 382 EU 001 Utility Plant Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 002 Utility Plant Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 003 Utility Plant Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 004 Utility Plant Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 005 Utility Plant Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 010 Mobile Eqp Shop Heating Boiler # SV AP-42 Emission AP-42 Emission AP-42 Emission n/a Factor Factor Factor EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU Incl with EU010 SV Incl with EU010 Incl with EU010 n/a Incl with EU010 EU 028 Coarse Crusher Zinc Furnace SV EU 032 Coarse Crusher Zinc Furnace SV AP-42 Emission Factor AP-42 Emission Factor 19 gallons used in 19 gallons used in Jan of 2005 * AP-42 Jan of 2005 * AP-42 Emission Factor Emission Factor n/a n/a AP-42 Emission Factor 19 gallons used in Jan of 2005 * AP-42 Emission Factor EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU Incl with EU032 SV Incl with EU032 Incl with EU032 n/a Incl with EU032 EU 142 Fine Crusher Zinc Furnace SV EU 143 Fine Crusher Zinc Furnace SV Assume one full day Assume one full day of operation: 24 hrs of operation: 24 hrs * * operating rate * operating rate * AP- AP-42 Emission 42 Emission Factor Factor Assume one full day Assume one full day of operation: 24 hrs of operation: 24 hrs * * operating rate * operating rate * AP- AP-42 Emission 42 Emission Factor Factor n/a n/a Assume one full day of operation: 24 hrs * operating rate * AP-42 Emission Facto Assume one full day of operation: 24 hrs * operating rate * AP-42 Emission Facto EU 387 Air Compressor SV 187 NA NA Based on PTE Based on PTE n/a Based on PTE

106 Table 3-3 De Minimis Visibility Modeling Results Combined Class I Area with Greatest Impact Model Scenario 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 De Minimis

107 Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data EU # EU Description Baseline Conditions - Utility Plant Heating Boilers SO 2 Maximum 24-hr Emission Rate (lbs/day) NO x Maximum 24-hr Emission Rate (lbs/day) PM 2.5 Maximum 24-hr Emission Rate (lbs/day) PM 10 Maximum 24-hr Emission Rate (lbs/day) SV # Stack Easting (utm) Stack Northing (utm) Height of Opening from Ground (ft) Base Elevation of Ground (ft) Stack length, width, or Diameter (ft) EU 001 Utility Plant Heating Boiler # n/a 5.3 SV , EU 002 Utility Plant Heating Boiler # n/a 19.5 SV , EU 003 Utility Plant Heating Boiler # n/a 2.9 SV , EU 004 Utility Plant Heating Boiler # n/a 6.3 SV , EU 005 Utility Plant Heating Boiler # n/a 6.1 SV , Baseline Conditions - Indurating Furnaces - Natural Gas Burning in Kiln EU 223 Line n/a 6552 SV , EU 259 Line n/a 2568 SV , Flow Rate at exit (acfm) Exit Temp ( F) Basis for SO hour Actual Emissions AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor Stack Test May 2005 Stack Test July 2006 Basis for NO x 24- hour Actual Emissions AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor Stack Test June 1997 Stack Test April 2004 EU 280 Line n/a 2568 SV , Same as Line 4 Same as line 4 N/A EU 313 Line n/a 1968 SV , Same as Line 7 Same as line 7 N/A EU 332 Line n/a 1968 SV , Baseline Conditions - Indurating Furnaces - Solid Fuel Burning in Kiln EU 223 Line n/a 6552 SV , EU 259 Line n/a 2568 SV , Stack Test June 2002 Stack Test March 1994 Stack Test July 2005 Stack Test June 2002 Stack Test April 2004 Stack Test April 2004 EU 280 Line n/a 2568 SV , Same as line 4 Same as line 4 N/A EU 313 Line n/a 1968 SV , Same as line 7 Same as line 7 N/A EU 332 Line n/a 1968 SV , Stack Test March 1994 Stack Test May 2004 Basis for PM Basis for PM hour Actual hour Actual Emissions Emissions N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor AP-42 Emission Factor Stack Test May 2005 Stack Test July 2005 Stack Test May 2005 Stack Test April 2005 Stack Test April 2005 Stack Test May 2005 Stack Test July 2005 Stack Test May 2005 Stack Test April 2005 Stack Test April 2005

108 Table 4-2 Baseline Visibility Modeling Results Scenario Control Technology Table 4-2 Baseline Visibility Modeling Results Combined Modeling Scenario SO 2 NO x 0 Baseline Indurating Furnaces burning Natural Gas Baseline Baseline Indurating Furnaces burning Natural Gas Baseline 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 Indurating Furnaces burning Solid Fuels Indurating Furnaces burning Solid Fuels BWCA

109 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) Line 3 $27,948,027 $5,322,323 $20,201 Line 4 $39,347,773 $8,448,332 $23,597 Line 5 $39,347,773 $8,448,332 $23,597 Line 6 $36,370,821 $7,939,628 $18,216 Line 7 $37,793,453 $8,123,761 $18,638 Secondary Wet Scrubber Line 3 $19,626,314 $2,816,433 $14,253 Line 4 $26,664,036 $4,123,939 $15,358 Line 5 $26,664,036 $4,123,939 $15,358 Line 6 $25,704,464 $3,953,025 $12,093 Line 7 $25,704,464 $3,953,025 $12,093

110 Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates Scenario Control Technology SO 2 NO x Control Scenario SV # Emission Max 24-hour Max 24-hour Unit SO 2 NO x % Reduction lbs/day % Reduction lbs/day 2 SV 103 Line 3 Current Operations Current Operation 30% 2, ,128 SV 118 Line 4 w/ Line 3 Scrubber w/ line 6 Burners --- 3, ,520 SV 127 Line , ,520 SV 144 Line 6 Indurating Furnaces Burning Indurating Furances Burning --- 2,520 10% 23,609 SV 151 Line 7 Nat Gas Nat Gas --- 2, ,232 3 SV 103 Line 3 Current Operations Current Operation 30% 2, ,168 SV 118 Line 4 w/ Line 3 Scrubber w/ line 6 Burners --- 3, ,360 SV 127 Line , ,360 SV 144 Line 6 Indurating Furnaces Burning Indurating Furnaces Burning --- 4,032 10% 17,496 SV 151 Line 7 Solid Fuel Solid Fuel --- 4, ,440

111 Table 5-5 Post-BART SO 2 Modeling Scenarios - Visibility Modeling Results Scenario Control Technology Combined Scenario # SO 2 NO x 0 Baseline Baseline 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 Indurating Furnaces burning Natural Gas 1 Baseline Indurating Furnaces burning Solid Fuels 2 Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas 3 Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Indurating Furnaces burning Natural Gas Baseline Indurating Furnaces burning Solid Fuels Current Operation w/ line 6 Burners Indurating Furances Burning Nat Gas Current Operation w/ line 6 Burners Indurating Furnaces Burning Solid Fuel BWCA BWCA BWCA

112 Table 5-8 Indurating Furnace NOx Control Cost Summary Control Technology Installed Capital Cost (MM$) Operating Cost (MM$/yr) Annualized Pollution Control Cost ($/ton) Incremental Control Cost ($/ton) Selective Catalytic Reduction (SCR) Line 3 $69,222,423 $19,513,772 $18,135 n/a Line 4 $58,874,795 $28,169,433 $19,433 n/a Line 5 $58,874,795 $28,169,433 $19,347 n/a Line 6 $56,748,729 $26,419,264 $18,595 n/a Line 7 $56,748,729 $26,419,264 $17,129 n/a Low-NOx Burners + Ported Kilns Line 3 n/a n/a n/a n/a Line 4 $5,091,356 $480,588 $5,844 $5,076 Line 5 $6,474,892 $611,184 $5,974 $5,209 Line 6 n/a n/a n/a n/a Line 7 n/a n/a n/a n/a Low-NOx Burners Line 3 n/a n/a n/a n/a Line 4 $1,474,892 $139,219 $768 -$3,673 Line 5 $1,474,892 $139,219 $765 -$3,657 Line 6 n/a n/a n/a n/a Line 7 $1,200,000 $113,272 $588 n/a Ported Kilns Line 3 $3,616,464 $341,369 $5,076 n/a Line 4 $5,000,000 $471,965 $5,209 n/a Line 5 $5,000,000 $471,965 $5,186 n/a Line 6 n/a n/a n/a n/a Line 7 n/a n/a n/a n/a

113 Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates Scenario Control Technology SO 2 NO x Control Scenario SV # 4 Emission Unit SO 2 NO x % Reduction Max 24-hour lbs/day % Reduction Max 24-hour lbs/day SV 103 Line ,150 5% 18,172 5 SV 118 Line 4 Current Operations Ported Kilns --- 3,192 5% 28,044 w/ Line 3 Scrubber (lines 3, 4, 5) SV 127 Line ,192 5% 28,044 SV 144 Line 6 Indurating Furnaces Indurating Furances Ports already Burning Nat Gas Burning Nat Gas --- 2,520 installed 23,609 SV 151 Line ,520 Ports already installed 26,232 SV 103 Line ,150 No NOx improvement 12,168 on solid fuels SV 118 Line ,192 No NOx improvement 27,360 Current Operations Ported Kilns on solid fuels w/ Line 3 Scrubber (lines 3, 4, 5) No NOx SV 127 Line ,192 improvement 27,360 Indurating Furnaces Indurating Furances on solid fuels Burning Solid Fuel Burning Solid Fuel No NOx SV 144 Line ,032 improvement 17,496 on solid fuels SV 151 Line ,032 No NOx improvement on solid fuels 19,440

114 Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates Scenario Control Technology SO 2 NO x Control Scenario SV # Emission Unit SO 2 NO x % Reduction Max 24-hour lbs/day % Reduction Max 24-hour lbs/day 6 low-nox Not SV 103 Line ,150 19,128 Available Current Operations Low NOx Burners SV 118 Line ,192 10% 26,568 w/ Line 3 Scrubber (lines 4, 5, 7) SV 127 Line ,192 10% 26,568 low-nox Indurating Furnaces Indurating Furances SV 144 Line ,520 Already 23,609 Burning Nat Gas Burning Nat Gas Installed SV 151 Line ,520 10% 23,609 7 low-nox Not SV 103 Line ,150 12,168 Available Current Operations Low NOx Burners SV 118 Line ,192 10% 24,624 w/ Line 3 Scrubber (lines 4, 5, 7) SV 127 Line ,192 10% 24,624 low-nox Indurating Furnaces Indurating Furances SV 144 Line ,032 Already 17,496 Burning Solid Fuel Burning Solid Fuel Installed SV 151 Line ,032 10% 17,496 8 SV 103 Line 3 Ported Kilns Current Operations --- 2,150 5% 18,172 (lines 3, 4, 5) SV 118 Line 4 w/ Line 3 Scrubber --- 3,192 15% 25,092 + SV 127 Line ,192 15% 25,092 Low NOx Burners SV 144 Line 6 Indurating Furnaces (lines 4, 5, 7) --- 2,520 0% 23,609 SV 151 Line 7 Burning Nat Gas --- 2,520 10% 23,609 9 SV 103 Line 3 Ported Kilns Current Operations --- 2,150 0% 12,168 (lines 3, 4, 5) SV 118 Line 4 w/ Line 3 Scrubber --- 3,192 10% 24,624 + SV 127 Line ,192 10% 24,624 Low NOx Burners SV 144 Line 6 Indurating Furnaces (lines 4, 5, 7) --- 4,032 0% 17,496 SV 151 Line 7 Burning Solid Fuel --- 4,032 10% 17,496

115 Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results Combined Scenario # Operating Conditions Operating Conditions 0 Baseline Indurating Furnaces burning Natural Gas Baseline Baseline Indurating Furnaces burning Natural Gas Baseline 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 Indurating Furnaces burning Solid Fuels Indurating Furnaces burning Solid Fuels BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operation w/ line 6 Burners Indurating Furances Burning Nat Gas BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Current Operation w/ line 6 Burners Indurating Furnaces Burning Solid Fuel BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Ported Kilns (lines 3, 4, 5) Indurating Furances Burning Nat Gas BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Ported Kilns (lines 3, 4, 5) Indurating Furances Burning Solid Fuel BWCA

116 Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results Combined Scenario # Operating Conditions Operating Conditions Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Nat Gas Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Solid Fuel Ported Kilns (lines 3, 4, 5) + Low NOx Burners (lines 4, 5, 7) Burning Nat Gas Ported Kilns (lines 3, 4, 5) + Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Solid Fuel 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 BWCA BWCA BWCA

117 Table 5-14 Boiler NOx Control Cost Summary Control Technology Installed Capital Cost (MM$) Operating Cost (MM$/yr) Annualized Pollution Control Cost ($/ton) Low Temperature Oxidation (LoTOx) Utility Plant Heater Boiler #1 $1,681,680 $304,052 $23,668 Utility Plant Heater Boiler #2 $1,681,680 $304,052 $24,489 Utility Plant Heater Boiler #4 $1,914,641 $343,518 $25,720 Utility Plant Heater Boiler #5 $1,914,641 $343,518 $27,713 Selective Catalytic Reduction (SCR) Utility Plant Heater Boiler #1 $4,488,567 $592,165 $50,632 Utility Plant Heater Boiler #2 $4,488,567 $592,165 $52,345 Utility Plant Heater Boiler #4 $5,234,392 $688,384 $56,028 Utility Plant Heater Boiler #5 $5,234,392 $688,384 $60,211 Low NOX Burner / Flue Gas Recirculation Utility Plant Heater Boiler #1 $1,384,220 $166,560 $15,558 Utility Plant Heater Boiler #2 $1,384,220 $166,560 $16,098 Utility Plant Heater Boiler #4 $1,745,018 $209,678 $18,839 Utility Plant Heater Boiler #5 $1,745,018 $209,678 $20,299 Regenerative Selective Catalytic Reduction (R-SCR) Utility Plant Heater Boiler #1 $1,690,961 $238,636 $22,879 Utility Plant Heater Boiler #2 $1,690,961 $238,636 $23,638 Utility Plant Heater Boiler #4 $2,156,692 $316,281 $28,633 Utility Plant Heater Boiler #5 $2,156,692 $316,281 $30,710 Low NOX Burner / Overfire Air (OFA) Utility Plant Heater Boiler #1 $1,131,149 $136,590 $14,282 Utility Plant Heater Boiler #2 $1,131,149 $136,590 $14,778 Utility Plant Heater Boiler #4 $1,425,985 $171,954 $17,294 Utility Plant Heater Boiler #5 $1,425,985 $171,954 $18,634 Low NOX Burner Utility Plant Heater Boiler #1 $344,269 $47,480 $6,653 Utility Plant Heater Boiler #2 $344,269 $47,480 $6,883 Utility Plant Heater Boiler #4 $434,003 $59,540 $8,024 Utility Plant Heater Boiler #5 $434,003 $59,540 $8,646 Selective Non-Catalytic Reduction (SNCR) Utility Plant Heater Boiler #1 $1,084,406 $300,018 $42,037 Utility Plant Heater Boiler #2 $1,084,406 $300,018 $43,495 Utility Plant Heater Boiler #4 $1,277,232 $354,613 $47,792 Utility Plant Heater Boiler #5 $1,277,232 $354,613 $51,494

118 Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates Scenario Control Technology NO x Control Scenario SV # 0 (baseline) 1 Emission Unit NO x % Reduction Max 24-hour lbs/day SV 001 EU 001 Baseline SV 002 EU SV 004 EU 004 Indurating Furnaces burning Natural SV 005 EU 005 Gas SV 001 EU % 97 SV 002 EU 002 Utility Plant Heating Boilers 50% 360 SV 004 EU 004 Low-NOx Burners 50% 115 SV 005 EU % 113

119 Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results Scenario Control Technology Combined Scenario # SO2 NO x 0 10 Baseline Indurating Furnaces burning Natural Gas Baseline Indurating Furnaces burning Natural Gas Baseline Indurating Furnaces burning Natural Gas Utility Plant Heating Boilers Low-NOx Burners 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 BWCA

120 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results Combined Scenario # Operating Conditions Operating Conditions 0 Baseline Indurating Furnaces burning Natural Gas Baseline Baseline Indurating Furnaces burning Natural Gas Baseline 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 Indurating Furnaces burning Solid Fuels Indurating Furnaces burning Solid Fuels BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operation w/ line 6 Burners Indurating Furances Burning Nat Gas BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Current Operation w/ line 6 Burners Indurating Furnaces Burning Solid Fuel BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Ported Kilns (lines 3, 4, 5) Indurating Furances Burning Nat Gas BWCA Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Ported Kilns (lines 3, 4, 5) Indurating Furances Burning Solid Fuel BWCA

121 Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results Combined Scenario # Operating Conditions Operating Conditions Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Nat Gas Current Operations w/ Line 3 Scrubber Indurating Furnaces Burning Solid Fuel Baseline Indurating Furnaces burning Natural Gas Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Nat Gas Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Solid Fuel Ported Kilns (lines 3, 4, 5) + Low NOx Burners (lines 4, 5, 7) Burning Nat Gas Ported Kilns (lines 3, 4, 5) + Low NOx Burners (lines 4, 5, 7) Indurating Furances Burning Solid Fuel Utility Plant Heating Boilers Low-NOx Burners 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 BWCA BWCA BWCA BWCA

122 9/6/2006 BART Report - Attachment A: Emission Control Cost Analysis Table A.1: Furnaces Cost Summary NO x Control Cost Summary Control Technology Control Eff % Controlled Emissions T/y Selective Catalytic Reduction with Reheat (SCR) Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton Line 3 80% $69,222,423 $19,513,772 $18,135 n/a Line 4 80% $58,874,795 $28,169,433 $19,433 n/a Line 5 80% $58,874,795 $28,169,433 $19,347 n/a Line 6 80% $56,748,729 $26,419,264 $18,595 n/a Line 7 80% $56,748,729 $26,419,264 $17,129 n/a Low NO X Burners + Ported Kilns Line 3 n/a n/a n/a n/a n/a n/a n/a Line 4 15% $5,091,356 $480,588 $5,844 $5,076 Line 5 15% $6,474,892 $611,184 $5,974 $5,209 Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 n/a n/a n/a n/a n/a n/a n/a Low NO X Burners Line 3 n/a n/a n/a n/a n/a n/a n/a Line 4 10% $1,474,892 $139,219 $768 -$3,673 Line 5 10% $1,474,892 $139,219 $765 -$3,657 Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 10% $1,200,000 $113,272 $588 n/a Ported Kilns Line 3 5% $3,616,464 $341,369 $5,076 n/a Line 4 5% $5,000,000 $471,965 $5,209 n/a Line 5 5% $5,000,000 $471,965 $5,186 n/a Line 6 n/a n/a n/a n/a n/a n/a n/a Line 7 n/a n/a n/a n/a n/a n/a n/a SO 2 Control Cost Summary Control Technology Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Incremental Control Cost $/ton Wet Walled Electrostatic Precipitator (WWESP) (after existing scrubber) Line 3 80% $27,948,027 $5,322,323 $20,201 n/a Line 4 80% $39,347,773 $8,448,332 $23,597 n/a Line 5 80% $39,347,773 $8,448,332 $23,597 n/a Line 6 80% $36,370,821 $7,939,628 $18,216 n/a Line 7 80% $37,793,453 $8,123,761 $18,638 n/a Secondary Wet Scrubber (after existing scrubber) Line 3 60% $19,626,314 $2,816,433 $14,253 n/a Line 4 60% $26,664,036 $4,123,939 $15,358 n/a Line 5 60% $26,664,036 $4,123,939 $15,358 n/a Line 6 60% $25,704,464 $3,953,025 $12,093 n/a Line 7 60% $25,704,464 $3,953,025 $12,093 n/a Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Cost Summary 9/7/2006 Page 1 of 75

123 BART Report - Attachment A: Emission Control Cost Analysis Table A.2 - Summary of Utility, Chemical and Supply Costs Operating Unit: Line 3 waste gas Study Year 2006 Emission Unit Number EU 223 Stack/Vent Number SV 103 Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Operating Unit: Line 6 waste gas Emission Unit Number EU 313 Stack/Vent Number SV 144 Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Reference Item Unit Cost Units Cost Year Data Source Notes Operating Labor 61 $/hr Per Chrissy Bartovich Maintenance Labor 61 $/hr Per Chrissy Bartovich Expected annual average industrial price of electricity in the West North Central Division Electricity $/kwh 2006 for DOE Natural Gas $/mscf Energy Information Administration. Average US Industrial Natural Gas Prices. July '05 to 2005 June '06. Water 0.08 $/mgal 2006 Per Chrissy Bartovich Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich Compressed Air 0.32 $/mscf 0.25 EPA Air Pollution Control Cost Manual 6th 1998 Ed 2002, Section 6 Chapter 1 Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation Wastewater Disposal Neutralization 1.69 $/mgal 1.50 EPA Air Pollution Control Cost Manual 6th 2002 Ed 2002, Section 2 Chapter Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch 3 lists $ $2.15/1,000 gal Chemicals & Supplies Lime $/ton Estimate from Cutler-Magney Company Oxygen $/ton 2006 BOC estimate. Ammonia (29% aqua.) 0.12 $/lb EPA Air Pollution Control Cost Manual 6th 2000 Ed 2002, Section 4 Chapter 2, page 2-50 Annual costs for a retrofit SCR system example problem. '00 costs adjusted for 3% inflation. Caustic $/ton Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflation SCR Catalyst $/ft 3 Cormetech, Inc. Other Sales Tax 6.5% % Interest Rate 7.00% % EPA Air Pollution Control Cost Manual Introduction, Chapter 2, section Social (discount) rate used as a default. Operating Information Annual Op. Hrs 7946 Hours Engineering Estimate Utilization Rate 93% Equipment Life 20 yrs Engineering Estimate Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Utility Chem$ Data 9/7/2006 Page 2 of 75

124 Standardized Flow Rate SV ,515 32º F Calculated. SV ,174 32º F Calculated. SV ,174 32º F Calculated. SV ,805 32º F Calculated. SV ,805 32º F Calculated. Temperature SV Deg F BART spreadsheet. SV Deg F BART spreadsheet. SV Deg F BART spreadsheet. SV Deg F BART spreadsheet. SV Deg F BART spreadsheet. Moisture Content SV % Assumed value. SV % Assumed value. SV % Assumed value. SV % Assumed value. SV % Assumed value. Actual Flow Rate SV ,000 acfm BART spreadsheet. SV ,000 acfm BART spreadsheet. SV ,000 acfm BART spreadsheet. SV ,000 acfm Same as line 7 SV ,000 acfm BART spreadsheet. Standardized Flow Rate SV ,163 68º F Calculated. SV ,870 68º F Calculated. SV ,870 68º F Calculated. SV ,766 68º F Calculated. SV ,766 68º F Calculated. Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Utility Chem$ Data 9/7/2006 Page 3 of 75

125 Dry Std Flow Rate SV ,906 68º F Calculated. SV ,198 68º F Calculated. SV ,198 68º F Calculated. SV ,306 68º F Calculated. SV ,306 68º F Calculated. 24-hour Max Emis Projected future actual lb/hr ton/year Pollutant Lb/Hr emissions (tpy) ppmv ppmv Max 24 hour emissions source Projected future actual emissions source Nitrous Oxides (NOx) SV , Based on max stack test plus 10% Based on 2005 AEI plus 10%. SV , Based on max stack test plus 10% Based on 2005 AEI plus 10%. SV , Based on max stack test plus 10% Based on 2005 AEI plus 10%. SV , Based on max stack test plus 10% Based on 2005 AEI plus 10%. SV , Based on max stack test plus 10% Based on 2005 AEI plus 10%. Sulfur Dioxides (SO2) SV Based on max stack test plus 10%, minus 30% to account for new scrubber. Based on AEI avg 2004/2005 plus 10%., minus 30% to account for new scrubber. SV Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%. SV Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%. SV Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%. SV Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%. Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Utility Chem$ Data 9/7/2006 Page 4 of 75

126 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 3 waste gas Emission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 130 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 68º F Dry Std Flow Rate 257,906 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 28,387,757 Purchased Equipment Total SCR Only 30,232,961 SCR + Reheat 30,950,318 Total Capital Investment (TCI) = DC + IC SCR + Reheat 69,222,423 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 11,235,240 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 8,288,440 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 19,513,772 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) , % , ,135 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Control Efficiency = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 SCR Line3 SCR 5 of 75

127 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 28,387,757 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,845,204 Freight 5% of control device cost (A) NA Purchased Equipment Total 30,232,961 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 9% Replacement Power, two weeks 2,643,899 Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899 Project Contingeny (C) 15% of (A + B) 4,931,529 Total Plant Cost (D) A + B + C 37,808,389 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 756,168 Inventory Capital Reagent Vol * $/gal 102,618 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 38,667,175 Retrofit Factor (14) 60% of TCI 23,200,305 Sitework and foundations 1,400,000 Structural steel 4,800,000 Total Capital Investment Retrofit Installed 68,067,479 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 580,008 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 652 kw-hr, 7946 hr/yr, 93% utilization 245,543 SCR Catalyst Catalyst Replacement 193,359 Ammonia (29% aqua.) 0.12 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization 2,694,872 Total Annual Direct Operating Costs 3,853,135 Indirect Operating Costs Overhead 60% of total labor and material costs 94,284 Administration (2% total capital costs) 2% of total capital costs (TCI) 773,343 Property tax (1% total capital costs) 1% of total capital costs (TCI) 386,672 Insurance (1% total capital costs) 1% of total capital costs (TCI) 386,672 Capital Recovery for a 20- year equipment life and a 7% interest rate 6,425,089 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,066,059 Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,919,195 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 SCR Line3 SCR 6 of 75

128 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. # ft 3 Cormetech, Inc. FCW Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 288,163 scfm Amount Required 4,409 ft 3 Catalyst Cost 621,630 Y catalyst life factor 3 Years Annualized Cost 193,359 Vol # ft 3 Equivalent Duty 1,547 Plant Cap kw A 158,727 Est power platn eff 35% Unc Nox lb/mmbtu B 0.62 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr Nox Red. Eff. C 80% E=D*A* Equivalent power plant kw 158,727 Capital Cost $/kw D $ $23,809, Total SCR Equipment Uncontrolled Nox t/y 3,840.9 Fixed O&M E $157, Annual Operating Hrs 7,946 Variable O&M F $394, Uncontrolled Nox lb/mmbtu Ann Cap Factor G 0.82 Heat Input mmbtu/hr H 1,547 Electrical Use Equivalent Duty 1,547 MMBtu/hr kw NOx Cont Eff 80% Power NOx in 0.62 lb/mmbtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 877 lb/hr Neat gal/hr 29% solution Volume 14 day inventory 135,729 gal $102,618 Inventory Cost 3024 lb/hr Design Basis Max Emis Control Eff (%) lb/mmbtu 80% Nitrous Oxides (NOx) Actual Method 19 Factor Adjusted Duty 77,372 dscf/mmbtu 10,000 dscf/mmbtu 1,547 MMBtu/hr Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 580,008 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 4,814, ,543 $/kwh, 652 kw-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 193,359 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 3024 lb/hr 22,345,675 2,694,872 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 SCR Line3 SCR 7 of 75

129 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NO x Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Line 3 waste gas Emission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 130 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 68º F Dry Std Flow Rate 257,906 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 590,417 Purchased Equipment Total (B) 22% of control device cost (A) 717,356 Installation - Standard Costs 30% of purchased equip cost (B) 215,207 Installation - Site Specific Costs NA Installation Total 215,207 Total Direct Capital Cost, DC 932,563 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380 Total Capital Investment (TCI) = DC + IC 1,154,944 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 7,382,105 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 8 of 75

130 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 590,417 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 59,042 MN Sales Taxes 6.5% of control device cost (A) 38,377 Freight 5% of control device cost (A) 29,521 Purchased Equipment Total (B) 22% 717,356 Installation Foundations & supports 8% of purchased equip cost (B) 57,389 Handling & erection 14% of purchased equip cost (B) 100,430 Electrical 4% of purchased equip cost (B) 28,694 Piping 2% of purchased equip cost (B) 14,347 Insulation 1% of purchased equip cost (B) 7,174 Painting 1% of purchased equip cost (B) 7,174 Installation Subtotal Standard Expenses 30% 215,207 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 215,207 Total Direct Capital Cost, DC 932,563 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 71,736 Construction & field expenses 5% of purchased equip cost (B) 35,868 Contractor fees 10% of purchased equip cost (B) 71,736 Start-up 2% of purchased equip cost (B) 14,347 Performance test 1% of purchased equip cost (B) 7,174 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 21,521 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380 Total Capital Investment (TCI) = DC + IC 1,154,944 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,154,944 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,193 kw-hr, 7946 hr/yr, 93% utilization 449,620 Natural Gas 9.26 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization 6,837,058 Total Annual Direct Operating Costs 7,382,105 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 23,099 Property tax (1% total capital costs) 1% of total capital costs (TCI) 11,549 Insurance (1% total capital costs) 1% of total capital costs (TCI) 11,549 Capital Recovery for a 20- year equipment life and a 7% interest rate 109,019 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 9 of 75

131 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 3 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 322, ,193.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 322, ,444.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 8,816, ,620 $/kwh, 1,193 kw-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 1,666 scfm 738,543 6,837,058 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 10 of 75

132 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 130 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 564 Deg F - Temperature of waste gas out of heat recovery T fo 316 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 288,163 scfm - Flow of waste gas Q af 1,666 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 289,828 scfm Flue Gas Cost in 1989 $'s $495,188 Current Cost Using CHE Plant Cost Index $590,417 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 Reheat Line3 Reheat 11 of 75

133 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 23,050,831 Purchased Equipment Total SCR Only 24,549,135 SCR + Reheat 25,409,745 Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % , ,433 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Control Efficiency = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 SCR Line4 SCR 12 of 75

134 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,498,304 Freight 5% of control device cost (A) NA Purchased Equipment Total 24,549,135 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899 Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899 Project Contingeny (C) 15% of (A + B) 4,078,955 Total Plant Cost (D) A + B + C 31,271,989 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 625,440 Inventory Capital Reagent Vol * $/gal 158,329 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758 Retrofit Factor (14) 60% of TCI 19,233,455 Sitework and foundations 1,400,000 Structural steel 4,800,000 Total Capital Investment Retrofit Installed 57,489,212 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 480,836 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,409 kw-hr, 7946 hr/yr, 93% utilization 531,079 SCR Catalyst Catalyst Replacement 400,504 Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919 Total Annual Direct Operating Costs 5,709,691 Indirect Operating Costs Overhead 60% of total labor and material costs 91,281 Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115 Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558 Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558 Capital Recovery for a 20- year equipment life and a 7% interest rate 5,426,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087 Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 SCR Line4 SCR 13 of 75

135 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. # ft 3 Cormetech, Inc. FCW Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 596,870 scfm Amount Required 9,132 ft 3 Catalyst Cost 1,287,579 Y catalyst life factor 3 Years Annualized Cost 400,504 Vol # ft 3 Equivalent Duty 3,484 Plant Cap kw A 357,359 Est power platn eff 35% Unc Nox lb/mmbtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr Nox Red. Eff. C 80% E=D*A* Equivalent power plant kw 357,359 Capital Cost $/kw D $64.50 $23,050, Total SCR Equipment Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152, Annual Operating Hrs 8000 Variable O&M F $624, Uncontrolled Nox lb/mmbtu Ann Cap Factor G 0.82 Heat Input mmbtu/hr H 6,000 Electrical Use Equivalent Duty 3,484 MMBtu/hr kw NOx Cont Eff 80% Power 1,409.2 NOx in 0.43 lb/mmbtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 1353 lb/hr Neat gal/hr 29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost 4666 lb/hr Design Basis Max Emis Control Eff (%) lb/mmbtu 80% Nitrous Oxides (NOx) Actual Method 19 Factor Adjusted Duty 106,840 dscf/mmbtu 9,200 dscf/mmbtu 3,484 MMBtu/hr Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 10,413, ,079 $/kwh, 1,409 kw-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 SCR Line4 SCR 14 of 75

136 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NO x Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 115 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 708,321 Purchased Equipment Total (B) 22% of control device cost (A) 860,610 Installation - Standard Costs 30% of purchased equip cost (B) 258,183 Installation - Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 Reheat Line4 Reheat 15 of 75

137 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 708,321 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 70,832 MN Sales Taxes 6.5% of control device cost (A) 46,041 Freight 5% of control device cost (A) 35,416 Purchased Equipment Total (B) 22% 860,610 Installation Foundations & supports 8% of purchased equip cost (B) 68,849 Handling & erection 14% of purchased equip cost (B) 120,485 Electrical 4% of purchased equip cost (B) 34,424 Piping 2% of purchased equip cost (B) 17,212 Insulation 1% of purchased equip cost (B) 8,606 Painting 1% of purchased equip cost (B) 8,606 Installation Subtotal Standard Expenses 30% 258,183 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 86,061 Construction & field expenses 5% of purchased equip cost (B) 43,031 Contractor fees 10% of purchased equip cost (B) 86,061 Start-up 2% of purchased equip cost (B) 17,212 Performance test 1% of purchased equip cost (B) 8,606 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,818 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,408 kw-hr, 7946 hr/yr, 93% utilization 907,618 Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142 Total Annual Direct Operating Costs 15,416,187 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856 Capital Recovery for a 20- year equipment life and a 7% interest rate 130,789 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 Reheat Line4 Reheat 16 of 75

138 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 3 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 650, ,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 650, ,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 17,796, ,618 $/kwh, 2,408 kw-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 Reheat Line4 Reheat 17 of 75

139 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 115 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 560 Deg F - Temperature of waste gas out of heat recovery T fo 306 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 596,870 scfm - Flow of waste gas Q af 3,511 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076 Current Cost Using CHE Plant Cost Index $708,321 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 Reheat Line4 Reheat 18 of 75

140 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 23,050,831 Purchased Equipment Total SCR Only 24,549,135 SCR + Reheat 25,409,745 Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % , ,347 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Control Efficiency = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 SCR Line5 SCR 19 of 75

141 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,498,304 Freight 5% of control device cost (A) NA Purchased Equipment Total 24,549,135 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899 Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899 Project Contingeny (C) 15% of (A + B) 4,078,955 Total Plant Cost (D) A + B + C 31,271,989 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 625,440 Inventory Capital Reagent Vol * $/gal 158,329 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758 Retrofit Factor (14) 60% of TCI 19,233,455 Sitework and foundations 1,400,000 Structural steel 4,800,000 Total Capital Investment Retrofit Installed 57,489,212 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 480,836 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,409 kw-hr, 7946 hr/yr, 93% utilization 531,079 SCR Catalyst Catalyst Replacement 400,504 Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919 Total Annual Direct Operating Costs 5,709,691 Indirect Operating Costs Overhead 60% of total labor and material costs 91,281 Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115 Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558 Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558 Capital Recovery for a 20- year equipment life and a 7% interest rate 5,426,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087 Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 SCR Line5 SCR 20 of 75

142 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. # ft 3 Cormetech, Inc. FCW Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 596,870 scfm Amount Required 9,132 ft 3 Catalyst Cost 1,287,579 Y catalyst life factor 3 Years Annualized Cost 400,504 Vol # ft 3 Equivalent Duty 3,484 Plant Cap kw A 357,359 Est power platn eff 35% Unc Nox lb/mmbtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr Nox Red. Eff. C 80% E=D*A* Equivalent power plant kw 357,359 Capital Cost $/kw D $64.50 $23,050, Total SCR Equipment Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152, Annual Operating Hrs 8000 Variable O&M F $624, Uncontrolled Nox lb/mmbtu Ann Cap Factor G 0.82 Heat Input mmbtu/hr H 6,000 SCR Capital Cost Electrical Use Duty 3,484 MMBtu/hr kw NOx Cont Eff 80% Power 1,409.2 NOx in 0.43 lb/mmbtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 1353 lb/hr Neat gal/hr 29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost 4666 lb/hr Design Basis Max Emis Control Eff (%) lb/mmbtu 80% Nitrous Oxides (NOx) Actual Method 19 Factor Adjusted Duty 106,840 dscf/mmbtu 9,200 dscf/mmbtu 3,484 MMBtu/hr Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 10,413, ,079 $/kwh, 1,409 kw-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 SCR Line5 SCR 21 of 75

143 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NO x Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 115 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 708,321 Purchased Equipment Total (B) 22% of control device cost (A) 860,610 Installation - Standard Costs 30% of purchased equip cost (B) 258,183 Installation - Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 Reheat Line5 Reheat 22 of 75

144 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 708,321 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 70,832 MN Sales Taxes 6.5% of control device cost (A) 46,041 Freight 5% of control device cost (A) 35,416 Purchased Equipment Total (B) 22% 860,610 Installation Foundations & supports 8% of purchased equip cost (B) 68,849 Handling & erection 14% of purchased equip cost (B) 120,485 Electrical 4% of purchased equip cost (B) 34,424 Piping 2% of purchased equip cost (B) 17,212 Insulation 1% of purchased equip cost (B) 8,606 Painting 1% of purchased equip cost (B) 8,606 Installation Subtotal Standard Expenses 30% 258,183 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 258,183 Total Direct Capital Cost, DC 1,118,793 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 86,061 Construction & field expenses 5% of purchased equip cost (B) 43,031 Contractor fees 10% of purchased equip cost (B) 86,061 Start-up 2% of purchased equip cost (B) 17,212 Performance test 1% of purchased equip cost (B) 8,606 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,818 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789 Total Capital Investment (TCI) = DC + IC 1,385,582 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,408 kw-hr, 7946 hr/yr, 93% utilization 907,618 Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142 Total Annual Direct Operating Costs 15,416,187 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856 Capital Recovery for a 20- year equipment life and a 7% interest rate 130,789 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468 Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 Reheat Line5 Reheat 23 of 75

145 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 3 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 650, ,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 650, ,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 17,796, ,618 $/kwh, 2,408 kw-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 Reheat Line5 Reheat 24 of 75

146 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 115 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 560 Deg F - Temperature of waste gas out of heat recovery T fo 306 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 596,870 scfm - Flow of waste gas Q af 3,511 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076 Current Cost Using CHE Plant Cost Index $708,321 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 Reheat Line5 Reheat 25 of 75

147 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 6 waste gas Emission Unit Number EU 313 Stack/Vent Number SV 144 Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 22,013,215 Purchased Equipment Total SCR Only 23,444,074 SCR + Reheat 24,289,858 Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % , ,595 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Control Efficiency = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 SCR Line6 SCR 26 of 75

148 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,430,859 Freight 5% of control device cost (A) NA Purchased Equipment Total 23,444,074 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899 Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899 Project Contingeny (C) 15% of (A + B) 3,913,196 Total Plant Cost (D) A + B + C 30,001,168 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 600,023 Inventory Capital Reagent Vol * $/gal 140,694 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886 Retrofit Factor (14) 60% of TCI 18,445,131 Sitework and foundations 1,400,000 Structural steel 4,800,000 Total Capital Investment Retrofit Installed 55,387,017 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 461,128 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,309 kw-hr, 7946 hr/yr, 93% utilization 493,304 SCR Catalyst Catalyst Replacement 373,594 Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801 Total Annual Direct Operating Costs 5,162,181 Indirect Operating Costs Overhead 60% of total labor and material costs 87,172 Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838 Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419 Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419 Capital Recovery for a 20- year equipment life and a 7% interest rate 5,228,143 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990 Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 SCR Line6 SCR 27 of 75

149 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. # ft 3 Cormetech, Inc. FCW Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 556,766 scfm Amount Required 8,518 ft 3 Catalyst Cost 1,201,067 Y catalyst life factor 3 Years Annualized Cost 373,594 Vol # ft 3 Equivalent Duty 3,250 Plant Cap kw A 333,349 Est power platn eff 35% Unc Nox lb/mmbtu B 0.41 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr Nox Red. Eff. C 80% E=D*A* Equivalent power plant kw 333,349 Capital Cost $/kw D $66.04 $22,013, Total SCR Equipment Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145, Annual Operating Hrs 8000 Variable O&M F $586, Uncontrolled Nox lb/mmbtu Ann Cap Factor G 0.82 Heat Input mmbtu/hr H 6,000 SCR Capital Cost Electrical Use Duty 3,250 MMBtu/hr kw NOx Cont Eff 80% Power 1,308.9 NOx in 0.41 lb/mmbtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 1202 lb/hr Neat gal/hr 29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost 4146 lb/hr Design Basis Max Emis Control Eff (%) lb/mmbtu 80% Nitrous Oxides (NOx) Actual Method 19 Factor Adjusted Duty 99,661 dscf/mmbtu 9,200 dscf/mmbtu 3,250 MMBtu/hr Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,672, ,304 $/kwh, 1,309 kw-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 SCR Line6 SCR 28 of 75

150 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NO x Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Line 6 waste gas Emission Unit Number EU 313 Stack/Vent Number SV 144 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 109 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 696,118 Purchased Equipment Total (B) 22% of control device cost (A) 845,784 Installation - Standard Costs 30% of purchased equip cost (B) 253,735 Installation - Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 Reheat Line6 Reheat 29 of 75

151 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 696,118 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 69,612 MN Sales Taxes 6.5% of control device cost (A) 45,248 Freight 5% of control device cost (A) 34,806 Purchased Equipment Total (B) 22% 845,784 Installation Foundations & supports 8% of purchased equip cost (B) 67,663 Handling & erection 14% of purchased equip cost (B) 118,410 Electrical 4% of purchased equip cost (B) 33,831 Piping 2% of purchased equip cost (B) 16,916 Insulation 1% of purchased equip cost (B) 8,458 Painting 1% of purchased equip cost (B) 8,458 Installation Subtotal Standard Expenses 30% 253,735 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 84,578 Construction & field expenses 5% of purchased equip cost (B) 42,289 Contractor fees 10% of purchased equip cost (B) 84,578 Start-up 2% of purchased equip cost (B) 16,916 Performance test 1% of purchased equip cost (B) 8,458 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,374 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,223 kw-hr, 7946 hr/yr, 93% utilization 837,802 Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605 Total Annual Direct Operating Costs 14,471,833 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617 Capital Recovery for a 20- year equipment life and a 7% interest rate 128,536 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 Reheat Line6 Reheat 30 of 75

152 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 3 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 600, ,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 600, ,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 16,427, ,802 $/kwh, 2,223 kw-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 Reheat Line6 Reheat 31 of 75

153 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 109 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 558 Deg F - Temperature of waste gas out of heat recovery T fo 301 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 556,766 scfm - Flow of waste gas Q af 3,298 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841 Current Cost Using CHE Plant Cost Index $696,118 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 Reheat Line6 Reheat 32 of 75

154 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs EPRI Correlation Purchased Equipment 22,013,215 Purchased Equipment Total SCR Only 23,444,074 SCR + Reheat 24,289,858 Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % , ,129 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 For Calculation purposes, duty reflects increased flow rate, not actual duty. 3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Control Efficiency = 80% reduction 12 Site specific electricity costs 13 Catalyst replacement every 3 years. 14 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 SCR Line7 SCR 33 of 75

155 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) 1,430,859 Freight 5% of control device cost (A) NA Purchased Equipment Total 23,444,074 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 11% Replacement Power, two weeks 2,643,899 Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899 Project Contingeny (C) 15% of (A + B) 3,913,196 Total Plant Cost (D) A + B + C 30,001,168 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 600,023 Inventory Capital Reagent Vol * $/gal 140,694 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886 Retrofit Factor (14) 60% of TCI 18,445,131 Sitework and foundations 1,400,000 Structural steel 4,800,000 Total Capital Investment Retrofit Installed 55,387,017 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Total 1.50 % of Total Capital Investment 461,128 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,309 kw-hr, 7946 hr/yr, 93% utilization 493,304 SCR Catalyst Catalyst Replacement 373,594 Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801 Total Annual Direct Operating Costs 5,162,181 Indirect Operating Costs Overhead 60% of total labor and material costs 87,172 Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838 Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419 Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419 Capital Recovery for a 20- year equipment life and a 7% interest rate 5,228,143 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990 Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 SCR Line7 SCR 34 of 75

156 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Estimate amount of catalyst required Equipment Life 24,000 hours Vol. # ft 3 Cormetech, Inc. FCW Flow #1 177,000 scfm Cormetech, Inc. Rep part cost per unit $141 Flow #2 556,766 scfm Amount Required 8,518 ft 3 Catalyst Cost 1,201,067 Y catalyst life factor 3 Years Annualized Cost 373,594 Vol # ft 3 Equivalent Duty 3,250 Plant Cap kw A 333,349 Est power platn eff 35% Unc Nox lb/mmbtu B 0.41 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35 Watt per Btu/hr Nox Red. Eff. C 80% E=D*A* Equivalent power plant kw 333,349 Capital Cost $/kw D $66.04 $22,013, Total SCR Equipment Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145, Annual Operating Hrs 8000 Variable O&M F $586, Uncontrolled Nox lb/mmbtu Ann Cap Factor G 0.82 Heat Input mmbtu/hr H 6,000 SCR Capital Cost Electrical Use Duty 3,250 MMBtu/hr kw NOx Cont Eff 80% Power 1,308.9 NOx in 0.41 lb/mmbtu n catalyst layers 4 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 1202 lb/hr Neat gal/hr 29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost 4146 lb/hr Design Basis Max Emis Control Eff (%) lb/mmbtu 80% Nitrous Oxides (NOx) Actual Method 19 Factor Adjusted Duty 99,661 dscf/mmbtu 9,200 dscf/mmbtu 3,250 MMBtu/hr Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,672, ,304 $/kwh, 1,309 kw-hr, 7946 hr/yr, 93% utilization SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 SCR Line7 SCR 35 of 75

157 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NO x Control - Selective Catalytic Reduction with Reheat Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Chemical Engineering Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 32º F Chemical Plant Cost Index Expected Utilization Rate 93% Temperature 109 Deg F 1998/ Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 696,118 Purchased Equipment Total (B) 22% of control device cost (A) 845,784 Installation - Standard Costs 30% of purchased equip cost (B) 253,735 Installation - Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 36 of 75

158 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 696,118 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 69,612 MN Sales Taxes 6.5% of control device cost (A) 45,248 Freight 5% of control device cost (A) 34,806 Purchased Equipment Total (B) 22% 845,784 Installation Foundations & supports 8% of purchased equip cost (B) 67,663 Handling & erection 14% of purchased equip cost (B) 118,410 Electrical 4% of purchased equip cost (B) 33,831 Piping 2% of purchased equip cost (B) 16,916 Insulation 1% of purchased equip cost (B) 8,458 Painting 1% of purchased equip cost (B) 8,458 Installation Subtotal Standard Expenses 30% 253,735 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 253,735 Total Direct Capital Cost, DC 1,099,519 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 84,578 Construction & field expenses 5% of purchased equip cost (B) 42,289 Contractor fees 10% of purchased equip cost (B) 84,578 Start-up 2% of purchased equip cost (B) 16,916 Performance test 1% of purchased equip cost (B) 8,458 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 25,374 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193 Total Capital Investment (TCI) = DC + IC 1,361,712 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2,223 kw-hr, 7946 hr/yr, 93% utilization 837,802 Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605 Total Annual Direct Operating Costs 14,471,833 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617 Capital Recovery for a 20- year equipment life and a 7% interest rate 128,536 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260 Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093 See Summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 37 of 75

159 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 3 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 600, ,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 600, ,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 16,427, ,802 $/kwh, 2,223 kw-hr, 7946 hr/yr, 93% utilization Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 38 of 75

160 BART Report - Attachment A: Emission Control Cost Analysis Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 109 Deg F - Temperature of waste gas into heat recovery T fi 750 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 558 Deg F - Temperature of waste gas out of heat recovery T fo 301 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 556,766 scfm - Flow of waste gas Q af 3,298 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841 Current Cost Using CHE Plant Cost Index $696,118 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 Reheat Line7 Reheat 39 of 75

161 BART Report - Attachment A: Emission Control Cost Analysis Table A.4.a: NO X Control - Low-NO X Burners Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F Size 165 mmbtu/hr CONTROL EQUIPMENT COSTS Capital Costs (1) Total Capital Investment (TCI) = DC + IC 1,474,892 Operating Costs (2) Total Annual Cost (Annualized Capital Cost) 139,219 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 139,219 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % Sulfur Dioxide (SO 2 ) % NA NA NA Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section Cost is ratioed to Line 4 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X emissions based on NO X CEMS

162 BART Report - Attachment A: Emission Control Cost Analysis Table A.4.b: NO X Control - Low-NO X Burners Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F Size 165 mmbtu/hr CONTROL EQUIPMENT COSTS Capital Costs (1) Total Capital Investment (TCI) = DC + IC 1,474,892 Operating Costs (2) Total Annual Cost (Annualized Capital Cost) 139,219 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 139,219 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % Sulfur Dioxide (SO 2 ) % NA NA NA Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section Cost is ratioed to Line 5 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X emissions based on NO X CEMS

163 BART Report - Attachment A: Emission Control Cost Analysis Table A.4.c: NO X Control - Low-NO X Burners Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F Size 165 mmbtu/hr CONTROL EQUIPMENT COSTS Capital Costs (1) Total Capital Investment (TCI) = DC + IC 1,200,000 Operating Costs (2) Total Annual Cost (Annualized Capital Cost) 113,272 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 113,272 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Exit Conc. Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % Sulfur Dioxide (SO 2 ) % NA NA NA Notes & Assumptions 1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on estimated reduction of line 6 total NO X emissions based on NO X CEMS

164 BART Report - Attachment A: Emission Control Cost Analysis Table A.5.a: NO X Control - Ported Kilns Operating Unit: Line 3 waste gas Emission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 32º F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 68º F Dry Std Flow Rate 257,906 68º F Size 165 mmbtu/hr Minntac Line 4/5 Budget Estimate = 5,000,000 CONTROL EQUIPMENT COSTS $ Capital Costs (1) Total Capital Investment (TCI) = DC + IC 3,616,464 Minntac Line 4/5 volumetric flow = 650,000 acfm Operating Costs (2) Minntac Line 3 volumetric flow = 378,824 acfm Total Annual Cost (Annualized Capital Cost) 341,369 Use "6/10 Rule" to calculate Line 3 Cost = $ 3,616,464 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 341,369 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) , % ,076 Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate and scaled to Line 3 stack flow rate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

165 BART Report - Attachment A: Emission Control Cost Analysis Table A.5.b: NO X Control - Ported Kilns Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F Size 165 mmbtu/hr CONTROL EQUIPMENT COSTS Capital Costs (1) Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = $ 5,000,000 Operating Costs (2) Total Annual Cost (Annualized Capital Cost) 471,965 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 471,965 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % ,209 Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

166 BART Report - Attachment A: Emission Control Cost Analysis Table A.5.c: NO X Control - Ported Kilns Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F Size 165 mmbtu/hr CONTROL EQUIPMENT COSTS Capital Costs (1) Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = $ 5,000,000 Operating Costs (2) Total Annual Cost (Annualized Capital Cost) 471,965 Capital Recovery Factor Interest Rate 7.00% Equipment Life 20 years CRF Capital Recovery Cost 471,965 Emission Control Cost Calculation Actual Emis Max Emis Annual Control Eff (3) Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % ,186 Notes & Assumptions 1 Capital costs based on Minntac Line 4/5 budget estimate. 2 Total annualized cost is equal to the annualized capital cost. 3 Control efficiency based on report, "NO X Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."

167 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO 2 Control - Wet Walled Electrostatic Precipitator Operating Unit: Line 3 waste gas Emission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 32º F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 68º F Dry Std Flow Rate 257,906 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 4,994,311 Purchased Equipment Total (B) 22% of control device cost (A) 6,068,088 Installation - Standard Costs 67% of purchased equip cost (B) 4,065,619 Installation - Site Specific Costs 6,200,000 Installation Total 4,065,619 Total Direct Capital Cost, DC 10,133,707 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810 Total Capital Investment (TCI) = DC + IC 27,948,027 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,023,179 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) , % NA Sulfur Dioxide (SO 2) % ,201 Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm 3 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 WWESP 9/7/2006 Page 46 of 75

168 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 4,994,311 Instrumentation 10% of control device cost (A) 499,431 MN Sales Taxes 6.5% of control device cost (A) 324,630 Freight 5% of control device cost (A) 249,716 Purchased Equipment Total (B) 22% 6,068,088 Installation Foundations & supports 4% of purchased equip cost (B) 242,724 Handling & erection 50% of purchased equip cost (B) 3,034,044 Electrical 8% of purchased equip cost (B) 485,447 Piping 1% of purchased equip cost (B) 60,681 Insulation 2% of purchased equip cost (B) 121,362 Painting 2% of purchased equip cost (B) 121,362 Installation Subtotal Standard Expenses 67% 4,065,619 Total Direct Capital Cost, DC 10,133,707 Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,213,618 Construction & field expenses 20% of purchased equip cost (B) 1,213,618 Contractor fees 10% of purchased equip cost (B) 606,809 Start-up 1% of purchased equip cost (B) 60,681 Performance test 1% of purchased equip cost (B) 60,681 Model Studies 2% of purchased equip cost (B) 121,362 Contingencies 3% of purchased equip cost (B) 182,043 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810 Total Capital Investment (TCI) = DC + IC 13,592,517 Retrofit multiplier 3 60% of TCI 8,155,510 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific NA Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 27,948,027 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor $/Hr, 15.0 hr/wk, 7946 hr/yr 6,283 Maintenance Materials 1.00 % of Maintenance Labor 49,943 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 761 kw-hr, 7946 hr/yr, 93% utilization 286,765 Water 0.08 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 57,108 WW Treat Neutralization 1.69 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 1,205,171 Caustic $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization 278,556 Total Annual Direct Operating Costs 2,023,179 Indirect Operating Costs Overhead 60% of total labor and material costs 117,347 Administration (2% total capital costs) 2% of total capital costs (TCI) 271,850 Property tax (1% total capital costs) 1% of total capital costs (TCI) 135,925 Insurance (1% total capital costs) 1% of total capital costs (TCI) 135,925 Capital Recovery for a 20- year equipment life and a 7% interest rate 2,638,096 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144 Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323 See summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 WWESP 9/7/2006 Page 47 of 75

169 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0 Electrical Use Flow acfm D P in H2O kw Fan Power 322, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 30.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 76, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48 Total Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm EPA Cont Cost Manual 6th ed - Sec 6 Ch lb/hr Reagent Use 2.50 lb NaOH/lb SO lb/hr caustic Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor $/Hr 15.0 hr/wk 660 6,283 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 49,943 EPA Cont Cost Manual 6th ed - Sec 6 Ch Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 5,622, ,765 $/kwh, 761 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 1,610.0 gpm 713,853 57,108 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 1,610.0 gpm 713,853 1,205,171 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization Caustic $/ton lb/hr ,556 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization See summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line3 WWESP 9/7/2006 Page 48 of 75

170 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO 2 Control - Wet Walled Electrostatic Precipitator Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,612,198 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821 Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710 Installation - Site Specific Costs 6,200,000 Installation Total 6,196,710 Total Direct Capital Cost, DC 15,445,530 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 39,347,773 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,597 Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm 3 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 49 of 75

171 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,612,198 Instrumentation 10% of control device cost (A) 761,220 MN Sales Taxes 6.5% of control device cost (A) 494,793 Freight 5% of control device cost (A) 380,610 Purchased Equipment Total (B) 22% 9,248,821 Installation Foundations & supports 4% of purchased equip cost (B) 369,953 Handling & erection 50% of purchased equip cost (B) 4,624,410 Electrical 8% of purchased equip cost (B) 739,906 Piping 1% of purchased equip cost (B) 92,488 Insulation 2% of purchased equip cost (B) 184,976 Painting 2% of purchased equip cost (B) 184,976 Installation Subtotal Standard Expenses 67% 6,196,710 Total Direct Capital Cost, DC 15,445,530 Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,849,764 Construction & field expenses 20% of purchased equip cost (B) 1,849,764 Contractor fees 10% of purchased equip cost (B) 924,882 Start-up 1% of purchased equip cost (B) 92,488 Performance test 1% of purchased equip cost (B) 92,488 Model Studies 2% of purchased equip cost (B) 184,976 Contingencies 3% of purchased equip cost (B) 277,465 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 20,717,358 Retrofit multiplier 3 60% of TCI 12,430,415 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific NA Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 39,347,773 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683 Maintenance Materials 1.00 % of Maintenance Labor 76,122 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,536 kw-hr, 7946 hr/yr, 93% utilization 578,873 Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281 WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799 Caustic $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481 Total Annual Direct Operating Costs 3,768,592 Indirect Operating Costs Overhead 60% of total labor and material costs 136,895 Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347 Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174 Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174 Capital Recovery for a 20- year equipment life and a 7% interest rate 3,714,151 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332 See summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 50 of 75

172 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0 Electrical Use Flow acfm D P in H2O kw Fan Power 650, ,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 153, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48 Total 1,536.0 Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm EPA Cont Cost Manual 6th ed - Sec 6 Ch lb/hr Reagent Use 2.50 lb NaOH/lb SO lb/hr caustic Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor $/Hr 15.0 hr/wk ,683 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 11,350, ,873 $/kwh, 1,536 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,250.0 gpm 1,441, ,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization Caustic $/ton lb/hr 1, ,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization See summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line4 WWESP 9/7/2006 Page 51 of 75

173 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO 2 Control - Wet Walled Electrostatic Precipitator Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,612,198 Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821 Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710 Installation - Site Specific Costs 6,200,000 Installation Total 6,196,710 Total Direct Capital Cost, DC 15,445,530 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 39,347,773 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,597 Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm 3 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 52 of 75

174 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,612,198 Instrumentation 10% of control device cost (A) 761,220 MN Sales Taxes 6.5% of control device cost (A) 494,793 Freight 5% of control device cost (A) 380,610 Purchased Equipment Total (B) 22% 9,248,821 Installation Foundations & supports 4% of purchased equip cost (B) 369,953 Handling & erection 50% of purchased equip cost (B) 4,624,410 Electrical 8% of purchased equip cost (B) 739,906 Piping 1% of purchased equip cost (B) 92,488 Insulation 2% of purchased equip cost (B) 184,976 Painting 2% of purchased equip cost (B) 184,976 Installation Subtotal Standard Expenses 67% 6,196,710 Total Direct Capital Cost, DC 15,445,530 Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,849,764 Construction & field expenses 20% of purchased equip cost (B) 1,849,764 Contractor fees 10% of purchased equip cost (B) 924,882 Start-up 1% of purchased equip cost (B) 92,488 Performance test 1% of purchased equip cost (B) 92,488 Model Studies 2% of purchased equip cost (B) 184,976 Contingencies 3% of purchased equip cost (B) 277,465 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828 Total Capital Investment (TCI) = DC + IC 20,717,358 Retrofit multiplier 3 60% of TCI 12,430,415 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific NA Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 39,347,773 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683 Maintenance Materials 1.00 % of Maintenance Labor 76,122 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,536 kw-hr, 7946 hr/yr, 93% utilization 578,873 Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281 WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799 Caustic $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481 Total Annual Direct Operating Costs 3,768,592 Indirect Operating Costs Overhead 60% of total labor and material costs 136,895 Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347 Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174 Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174 Capital Recovery for a 20- year equipment life and a 7% interest rate 3,714,151 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332 See summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 53 of 75

175 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0 Electrical Use Flow acfm D P in H2O kw Fan Power 650, ,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 153, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48 Total 1,536.0 Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm EPA Cont Cost Manual 6th ed - Sec 6 Ch lb/hr Reagent Use 2.50 lb NaOH/lb SO lb/hr caustic Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor $/Hr 15.0 hr/wk ,683 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 11,350, ,873 $/kwh, 1,536 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,250.0 gpm 1,441, ,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization Caustic $/ton lb/hr 1, ,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization See summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line5 WWESP 9/7/2006 Page 54 of 75

176 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO 2 Control - Wet Walled Electrostatic Precipitator Operating Unit: Line 6 waste gas Emission Unit Number EU 313 Stack/Vent Number SV 144 Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 6,928,558 Purchased Equipment Total (B) 22% of control device cost (A) 8,418,198 Installation - Standard Costs 67% of purchased equip cost (B) 5,640,193 Installation - Site Specific Costs 6,200,000 Installation Total 5,640,193 Total Direct Capital Cost, DC 14,058,391 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373 Total Capital Investment (TCI) = DC + IC 36,370,821 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,620,521 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,216 Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm 3 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 55 of 75

177 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 6,928,558 Instrumentation 10% of control device cost (A) 692,856 MN Sales Taxes 6.5% of control device cost (A) 450,356 Freight 5% of control device cost (A) 346,428 Purchased Equipment Total (B) 22% 8,418,198 Installation Foundations & supports 4% of purchased equip cost (B) 336,728 Handling & erection 50% of purchased equip cost (B) 4,209,099 Electrical 8% of purchased equip cost (B) 673,456 Piping 1% of purchased equip cost (B) 84,182 Insulation 2% of purchased equip cost (B) 168,364 Painting 2% of purchased equip cost (B) 168,364 Installation Subtotal Standard Expenses 67% 5,640,193 Total Direct Capital Cost, DC 14,058,391 Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,683,640 Construction & field expenses 20% of purchased equip cost (B) 1,683,640 Contractor fees 10% of purchased equip cost (B) 841,820 Start-up 1% of purchased equip cost (B) 84,182 Performance test 1% of purchased equip cost (B) 84,182 Model Studies 2% of purchased equip cost (B) 168,364 Contingencies 3% of purchased equip cost (B) 252,546 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373 Total Capital Investment (TCI) = DC + IC 18,856,763 Retrofit multiplier 3 60% of TCI 11,314,058 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific NA Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 36,370,821 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor $/Hr, 15.0 hr/wk, 7946 hr/yr 10,842 Maintenance Materials 1.00 % of Maintenance Labor 69,286 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,397 kw-hr, 7946 hr/yr, 93% utilization 526,675 Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413 WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661 Caustic $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292 Total Annual Direct Operating Costs 3,620,521 Indirect Operating Costs Overhead 60% of total labor and material costs 131,688 Administration (2% total capital costs) 2% of total capital costs (TCI) 377,135 Property tax (1% total capital costs) 1% of total capital costs (TCI) 188,568 Insurance (1% total capital costs) 1% of total capital costs (TCI) 188,568 Capital Recovery for a 20- year equipment life and a 7% interest rate 3,433,148 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107 Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628 See summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 56 of 75

178 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0 Electrical Use Flow acfm D P in H2O kw Fan Power 600, ,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 131, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48 Total 1,397.5 Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm EPA Cont Cost Manual 6th ed - Sec 6 Ch lb/hr Reagent Use 2.50 lb NaOH/lb SO lb/hr caustic Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor $/Hr 15.0 hr/wk ,842 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 69,286 EPA Cont Cost Manual 6th ed - Sec 6 Ch Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 10,326, ,675 $/kwh, 1,397 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,000.0 gpm 1,330, ,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization Caustic $/ton lb/hr 1, ,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization See summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line6 WWESP 9/7/2006 Page 57 of 75

179 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: SO 2 Control - Wet Walled Electrostatic Precipitator Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 7,255,257 Purchased Equipment Total (B) 22% of control device cost (A) 8,815,138 Installation - Standard Costs 67% of purchased equip cost (B) 5,906,142 Installation - Site Specific Costs 6,200,000 Installation Total 5,906,142 Total Direct Capital Cost, DC 14,721,280 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628 Total Capital Investment (TCI) = DC + IC 37,793,453 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,632,323 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,638 Notes & Assumptions 1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3. 2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm 3 CUECost Workbook Version 1.0, USEPA Document Page 2 Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 58 of 75

180 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) 1 Purchased Equipment Costs (A) 2 - ESP + auxiliary equipment 7,255,257 Instrumentation 10% of control device cost (A) 725,526 MN Sales Taxes 6.5% of control device cost (A) 471,592 Freight 5% of control device cost (A) 362,763 Purchased Equipment Total (B) 22% 8,815,138 Installation Foundations & supports 4% of purchased equip cost (B) 352,606 Handling & erection 50% of purchased equip cost (B) 4,407,569 Electrical 8% of purchased equip cost (B) 705,211 Piping 1% of purchased equip cost (B) 88,151 Insulation 2% of purchased equip cost (B) 176,303 Painting 2% of purchased equip cost (B) 176,303 Installation Subtotal Standard Expenses 67% 5,906,142 Total Direct Capital Cost, DC 14,721,280 Indirect Capital Costs Engineering, supervision 20% of purchased equip cost (B) 1,763,028 Construction & field expenses 20% of purchased equip cost (B) 1,763,028 Contractor fees 10% of purchased equip cost (B) 881,514 Start-up 1% of purchased equip cost (B) 88,151 Performance test 1% of purchased equip cost (B) 88,151 Model Studies 2% of purchased equip cost (B) 176,303 Contingencies 3% of purchased equip cost (B) 264,454 Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628 Total Capital Investment (TCI) = DC + IC 19,745,908 Retrofit multiplier 3 60% of TCI 11,847,545 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific NA Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 37,793,453 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177 Supervisor 15% 15% of Operator Costs 18,176 Maintenance Maintenance Labor $/Hr, 15.0 hr/wk, 7946 hr/yr 11,707 Maintenance Materials 1.00 % of Maintenance Labor 72,553 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,418 kw-hr, 7946 hr/yr, 93% utilization 534,344 Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413 WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661 Caustic $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292 Total Annual Direct Operating Costs 3,632,323 Indirect Operating Costs Overhead 60% of total labor and material costs 134,168 Administration (2% total capital costs) 2% of total capital costs (TCI) 394,918 Property tax (1% total capital costs) 1% of total capital costs (TCI) 197,459 Insurance (1% total capital costs) 1% of total capital costs (TCI) 197,459 Capital Recovery for a 20- year equipment life and a 7% interest rate 3,567,435 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439 Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761 See summary page for notes and assumptions Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 59 of 75

181 BART Report - Attachment A: Emission Control Cost Analysis Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit Amount Required 0 Total Rep Parts Cost 0 Installation Labor 0 Total Installed Cost 0 Annualized Cost 0 Electrical Use Flow acfm D P in H2O kw Fan Power 600, ,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46 Fluid Head (ft) Pump Eff. Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47 Plate Area ESP Power 141, EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48 Total 1,417.8 Reagent Use & Other Operating Costs gpm Water 5.00 gal/min-kacfm EPA Cont Cost Manual 6th ed - Sec 6 Ch lb/hr Reagent Use 2.50 lb NaOH/lb SO lb/hr caustic Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor 61 $/Hr 2.0 hr/8 hr shift 1, ,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 18,176 15% of Operator Costs Maintenance Maint Labor $/Hr 15.0 hr/wk ,707 $/Hr, 15.0 hr/wk, 7946 hr/yr Maint Mtls 1 % of Purchase Cost NA 72,553 EPA Cont Cost Manual 6th ed - Sec 6 Ch Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 10,477, ,344 $/kwh, 1,418 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/mgal 3,000.0 gpm 1,330, ,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization Caustic $/ton lb/hr 1, ,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization See summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs Line7 WWESP 9/7/2006 Page 60 of 75

182 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO 2 Control - Wet Scrubber Operating Unit: Line 3 waste gas Emission Unit Number EU 223 Stack/Vent Number SV 103 Standardized Flow Rate 268,515 32º F Expected Utilization Rate 93% Temperature 130 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 68º F Dry Std Flow Rate 257,906 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 3,453,270 Purchased Equipment Total (B) 22% of control device cost (A) 4,195,723 Installation - Standard Costs 85% of purchased equip cost (B) 3,566,365 Installation - Site Specific Costs 6,200,000 Installation Total 3,566,365 Total Direct Capital Cost, DC 7,762,088 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358 Total Capital Investment (TCI) = DC + IC 19,626,314 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 570,934 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) , % NA Sulfur Dioxide (SO 2) % ,253 Notes & Assumptions 1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf 3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate 4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition. 5 CUECost Workbook Version 1.0, USEPA Document Page 2 Line3 Wet Scrubber

183 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO2 Control - Wet Scrubber CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,453,270 Instrumentation 10% of control device cost (A) 345,327 MN Sales Taxes 6.5% of control device cost (A) 224,463 Freight 5% of control device cost (A) 172,663 Purchased Equipment Total (B) 22% 4,195,723 Installation Foundations & supports 12% of purchased equip cost (B) 503,487 Handling & erection 40% of purchased equip cost (B) 1,678,289 Electrical 1% of purchased equip cost (B) 41,957 Piping 30% of purchased equip cost (B) 1,258,717 Insulation 1% of purchased equip cost (B) 41,957 Painting 1% of purchased equip cost (B) 41,957 Installation Subtotal Standard Expenses 85% 3,566,365 Total Direct Capital Cost, DC 7,762,088 Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 209,786 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 209,786 Start-up 1% of purchased equip cost (B) 41,957 Performance test 1% of purchased equip cost (B) 41,957 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 125,872 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358 Total Capital Investment (TCI) = DC + IC 8,391,446 Retrofit multiplier 5 60% of TCI 5,034,868 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 19,626,314 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 662 kw-hr, 7946 hr/yr, 93% utilization 249,567 Water 0.08 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization 10,717 WW Treat Neutralization 1.69 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization 183,186 Lime $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization 32,037 Total Annual Direct Operating Costs 570,934 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 167,829 Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,914 Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,914 Capital Recovery for a 20- year equipment life and a 7% interest rate 1,852,585 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433 See Summary page for notes and assumptions Line3 Wet Scrubber

184 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.a: SO2 Control - Wet Scrubber Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Equipment Life 20 years CRF 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 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 322, EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48 Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 12,236 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 302 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total Reagent Use & Other Operating Costs Caustic Use lb/hr SO lb NaOH/lb SO lb/hr Caustic Lime Use lb/hr SO lb Lime/lb SO 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 12,236 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 302 gpm Evaporation Loss 4 = gpm Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 4,893, ,567 $/kwh, 662 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal gpm 133,963 10,717 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralizatio 1.69 $/kgal gpm 108, ,186 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton 94.9 lb/hr ,037 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Line3 Wet Scrubber

185 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO 2 Control - Wet Scrubber Operating Unit: Line 4 waste gas Emission Unit Number EU 259 Stack/Vent Number SV 118 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,263,384 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011 Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759 Installation - Site Specific Costs 6,200,000 Installation Total 5,435,759 Total Direct Capital Cost, DC 11,830,771 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 26,664,036 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,358 Notes & Assumptions 1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf 3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate 4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition. 5 CUECost Workbook Version 1.0, USEPA Document Page 2 Line4 Wet Scrubber

186 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO2 Control - Wet Scrubber CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384 Instrumentation 10% of control device cost (A) 526,338 MN Sales Taxes 7% of control device cost (A) 342,120 Freight 5% of control device cost (A) 263,169 Purchased Equipment Total (B) 22% 6,395,011 Installation Foundations & supports 12% of purchased equip cost (B) 767,401 Handling & erection 40% of purchased equip cost (B) 2,558,004 Electrical 1% of purchased equip cost (B) 63,950 Piping 30% of purchased equip cost (B) 1,918,503 Insulation 1% of purchased equip cost (B) 63,950 Painting 1% of purchased equip cost (B) 63,950 Installation Subtotal Standard Expenses 85% 5,435,759 Total Direct Capital Cost, DC 11,830,771 Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 319,751 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 319,751 Start-up 1% of purchased equip cost (B) 63,950 Performance test 1% of purchased equip cost (B) 63,950 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 191,850 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 12,790,022 Retrofit multiplier 5 60% of TCI 7,674,013 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 26,664,036 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,337 kw-hr, 7946 hr/yr, 93% utilization 503,785 Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634 WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785 Lime $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555 Total Annual Direct Operating Costs 1,038,186 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800 Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900 Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900 Capital Recovery for a 20- year equipment life and a 7% interest rate 2,516,896 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939 See Summary page for notes and assumptions Line4 Wet Scrubber

187 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.b: SO2 Control - Wet Scrubber Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Equipment Life 20 years CRF 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 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 650, EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48 Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 24,700 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 610 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total Reagent Use & Other Operating Costs Caustic Use lb/hr SO lb NaOH/lb SO lb/hr Caustic Lime Use lb/hr SO lb Lime/lb SO 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 24,700 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 610 gpm Evaporation Loss 4 = gpm Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,878, ,785 $/kwh, 1,337 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralizatio 1.69 $/kgal gpm 219, ,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton lb/hr ,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Line4 Wet Scrubber

188 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO 2 Control - Wet Scrubber Operating Unit: Line 5 waste gas Emission Unit Number EU 280 Stack/Vent Number SV 127 Standardized Flow Rate 556,174 32º F Expected Utilization Rate 93% Temperature 115 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 68º F Dry Std Flow Rate 534,198 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,263,384 Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011 Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759 Installation - Site Specific Costs 6,200,000 Installation Total 5,435,759 Total Direct Capital Cost, DC 11,830,771 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 26,664,036 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,358 Notes & Assumptions 1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf 3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate 4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition. 5 CUECost Workbook Version 1.0, USEPA Document Page 2 Line5 Wet Scrubber

189 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO2 Control - Wet Scrubber CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384 Instrumentation 10% of control device cost (A) 526,338 MN Sales Taxes 7% of control device cost (A) 342,120 Freight 5% of control device cost (A) 263,169 Purchased Equipment Total (B) 22% 6,395,011 Installation Foundations & supports 12% of purchased equip cost (B) 767,401 Handling & erection 40% of purchased equip cost (B) 2,558,004 Electrical 1% of purchased equip cost (B) 63,950 Piping 30% of purchased equip cost (B) 1,918,503 Insulation 1% of purchased equip cost (B) 63,950 Painting 1% of purchased equip cost (B) 63,950 Installation Subtotal Standard Expenses 85% 5,435,759 Total Direct Capital Cost, DC 11,830,771 Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 319,751 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 319,751 Start-up 1% of purchased equip cost (B) 63,950 Performance test 1% of purchased equip cost (B) 63,950 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 191,850 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252 Total Capital Investment (TCI) = DC + IC 12,790,022 Retrofit multiplier 5 60% of TCI 7,674,013 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 26,664,036 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,337 kw-hr, 7946 hr/yr, 93% utilization 503,785 Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634 WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785 Lime $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555 Total Annual Direct Operating Costs 1,038,186 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800 Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900 Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900 Capital Recovery for a 20- year equipment life and a 7% interest rate 2,516,896 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753 Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939 See Summary page for notes and assumptions Line5 Wet Scrubber

190 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.c: SO2 Control - Wet Scrubber Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Equipment Life 20 years CRF 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 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 650, EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48 Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 24,700 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 610 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total Reagent Use & Other Operating Costs Caustic Use lb/hr SO lb NaOH/lb SO lb/hr Caustic Lime Use lb/hr SO lb Lime/lb SO 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 24,700 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 610 gpm Evaporation Loss 4 = gpm Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,878, ,785 $/kwh, 1,337 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralizatio 1.69 $/kgal gpm 219, ,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton lb/hr ,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Line5 Wet Scrubber

191 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO 2 Control - Wet Scrubber Operating Unit: Line 6 waste gas Emission Unit Number EU 313 Stack/Vent Number SV 144 Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,016,580 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145 Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873 Installation - Site Specific Costs 6,200,000 Installation Total 5,180,873 Total Direct Capital Cost, DC 11,276,018 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 25,704,464 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,093 Notes & Assumptions 1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf 3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate 4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition. 5 CUECost Workbook Version 1.0, USEPA Document Page 2 Line6 Wet Scrubber

192 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO2 Control - Wet Scrubber CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580 Instrumentation 10% of control device cost (A) 501,658 MN Sales Taxes 7% of control device cost (A) 326,078 Freight 5% of control device cost (A) 250,829 Purchased Equipment Total (B) 22% 6,095,145 Installation Foundations & supports 12% of purchased equip cost (B) 731,417 Handling & erection 40% of purchased equip cost (B) 2,438,058 Electrical 1% of purchased equip cost (B) 60,951 Piping 30% of purchased equip cost (B) 1,828,543 Insulation 1% of purchased equip cost (B) 60,951 Painting 1% of purchased equip cost (B) 60,951 Installation Subtotal Standard Expenses 85% 5,180,873 Total Direct Capital Cost, DC 11,276,018 Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 304,757 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 304,757 Start-up 1% of purchased equip cost (B) 60,951 Performance test 1% of purchased equip cost (B) 60,951 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 182,854 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 12,190,290 Retrofit multiplier 5 60% of TCI 7,314,174 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 25,704,464 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,234 kw-hr, 7946 hr/yr, 93% utilization 465,032 Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970 WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340 Lime $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069 Total Annual Direct Operating Costs 981,838 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806 Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903 Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903 Capital Recovery for a 20- year equipment life and a 7% interest rate 2,426,320 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025 See Summary page for notes and assumptions Line6 Wet Scrubber

193 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.d: SO2 Control - Wet Scrubber Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Equipment Life 20 years CRF 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 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 600, EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48 Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 22,800 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 563 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total Reagent Use & Other Operating Costs Caustic Use lb/hr SO lb NaOH/lb SO lb/hr Caustic Lime Use lb/hr SO lb Lime/lb SO 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 22,800 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 563 gpm Evaporation Loss 4 = gpm Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,118, ,032 $/kwh, 1,234 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralizatio 1.69 $/kgal gpm 202, ,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton lb/hr ,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Line6 Wet Scrubber

194 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO 2 Control - Wet Scrubber Operating Unit: Line 7 waste gas Emission Unit Number EU 332 Stack/Vent Number SV 151 Standardized Flow Rate 518,805 32º F Expected Utilization Rate 93% Temperature 109 Deg F Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 68º F Dry Std Flow Rate 498,306 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs (1) Purchased Equipment (A) 5,016,580 Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145 Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873 Installation - Site Specific Costs 6,200,000 Installation Total 5,180,873 Total Direct Capital Cost, DC 11,276,018 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 25,704,464 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025 Actual Emission Control Cost Calculation Emis Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) 1, , % NA Sulfur Dioxide (SO 2) % ,093 Notes & Assumptions 1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm. 2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf 3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate 4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition. 5 CUECost Workbook Version 1.0, USEPA Document Page 2 Line7 Wet Scrubber

195 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO2 Control - Wet Scrubber CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580 Instrumentation 10% of control device cost (A) 501,658 MN Sales Taxes 7% of control device cost (A) 326,078 Freight 5% of control device cost (A) 250,829 Purchased Equipment Total (B) 22% 6,095,145 Installation Foundations & supports 12% of purchased equip cost (B) 731,417 Handling & erection 40% of purchased equip cost (B) 2,438,058 Electrical 1% of purchased equip cost (B) 60,951 Piping 30% of purchased equip cost (B) 1,828,543 Insulation 1% of purchased equip cost (B) 60,951 Painting 1% of purchased equip cost (B) 60,951 Installation Subtotal Standard Expenses 85% 5,180,873 Total Direct Capital Cost, DC 11,276,018 Indirect Capital Costs Engineering, supervision 5% of purchased equip cost (B) 304,757 Construction & field expenses 0% of purchased equip cost (B) 0 Contractor fees 5% of purchased equip cost (B) 304,757 Start-up 1% of purchased equip cost (B) 60,951 Performance test 1% of purchased equip cost (B) 60,951 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 182,854 Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272 Total Capital Investment (TCI) = DC + IC 12,190,290 Retrofit multiplier 5 60% of TCI 7,314,174 Sitework and foundations Site Specific 1,400,000 Structural steel Site Specific 4,800,000 Site Specific - Other Site Specific 0 Total Site Specific Costs 6,200,000 Total Capital Investment (TCI) Retrofit Installed 25,704,464 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Supervisor 15% 15% of Operator Costs 4,544 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294 Maintenance Materials 100% of maintenance labor costs 30,294 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 1,234 kw-hr, 7946 hr/yr, 93% utilization 465,032 Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970 WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340 Lime $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069 Total Annual Direct Operating Costs 981,838 Indirect Operating Costs Overhead 60% of total labor and material costs 57,256 Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806 Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903 Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903 Capital Recovery for a 20- year equipment life and a 7% interest rate 2,426,320 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187 Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025 See Summary page for notes and assumptions Line7 Wet Scrubber

196 BART Report - Attachment A: Emission Control Cost Analysis Table A.7.e: SO2 Control - Wet Scrubber Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Equipment Life 20 years CRF 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 Rep part cost per unit 0.00 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 600, EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48 Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 22,800 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 H2O WW Disch 563 gpm EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49 Other Total Reagent Use & Other Operating Costs Caustic Use lb/hr SO lb NaOH/lb SO lb/hr Caustic Lime Use lb/hr SO lb Lime/lb SO 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 22,800 gpm Water Makeup Rate/WW Disch 3 = 2.0% of circulating water rate + evap. loss = 563 gpm Evaporation Loss 4 = gpm Operating Cost Calculations Annual hours of operation: 7,946 Utilization Rate: 93% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Supervisor 15% of Op. NA 4,544 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr Maint Mtls 100 % of Maintenance Labor NA 30, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 9,118, ,032 $/kwh, 1,234 kw-hr, 7946 hr/yr, 93% utilization Water 0.08 $/kgal gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization WW Treat Neutralizatio 1.69 $/kgal gpm 202, ,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization Lime 91.4 $/ton lb/hr ,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor Line7 Wet Scrubber

197 BART Report - Attachment A: Emission Control Cost Analysis Table A.8: Utility Plant Heater Boilers Cost Summary NO x Control Cost Summary Control Technology Low Temperature Oxidation (LoTOx) Control Eff % Controlled Emissions T/y Emission Reduction T/yr Installed Capital Cost $ Annualized Operating Cost $/yr Pollution Control Cost $/ton Utility Plant Heater Boiler #1 90% $1,681,680 $304,052 $23,668 Utility Plant Heater Boiler #2 90% $1,681,680 $304,052 $24,489 Utility Plant Heater Boiler #4 90% $1,914,641 $343,518 $25,720 Utility Plant Heater Boiler #5 90% $1,914,641 $343,518 $27,713 Selective Catalytic Reduction (SCR) Utility Plant Heater Boiler #1 80% $4,488,567 $592,165 $50,632 Utility Plant Heater Boiler #2 80% $4,488,567 $592,165 $52,345 Utility Plant Heater Boiler #4 80% $5,234,392 $688,384 $56,028 Utility Plant Heater Boiler #5 80% $5,234,392 $688,384 $60,211 Low NO X Burner / Flue Gas Recirculation Utility Plant Heater Boiler #1 75% $1,384,220 $166,560 $15,558 Utility Plant Heater Boiler #2 75% $1,384,220 $166,560 $16,098 Utility Plant Heater Boiler #4 75% $1,745,018 $209,678 $18,839 Utility Plant Heater Boiler #5 75% $1,745,018 $209,678 $20,299 Regenerative Selective Catalytic Reduction (R-SCR) Utility Plant Heater Boiler #1 70% $1,690,961 $238,636 $22,879 Utility Plant Heater Boiler #2 70% $1,690,961 $238,636 $23,638 Utility Plant Heater Boiler #4 70% $2,156,692 $316,281 $28,633 Utility Plant Heater Boiler #5 70% $2,156,692 $316,281 $30,710 Low NO X Burner / Overfire Air (OFA) Utility Plant Heater Boiler #1 67% $1,131,149 $136,590 $14,282 Utility Plant Heater Boiler #2 67% $1,131,149 $136,590 $14,778 Utility Plant Heater Boiler #4 67% $1,425,985 $171,954 $17,294 Utility Plant Heater Boiler #5 67% $1,425,985 $171,954 $18,634 Low NO X Burner Utility Plant Heater Boiler #1 50% $344,269 $47,480 $6,653 Utility Plant Heater Boiler #2 50% $344,269 $47,480 $6,883 Utility Plant Heater Boiler #4 50% $434,003 $59,540 $8,024 Utility Plant Heater Boiler #5 50% $434,003 $59,540 $8,646 Selective Non-Catalytic Reduction (SNCR) Utility Plant Heater Boiler #1 50% $1,084,406 $300,018 $42,037 Utility Plant Heater Boiler #2 50% $1,084,406 $300,018 $43,495 Utility Plant Heater Boiler #4 50% $1,277,232 $354,613 $47,792 Utility Plant Heater Boiler #5 50% $1,277,232 $354,613 $51,494 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Cost Summary Cost Summary 1 of 106

198 Draft BART Emission Control Cost Analysis Table A.9: Summary of Utility, Chemical and Supply Costs Operating Unit: Utility Plant Heater Boiler #1 Study Year 2006 Emission Unit Number EU 001 Stack/Vent Number SV 001 Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Operating Unit: Utility Plant Heater Boiler #3 Emission Unit Number EU 003 Stack/Vent Number SV 003 Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Reference Item Unit Cost Units Cost Year Data Source Notes Operating Labor $/hr Per Chrissy Bartovich Maintenance Labor $/hr Per Chrissy Bartovich Electricity $/kwh Expected annual average industrial price of electricity in the West North Central Division for DOE Energy Information Administration. Average US Industrial Natural Gas Prices. July '05 to June '06. Natural Gas $/mscf Water 0.08 $/mgal 2006 Per Chrissy Bartovich Ch 1 Carbon Adsrobers, 1999 $ $0.30 Avg of 22.5 and 7 yrs and 3% inflation Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich EPA Air Pollution Control Cost Manual 6th Ed Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% inflation Compressed Air 0.32 $/kscf , Section 6 Chapter 1 Wastewater Disposal Bio-Treat 4.28 $/kgal Hazardous Waste Disposal $/ton Waste Transport 0.56 $/ton-mi EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 Ch 1lists $ $6.00 for municipal treatment, $3.80 is average. Cost adjusted for 3% inflation EPA Air Pollution Control Cost Manual 6th Ed Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% 2002, Section 2 Chapter inflation EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation Chemicals & Supplies Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery Oxygen $/ton BOC EPA Air Pollution Control Cost Manual 6th Ed Annual costs for a retrofit SCR system example problem. '00 costs Ammonia 0.12 $/lb , Section 5 Chapter 2, page 2-50 adjusted for 3% inflation. (29% aqua.) Catayst & Replacement Parts SCR Catalyst $/ft 3 Cormetech, Inc. Other Sales Tax 6.5 % Interest Rate 7.0% % Please note, for units of measure, k = 1,000 units, MM = 1,000,000 units e.g. kgal = 1,000 gal Operating Information Annual Op. Hrs Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 3,156 Hours 3,156 Hours 3,156 Hours 3,156 Hours 3,156 Hours Average actual operating hours based on 2004 and 2005 emission inventories Utilization Rate Utility Plant Heater Boiler #1 28% Utility Plant Heater Boiler #2 28% Utility Plant Heater Boiler #3 28% Utility Plant Heater Boiler #4 28% Utility Plant Heater Boiler #5 28% Average actual utilization rate based on 2004 and 2005 emission inventories Equipment Life 20 yrs Engineering Estimate Desgin Capacity Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 Standardized Flow Rate Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 Temperature Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 104 MMBtu/hr 104 MMBtu/hr 125 MMBtu/hr 153 MMBtu/hr 153 MMBtu/hr 11,005 32º F 11,005 32º F 13,465 32º F 16,508 32º F 16,508 32º F 380 Deg F 380 Deg F 380 Deg F 380 Deg F 380 Deg F Moisture Content Utility Plant Heater Boiler #1 13.3% Utility Plant Heater Boiler #2 13.3% Utility Plant Heater Boiler #3 13.3% Utility Plant Heater Boiler #4 13.3% Utility Plant Heater Boiler #5 13.3% Actual Flow Rate Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 Standardized Flow Rate Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 Dry Std Flow Rate Utility Plant Heater Boiler #1 Utility Plant Heater Boiler #2 Utility Plant Heater Boiler #3 Utility Plant Heater Boiler #4 Utility Plant Heater Boiler #5 17,000 acfm 17,000 acfm 20,800 acfm 25,500 acfm 25,500 acfm 11,811 68º F 11,811 68º F 14,451 68º F 17,716 68º F 17,716 68º F 10,240 68º F 10,240 68º F 12,529 68º F 15,360 68º F 15,360 68º F Design Basis Baseline Emis. Baseline Emis. Max Emis. (Model) Max Emis. Pollutant T/yr lb/mmbtu lb/hr lb/mmbtu Nitrous Oxides (NOx) Utility Plant Heater Boiler 0.03 # Max emissions based on limited potential emissions as reported in the BART Utility Plant Heater Boiler # spreadsheet. Baseline emissions are Utility Plant Heater Boiler # based on 2005 emission inventory. Utility Plant Heater Boiler # Utility Plant Heater Boiler # P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Utility Chem$ Data Utility Chem$ Data 2 of 106

199 Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation) Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 768,944 Purchased Equipment Total (B) 22% of control device cost (A) 934,267 Installation - Standard Costs 45% of purchased equip cost (B) 420,420 Total Direct Capital Cost, DC 1,354,687 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,668 Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X that has been converted to HNO 3 and N 2 O 5. This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LoTOx #1 LoTOx 3 of 106

200 Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 768,944 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894 MN Sales Taxes 6.5% of control device cost (A) 49,981 Freight 5% of control device cost (A) 38,447 Purchased Equipment Total (B) 22% 934,267 Installation Foundations & supports 12% of purchased equip cost (B) 112,112 Handling & erection (2) 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 9,343 Piping 30% of purchased equip cost (B) 280,280 Insulation 1% of purchased equip cost (B) 9,343 Painting 1% of purchased equip cost (B) 9,343 Installation Subtotal Standard Expenses 45% 420,420 Total Direct Capital Cost, DC 1,354,687 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 93,427 Construction & field expenses 10% of purchased equip cost (B) 93,427 Contractor fees 10% of purchased equip cost (B) 93,427 Start-up 1% of purchased equip cost (B) 9,343 Performance test 1% of purchased equip cost (B) 9,343 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 28,028 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 189 kw-hr, 3156 hr/yr, 28% utilization 8,534 Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502 Oxygen $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367 Total Annual Direct Operating Costs 55,305 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817 Capital Recovery for a 20- year equipment life and a 7% interest rate 158,739 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LoTOx #1 LoTOx 4 of 106

201 Draft BART Emission Control Cost Analysis Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 17,000 No extra load on blower Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 126 gpm No extra load on circulation pump H2O WW Disch 2 gpm No extra load on discharge pump kw-hr LoTOx Electric Use 4 kw/lb O per estimate from PCI Wedeco Total Oxygen Plant Electric Use 12,900 kw - cost accounted for in $/ton of O 2 Total 189 Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion lb/hr O2 5,311 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco Circulating Water Rate Water Makeup Rate WW Discharge (blowdown) gpm 5.8 gpm 2.2 gpm Nitrate loading (as NaNO 3 ) in scrubber water 49 lb/hr NaNO 3 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 167,342 8,534 $/kwh, 189 kw-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal gpm 6, $/mgal, 118 gpm, 3156 hr/yr, 28% utilization Oxygen $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LoTOx #1 LoTOx 5 of 106

202 Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation) Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 768,944 Purchased Equipment Total (B) 22% of control device cost (A) 934,267 Installation - Standard Costs 45% of purchased equip cost (B) 420,420 Total Direct Capital Cost, DC 1,354,687 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,489 Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X that has been converted to HNO 3 and N 2 O 5. This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LoTOx #2 LoTOx 6 of 106

203 Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 768,944 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894 MN Sales Taxes 6.5% of control device cost (A) 49,981 Freight 5% of control device cost (A) 38,447 Purchased Equipment Total (B) 22% 934,267 Installation Foundations & supports 12% of purchased equip cost (B) 112,112 Handling & erection (2) 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 9,343 Piping 30% of purchased equip cost (B) 280,280 Insulation 1% of purchased equip cost (B) 9,343 Painting 1% of purchased equip cost (B) 9,343 Installation Subtotal Standard Expenses 45% 420,420 Installation Total Total Direct Capital Cost, DC 1,354,687 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 93,427 Construction & field expenses 10% of purchased equip cost (B) 93,427 Contractor fees 10% of purchased equip cost (B) 93,427 Start-up 1% of purchased equip cost (B) 9,343 Performance test 1% of purchased equip cost (B) 9,343 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 28,028 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993 Total Capital Investment (TCI) = DC + IC 1,681,680 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 189 kw-hr, 3156 hr/yr, 28% utilization 8,534 Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502 Oxygen $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367 Total Annual Direct Operating Costs 55,305 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634 Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817 Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817 Capital Recovery for a 20- year equipment life and a 7% interest rate 158,739 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747 Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LoTOx #2 LoTOx 7 of 106

204 Draft BART Emission Control Cost Analysis Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 17,000 No extra load on blower Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 126 gpm No extra load on circulation pump H2O WW Disch 2 gpm No extra load on discharge pump kw-hr LoTOx Electric Use 4 kw/lb O per estimate from PCI Wedeco Total Oxygen Plant Electric Use 12,900 kw - cost accounted for in $/ton of O 2 Total 189 Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion lb/hr O2 5,311 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco Circulating Water Rate Water Makeup Rate WW Discharge (blowdown) gpm 5.8 gpm 2.2 gpm Nitrate loading (as NaNO 3 ) in scrubber water 49 lb/hr NaNO 3 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 167,342 8,534 $/kwh, 189 kw-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal gpm 6, $/mgal, 118 gpm, 3156 hr/yr, 28% utilization Oxygen $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LoTOx #2 LoTOx 8 of 106

205 Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation) Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 875,464 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689 Installation - Standard Costs 45% of purchased equip cost (B) 478,660 Total Direct Capital Cost, DC 1,542,349 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,720 Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X that has been converted to HNO 3 and N 2 O 5. This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LoTOx #4 LoTOx 9 of 106

206 Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546 MN Sales Taxes 6.5% of control device cost (A) 56,905 Freight 5% of control device cost (A) 43,773 Purchased Equipment Total (B) 22% 1,063,689 Installation Foundations & supports 12% of purchased equip cost (B) 127,643 Handling & erection (2) 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 10,637 Piping 30% of purchased equip cost (B) 319,107 Insulation 1% of purchased equip cost (B) 10,637 Painting 1% of purchased equip cost (B) 10,637 Installation Subtotal Standard Expenses 45% 478,660 Total Direct Capital Cost, DC 1,542,349 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 106,369 Construction & field expenses 10% of purchased equip cost (B) 106,369 Contractor fees 10% of purchased equip cost (B) 106,369 Start-up 1% of purchased equip cost (B) 10,637 Performance test 1% of purchased equip cost (B) 10,637 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 31,911 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 278 kw-hr, 3156 hr/yr, 28% utilization 12,535 Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737 Oxygen $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289 Total Annual Direct Operating Costs 63,463 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293 Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146 Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146 Capital Recovery for a 20- year equipment life and a 7% interest rate 180,729 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LoTOx #4 LoTOx 10 of 106

207 Draft BART Emission Control Cost Analysis Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 25,500 No extra load on blower Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 189 gpm No extra load on circulation pump H2O WW Disch 3 gpm No extra load on discharge pump kw-hr LoTOx Electric Use 4 kw/lb O per estimate from PCI Wedeco Total Oxygen Plant Electric Use 12,900 kw - cost accounted for in $/ton of O 2 Total 278 Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion lb/hr O2 7,801 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco Circulating Water Rate Water Makeup Rate WW Discharge (blowdown) gpm 8.7 gpm 3.2 gpm Nitrate loading (as NaNO 3 ) in scrubber water 71 lb/hr NaNO 3 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 245,784 12,535 $/kwh, 278 kw-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal gpm 9, $/mgal, 174 gpm, 3156 hr/yr, 28% utilization Oxygen $/ton 0.3 ton/hr ,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LoTOx #4 LoTOx 11 of 106

208 Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation) Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 875,464 Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689 Installation - Standard Costs 45% of purchased equip cost (B) 478,660 Total Direct Capital Cost, DC 1,542,349 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,713 Notes & Assumptions 1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter. Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers) 2 Handling and erection of ozone generators included in estimate from PCI Wedeco 3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project. 4 Oxygen plant site prep costs divided between all 5 lines 5 In order for LoTOx to work, a scrubber needs to be installed to capture NO X that has been converted to HNO 3 and N 2 O 5. This analysis does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs; however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LoTOx #5 LoTOx 12 of 106

209 Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464 Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546 MN Sales Taxes 6.5% of control device cost (A) 56,905 Freight 5% of control device cost (A) 43,773 Purchased Equipment Total (B) 22% 1,063,689 Installation Foundations & supports 12% of purchased equip cost (B) 127,643 Handling & erection (2) 0% of purchased equip cost (B) 0 Electrical 1% of purchased equip cost (B) 10,637 Piping 30% of purchased equip cost (B) 319,107 Insulation 1% of purchased equip cost (B) 10,637 Painting 1% of purchased equip cost (B) 10,637 Installation Subtotal Standard Expenses 45% 478,660 Total Direct Capital Cost, DC 1,542,349 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 106,369 Construction & field expenses 10% of purchased equip cost (B) 106,369 Contractor fees 10% of purchased equip cost (B) 106,369 Start-up 1% of purchased equip cost (B) 10,637 Performance test 1% of purchased equip cost (B) 10,637 Model Studies NA of purchased equip cost (B) NA Contingencies 3% of purchased equip cost (B) 31,911 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291 Total Capital Investment (TCI) = DC + IC 1,914,641 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 278 kw-hr, 3156 hr/yr, 28% utilization 12,535 Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737 Oxygen $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289 Total Annual Direct Operating Costs 63,463 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293 Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146 Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146 Capital Recovery for a 20- year equipment life and a 7% interest rate 180,729 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055 Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LoTOx #5 LoTOx 13 of 106

210 Draft BART Emission Control Cost Analysis Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Scrubber 25,500 No extra load on blower Flow Liquid SPGR P ft H2O Efficiency Hp kw Circ Pump 189 gpm No extra load on circulation pump H2O WW Disch 3 gpm No extra load on discharge pump kw-hr LoTOx Electric Use 4 kw/lb O per estimate from PCI Wedeco Total Oxygen Plant Electric Use 12,900 kw - cost accounted for in $/ton of O 2 Total 278 Reagent Use & Other Operating Costs Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC Oxygen Needed 10% wt O2 to O3 conversion lb/hr O2 7,801 scfh O2 Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco Circulating Water Rate Water Makeup Rate WW Discharge (blowdown) gpm 8.7 gpm 3.2 gpm Nitrate loading (as NaNO 3 ) in scrubber water 71 lb/hr NaNO 3 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 245,784 12,535 $/kwh, 278 kw-hr, 3156 hr/yr, 28% utilization Cooling Water 0.08 $/mgal gpm 9, $/mgal, 174 gpm, 3156 hr/yr, 28% utilization Oxygen $/ton 0.3 ton/hr ,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LoTOx #5 LoTOx 14 of 106

211 Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs ,173,722 Purchased Equipment (A) ,585,117 Purchased Equipment Total (B) SCR + Reheat 2,907,528 Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,632 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SCR #1 SCR 15 of 106

212 Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 2,585,117 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 31% Replacement Power, two weeks 796,012 Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012 Project Contingeny (C) 15% of (A + B) 507,169 Total Plant Cost (D) A + B + C 3,888,299 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 77,766 Inventory Capital Reagent Vol * $/gal 3,420 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 59,542 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 79 kw-hr, 3156 hr/yr, 28% utilization 3,565 Cat. Replacement Catalyst Replacement 2,705 Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739 Total Annual Direct Operating Costs 76,551 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 374,691 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691 Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SCR #1 SCR 16 of 106

213 Draft BART Emission Control Cost Analysis Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 24,000 hours FCW Rep part cost per unit 141 $/ft 3 # of Layers 10 Replacement Factor 8Layers replaced per year = 3.3 Amount Required 197 ft 3 Catalyst Cost 27,753 Y catalyst life factor 8 Years Annualized Cost 2,705 SCR Capital Cost per EPRI Method 2,173,722 Duty 104 MMBtu/hr Catalyst Area 50 ft f (h SCR) Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/mmbtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 1,509 ft 3 New/Retrofit R N or R Electrical Use Duty 104 MMBtu/hr kw NOx Cont Eff 80% (as faction) Power 79.1 NOx in 0.28 lb/mmbtu n catalyst layers 11 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total 79.1 Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 29 lb/hr Neat 13.5 gal/hr 29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost 101 lb/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 79.1 kw-hr 69,892 3,565 $/kwh, 79 kw-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement Ammonia (29% aqua.) $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SCR #1 SCR 17 of 106

214 Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 265,359 Purchased Equipment Total (B) 22% of control device cost (A) 322,412 Installation - Standard Costs 30% of purchased equip cost (B) 96,724 Installation - Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 Reheat for SCR #1 Reheat for SCR 18 of 106

215 Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 265,359 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 26,536 ND Sales Taxes 6.5% of control device cost (A) 17,248 Freight 5% of control device cost (A) 13,268 Purchased Equipment Total (B) 22% 322,412 Installation Foundations & supports 8% of purchased equip cost (B) 25,793 Handling & erection 14% of purchased equip cost (B) 45,138 Electrical 4% of purchased equip cost (B) 12,896 Piping 2% of purchased equip cost (B) 6,448 Insulation 1% of purchased equip cost (B) 3,224 Painting 1% of purchased equip cost (B) 3,224 Installation Subtotal Standard Expenses 30% 96,724 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 32,241 Construction & field expenses 5% of purchased equip cost (B) 16,121 Contractor fees 10% of purchased equip cost (B) 32,241 Start-up 2% of purchased equip cost (B) 6,448 Performance test 1% of purchased equip cost (B) 3,224 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 9,672 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 63 kw-hr, 3156 hr/yr, 28% utilization 2,839 Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681 Total Annual Direct Operating Costs 48,421 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191 Capital Recovery for a 20- year equipment life and a 7% interest rate 48,998 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 Reheat for SCR #1 Reheat for SCR 19 of 106

216 Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 2 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 17, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 17, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) 63.0 Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 63.0 kw-hr 55,659 2,839 $/kwh, 63 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 Reheat for SCR #1 Reheat for SCR 20 of 106

217 Draft BART Emission Control Cost Analysis Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 380 Deg F - Temperature of waste gas into heat recovery T fi 450 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 429 Deg F - Temperature of waste gas out of heat recovery T fo 401 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 11,811 scfm - Flow of waste gas Q af 16 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560 Current Cost Using CHE Plant Cost Index $265,359 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % NOx Due to Duct Burner 939 scf/hr Flow of natural gas required 1.0 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 Reheat for SCR #1 Reheat for SCR 21 of 106

218 Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs ,173,722 Purchased Equipment (A) ,585,117 Purchased Equipment Total (B) SCR + Reheat 2,907,528 Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,345 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SCR #2 SCR 22 of 106

219 Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 2,585,117 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 31% Replacement Power, two weeks 796,012 Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012 Project Contingeny (C) 15% of (A + B) 507,169 Total Plant Cost (D) A + B + C 3,888,299 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 77,766 Inventory Capital Reagent Vol * $/gal 3,420 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 59,542 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 79 kw-hr, 3156 hr/yr, 28% utilization 3,565 Cat. Replacement Catalyst Replacement 2,705 Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739 Total Annual Direct Operating Costs 76,551 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 374,691 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691 Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SCR #2 SCR 23 of 106

220 Draft BART Emission Control Cost Analysis Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 24,000 hours FCW Rep part cost per unit 141 $/ft 3 # of Layers 10 Replacement Factor 8Layers replaced per year = 3.3 Amount Required 197 ft 3 Catalyst Cost 27,753 Y catalyst life factor 8 Years Annualized Cost 2,705 SCR Capital Cost per EPRI Method 2,173,722 Duty 104 MMBtu/hr Catalyst Area 50 ft f (h SCR) Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/mmbtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 1,509 ft 3 New/Retrofit R N or R Electrical Use Duty 104 MMBtu/hr kw NOx Cont Eff 80% (as faction) Power 79.1 NOx in 0.28 lb/mmbtu n catalyst layers 11 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total 79.1 Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 29 lb/hr Neat 13.5 gal/hr 29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost 101 lb/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 79.1 kw-hr 69,892 3,565 $/kwh, 79 kw-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement Ammonia (29% aqua.) $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SCR #2 SCR 24 of 106

221 Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 265,359 Purchased Equipment Total (B) 22% of control device cost (A) 322,412 Installation - Standard Costs 30% of purchased equip cost (B) 96,724 Installation - Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 Reheat for SCR #2 Reheat for SCR 25 of 106

222 Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 265,359 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 26,536 ND Sales Taxes 6.5% of control device cost (A) 17,248 Freight 5% of control device cost (A) 13,268 Purchased Equipment Total (B) 22% 322,412 Installation Foundations & supports 8% of purchased equip cost (B) 25,793 Handling & erection 14% of purchased equip cost (B) 45,138 Electrical 4% of purchased equip cost (B) 12,896 Piping 2% of purchased equip cost (B) 6,448 Insulation 1% of purchased equip cost (B) 3,224 Painting 1% of purchased equip cost (B) 3,224 Installation Subtotal Standard Expenses 30% 96,724 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 96,724 Total Direct Capital Cost, DC 419,135 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 32,241 Construction & field expenses 5% of purchased equip cost (B) 16,121 Contractor fees 10% of purchased equip cost (B) 32,241 Start-up 2% of purchased equip cost (B) 6,448 Performance test 1% of purchased equip cost (B) 3,224 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 9,672 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948 Total Capital Investment (TCI) = DC + IC 519,083 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 63 kw-hr, 3156 hr/yr, 28% utilization 2,839 Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681 Total Annual Direct Operating Costs 48,421 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191 Capital Recovery for a 20- year equipment life and a 7% interest rate 48,998 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502 Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 Reheat for SCR #2 Reheat for SCR 26 of 106

223 Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 2 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 17, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 17, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) 63.0 Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 63.0 kw-hr 55,659 2,839 $/kwh, 63 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 Reheat for SCR #2 Reheat for SCR 27 of 106

224 Draft BART Emission Control Cost Analysis Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 380 Deg F - Temperature of waste gas into heat recovery T fi 450 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 429 Deg F - Temperature of waste gas out of heat recovery T fo 401 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 11,811 scfm - Flow of waste gas Q af 16 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560 Current Cost Using CHE Plant Cost Index $265,359 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % NOx Due to Duct Burner 939 scf/hr Flow of natural gas required 1.0 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 Reheat for SCR #2 Reheat for SCR 28 of 106

225 Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs ,667,517 Purchased Equipment (A) ,172,367 Purchased Equipment Total (B) SCR + Reheat 3,529,175 Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,028 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SCR #4 SCR 29 of 106

226 Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 3,172,367 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 25% Replacement Power, two weeks 796,012 Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012 Project Contingeny (C) 15% of (A + B) 595,257 Total Plant Cost (D) A + B + C 4,563,637 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 91,273 Inventory Capital Reagent Vol * $/gal 5,023 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 69,899 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 116 kw-hr, 3156 hr/yr, 28% utilization 5,244 Cat. Replacement Catalyst Replacement 3,979 Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773 Total Annual Direct Operating Costs 94,895 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 439,865 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865 Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SCR #4 SCR 30 of 106

227 Draft BART Emission Control Cost Analysis Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 24,000 hours FCW Rep part cost per unit 141 $/ft 3 # of Layers 10 Replacement Factor 8Layers replaced per year = 3.3 Amount Required 290 ft 3 Catalyst Cost 40,823 Y catalyst life factor 8 Years Annualized Cost 3,979 SCR Capital Cost per EPRI Method 2,667,517 Duty 153 MMBtu/hr Catalyst Area 74 ft f (h SCR) Q flue gas 70,860 acfm Rx Area f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/mmbtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 2,220 ft 3 New/Retrofit R N or R Electrical Use Duty 153 MMBtu/hr kw NOx Cont Eff 80% (as faction) Power NOx in 0.28 lb/mmbtu n catalyst layers 11 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 43 lb/hr Neat 19.8 gal/hr 29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost 148 lb/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 102,817 5,244 $/kwh, 116 kw-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement Ammonia (29% aqua.) $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SCR #4 SCR 31 of 106

228 Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 293,668 Purchased Equipment Total (B) 22% of control device cost (A) 356,807 Installation - Standard Costs 30% of purchased equip cost (B) 107,042 Installation - Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 Reheat for SCR #4 Reheat for SCR 32 of 106

229 Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 293,668 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 29,367 ND Sales Taxes 6.5% of control device cost (A) 19,088 Freight 5% of control device cost (A) 14,683 Purchased Equipment Total (B) 22% 356,807 Installation Foundations & supports 8% of purchased equip cost (B) 28,545 Handling & erection 14% of purchased equip cost (B) 49,953 Electrical 4% of purchased equip cost (B) 14,272 Piping 2% of purchased equip cost (B) 7,136 Insulation 1% of purchased equip cost (B) 3,568 Painting 1% of purchased equip cost (B) 3,568 Installation Subtotal Standard Expenses 30% 107,042 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 35,681 Construction & field expenses 5% of purchased equip cost (B) 17,840 Contractor fees 10% of purchased equip cost (B) 35,681 Start-up 2% of purchased equip cost (B) 7,136 Performance test 1% of purchased equip cost (B) 3,568 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 10,704 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 94 kw-hr, 3156 hr/yr, 28% utilization 4,258 Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521 Total Annual Direct Operating Costs 53,680 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745 Capital Recovery for a 20- year equipment life and a 7% interest rate 54,225 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 Reheat for SCR #4 Reheat for SCR 33 of 106

230 Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 2 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 25, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 25, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) 94.5 Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 94.5 kw-hr 83,488 4,258 $/kwh, 94 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 Reheat for SCR #4 Reheat for SCR 34 of 106

231 Draft BART Emission Control Cost Analysis Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 380 Deg F - Temperature of waste gas into heat recovery T fi 450 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 429 Deg F - Temperature of waste gas out of heat recovery T fo 401 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 17,716 scfm - Flow of waste gas Q af 23 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303 Current Cost Using CHE Plant Cost Index $293,668 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % NOx Due to Duct Burner 1,408 scf/hr Flow of natural gas required 1.5 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 Reheat for SCR #4 Reheat for SCR 35 of 106

232 Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Year Direct Capital Costs ,667,517 Purchased Equipment (A) ,172,367 Purchased Equipment Total (B) SCR + Reheat 3,529,175 Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809 Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384 Emission Control Cost Calculation Max Emis Annual Control Eff ontrolled Emi Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,211 Notes & Assumptions 1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SCR #5 SCR 36 of 106

233 Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367 Instrumentation 0% of control device cost (A) NA ND Sales Taxes 0.0% of control device cost (A) NA Freight 0% of control device cost (A) NA Purchased Equipment Total (A) 0% 3,172,367 Indirect Installation General Facilities 0% of purchased equip cost (A) 0 Engineering & Home Office 0% of purchased equip cost (A) 0 Process Contingency 0% of purchased equip cost (A) 0 Site Specific-Other 25% Replacement Power, two weeks 796,012 Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012 Project Contingeny (C) 15% of (A + B) 595,257 Total Plant Cost (D) A + B + C 4,563,637 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 91,273 Inventory Capital Reagent Vol * $/gal 5,023 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 69,899 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 116 kw-hr, 3156 hr/yr, 28% utilization 5,244 Cat. Replacement Catalyst Replacement 3,979 Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773 Total Annual Direct Operating Costs 94,895 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 439,865 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865 Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SCR #5 SCR 37 of 106

234 Draft BART Emission Control Cost Analysis Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 24,000 hours FCW Rep part cost per unit 141 $/ft 3 # of Layers 10 Replacement Factor 8Layers replaced per year = 3.3 Amount Required 290 ft 3 Catalyst Cost 40,823 Y catalyst life factor 8 Years Annualized Cost 3,979 SCR Capital Cost per EPRI Method 2,667,517 Duty 153 MMBtu/hr Catalyst Area 74 ft f (h SCR) Q flue gas 70,860 acfm Rx Area f (h NH 3 ) NOx Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0 NOx in 0.28 lb/mmbtu n layer 10 layers Y Bypass? Y or N Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass) Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst) Temperature 380 Deg F h SCR 81 ft f (h SCR) Catalyst Volume 2,220 ft 3 New/Retrofit R N or R Electrical Use Duty 153 MMBtu/hr kw NOx Cont Eff 80% (as faction) Power NOx in 0.28 lb/mmbtu n catalyst layers 11 layers Press drop catalyst 1 in H 2 O per layer Press drop duct 3 in H 2 O Total Reagent Use & Other Operating Costs Ammonia Use 56.0 lb/ft 3 Density 43 lb/hr Neat 19.8 gal/hr 29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost 148 lb/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh kw-hr 102,817 5,244 $/kwh, 116 kw-hr, 3156 hr/yr, 28% utilization Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement Ammonia (29% aqua.) $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SCR #5 SCR 38 of 106

235 Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 293,668 Purchased Equipment Total (B) 22% of control device cost (A) 356,807 Installation - Standard Costs 30% of purchased equip cost (B) 107,042 Installation - Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625 Notes & Assumptions 1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 Reheat for SCR #5 Reheat for SCR 39 of 106

236 Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 293,668 Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC Instrumentation 10% of control device cost (A) 29,367 ND Sales Taxes 6.5% of control device cost (A) 19,088 Freight 5% of control device cost (A) 14,683 Purchased Equipment Total (B) 22% 356,807 Installation Foundations & supports 8% of purchased equip cost (B) 28,545 Handling & erection 14% of purchased equip cost (B) 49,953 Electrical 4% of purchased equip cost (B) 14,272 Piping 2% of purchased equip cost (B) 7,136 Insulation 1% of purchased equip cost (B) 3,568 Painting 1% of purchased equip cost (B) 3,568 Installation Subtotal Standard Expenses 30% 107,042 Site Preparation, as required Site Specific NA Buildings, as required Site Specific NA Site Specific - Other Site Specific NA Total Site Specific Costs NA Installation Total 107,042 Total Direct Capital Cost, DC 463,849 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 35,681 Construction & field expenses 5% of purchased equip cost (B) 17,840 Contractor fees 10% of purchased equip cost (B) 35,681 Start-up 2% of purchased equip cost (B) 7,136 Performance test 1% of purchased equip cost (B) 3,568 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 10,704 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610 Total Capital Investment (TCI) = DC + IC 574,460 Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Supervisor 15% 15% of Operator Costs 1,805 Maintenance Maintenance Labor $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032 Maintenance Materials 100% of maintenance labor costs 12,032 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 94 kw-hr, 3156 hr/yr, 28% utilization 4,258 Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521 Total Annual Direct Operating Costs 53,680 Indirect Operating Costs Overhead 60% of total labor and material costs 22,741 Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489 Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745 Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745 Capital Recovery for a 20- year equipment life and a 7% interest rate 54,225 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944 Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 Reheat for SCR #5 Reheat for SCR 40 of 106

237 Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catalyst: Catalyst Equipment Life 2 years CRF 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 Annualized Cost 0 0 Zero out if no replacement parts needed Replacement Parts & Equipment: Equipment Life 3 CRF Rep part cost per unit 0 $ each Amount Required 0 Number Total Rep Parts Cost 0 Cost adjusted for freight & sales tax Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5-20 min per bag. Total Installed Cost 0 Zero out if no replacement parts needed Annualized Cost 0 Electrical Use Flow acfm P in H2O Efficiency Hp kw Blower, Thermal 25, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Blower, Catalytic 25, EPA Cost Cont Manual 6th ed - Oxidizders Chapter Oxidizer Type thermal (catalytic or thermal) 94.5 Reagent Use & Other Operating Costs Oxidizers - NA Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 1,805 15% of Operator Costs Maintenance Maint Labor $/Hr 0.5 hr/8 hr shift ,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA 12, % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 94.5 kw-hr 83,488 4,258 $/kwh, 94 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 Reheat for SCR #5 Reheat for SCR 41 of 106

238 Draft BART Emission Control Cost Analysis Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer) Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery Auxiliary Fuel Use Equation 3.19 T wi 380 Deg F - Temperature of waste gas into heat recovery T fi 450 Deg F - Temperature of Flue gas into of heat recovery T ref FER 77 Deg F - Reference temperature for fuel combustion calculations 70% Factional Heat Recovery % Heat recovery section efficiency T wo 429 Deg F - Temperature of waste gas out of heat recovery T fo 401 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg p wg p af Q wg Btu/lb - Deg F Heat Capacity of waste gas (air) lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F 17,716 scfm - Flow of waste gas Q af 23 scfm - Flow of auxiliary fuel Year 2005 Inflation Rate 3.0% Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303 Current Cost Using CHE Plant Cost Index $293,668 Heat Rec % A B 0 10, Exponents per equation , Exponents per equation , Exponents per equation , 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 % % mw H2O 10 v % % mw N2 60 v % % mw O2 15 v % % Cp Flue Gas 100 v % % NOx Due to Duct Burner 1,408 scf/hr Flow of natural gas required 1.5 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 Reheat for SCR #5 Reheat for SCR 42 of 106

239 Draft BART Emission Control Cost Analysis Table A.12.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 442,265 Purchased Equipment Total (B) 22% of control device cost (A) 537,352 Installation - Standard Costs 30% of purchased equip cost (B) 161,206 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 1,384,220 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,558 Notes & Assumptions 1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB FGR 1/8/2008 Page 43 of 106

240 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 442,265 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 44,227 MN Sales Taxes 6.5% of control device cost (A) 28,747 Freight 5% of control device cost (A) 22,113 Purchased Equipment Total (B) 22% 537,352 Installation Foundations & supports 8% of purchased equip cost (B) 42,988 Handling & erection 14% of purchased equip cost (B) 75,229 Electrical 4% of purchased equip cost (B) 21,494 Piping 2% of purchased equip cost (B) 10,747 Insulation 1% of purchased equip cost (B) 5,374 Painting 1% of purchased equip cost (B) 5,374 Installation Subtotal Standard Expenses 30% 161,206 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 53,735 Construction & field expenses 5% of purchased equip cost (B) 26,868 Contractor fees 10% of purchased equip cost (B) 53,735 Start-up 2% of purchased equip cost (B) 10,747 Performance test 1% of purchased equip cost (B) 5,374 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,121 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 865,137 Retrofit Factor (3) 60% of TCI 519,082 TCI Retrofit Installed 1,384,220 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kw-hr, hr/yr, 0% utilization 81 Total Annual Direct Operating Costs 840 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651 Capital Recovery for a 20- year equipment life and a 7% interest rate 130,661 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB FGR 1/8/2008 Page 44 of 106

241 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 5% of flue gas is recirculated) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 1.8 kw-hr 1, $/kwh, 2 kw-hr, hr/yr, 0% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB FGR 1/8/2008 Page 45 of 106

242 Draft BART Emission Control Cost Analysis Table A.12.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 442,265 Purchased Equipment Total (B) 22% of control device cost (A) 537,352 Installation - Standard Costs 30% of purchased equip cost (B) 161,206 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 1,384,220 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,098 Notes & Assumptions 1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB FGR 1/8/2008 Page 46 of 106

243 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 442,265 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 44,227 MN Sales Taxes 6.5% of control device cost (A) 28,747 Freight 5% of control device cost (A) 22,113 Purchased Equipment Total (B) 22% 537,352 Installation Foundations & supports 8% of purchased equip cost (B) 42,988 Handling & erection 14% of purchased equip cost (B) 75,229 Electrical 4% of purchased equip cost (B) 21,494 Piping 2% of purchased equip cost (B) 10,747 Insulation 1% of purchased equip cost (B) 5,374 Painting 1% of purchased equip cost (B) 5,374 Installation Subtotal Standard Expenses 30% 161,206 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 698,558 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 53,735 Construction & field expenses 5% of purchased equip cost (B) 26,868 Contractor fees 10% of purchased equip cost (B) 53,735 Start-up 2% of purchased equip cost (B) 10,747 Performance test 1% of purchased equip cost (B) 5,374 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,121 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579 Total Capital Investment (TCI) = DC + IC 865,137 Retrofit Factor (3) 60% of TCI 519,082 TCI Retrofit Installed 1,384,220 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kw-hr, hr/yr, 0% utilization 81 Total Annual Direct Operating Costs 840 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651 Capital Recovery for a 20- year equipment life and a 7% interest rate 130,661 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721 Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB FGR 1/8/2008 Page 47 of 106

244 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 5% of flue gas is recirculated) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 1.8 kw-hr 1, $/kwh, 2 kw-hr, hr/yr, 0% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB FGR 1/8/2008 Page 48 of 106

245 Draft BART Emission Control Cost Analysis Table A.12.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 557,542 Purchased Equipment Total (B) 22% of control device cost (A) 677,414 Installation - Standard Costs 30% of purchased equip cost (B) 203,224 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,745,018 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,839 Notes & Assumptions 1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB FGR 1/8/2008 Page 49 of 106

246 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 557,542 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,754 MN Sales Taxes 6.5% of control device cost (A) 36,240 Freight 5% of control device cost (A) 27,877 Purchased Equipment Total (B) 22% 677,414 Installation Foundations & supports 8% of purchased equip cost (B) 54,193 Handling & erection 14% of purchased equip cost (B) 94,838 Electrical 4% of purchased equip cost (B) 27,097 Piping 2% of purchased equip cost (B) 13,548 Insulation 1% of purchased equip cost (B) 6,774 Painting 1% of purchased equip cost (B) 6,774 Installation Subtotal Standard Expenses 30% 203,224 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 67,741 Construction & field expenses 5% of purchased equip cost (B) 33,871 Contractor fees 10% of purchased equip cost (B) 67,741 Start-up 2% of purchased equip cost (B) 13,548 Performance test 1% of purchased equip cost (B) 6,774 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 20,322 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,090,636 Retrofit Factor (3) 60% of TCI 654,382 TCI Retrofit Installed 1,745,018 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kw-hr, hr/yr, 0% utilization 122 Total Annual Direct Operating Costs 880 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906 Capital Recovery for a 20- year equipment life and a 7% interest rate 164,717 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB FGR 1/8/2008 Page 50 of 106

247 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 1, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 5% of flue gas is recirculated) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.7 kw-hr 2, $/kwh, 3 kw-hr, hr/yr, 0% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB FGR 1/8/2008 Page 51 of 106

248 Draft BART Emission Control Cost Analysis Table A.12.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 557,542 Purchased Equipment Total (B) 22% of control device cost (A) 677,414 Installation - Standard Costs 30% of purchased equip cost (B) 203,224 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,745,018 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,299 Notes & Assumptions 1 Purchased equipment cost based on estimate from Coen Burner. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB FGR 1/8/2008 Page 52 of 106

249 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 557,542 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 55,754 MN Sales Taxes 6.5% of control device cost (A) 36,240 Freight 5% of control device cost (A) 27,877 Purchased Equipment Total (B) 22% 677,414 Installation Foundations & supports 8% of purchased equip cost (B) 54,193 Handling & erection 14% of purchased equip cost (B) 94,838 Electrical 4% of purchased equip cost (B) 27,097 Piping 2% of purchased equip cost (B) 13,548 Insulation 1% of purchased equip cost (B) 6,774 Painting 1% of purchased equip cost (B) 6,774 Installation Subtotal Standard Expenses 30% 203,224 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 880,638 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 67,741 Construction & field expenses 5% of purchased equip cost (B) 33,871 Contractor fees 10% of purchased equip cost (B) 67,741 Start-up 2% of purchased equip cost (B) 13,548 Performance test 1% of purchased equip cost (B) 6,774 Model Studies of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 20,322 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998 Total Capital Investment (TCI) = DC + IC 1,090,636 Retrofit Factor (3) 60% of TCI 654,382 TCI Retrofit Installed 1,745,018 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kw-hr, hr/yr, 0% utilization 122 Total Annual Direct Operating Costs 880 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813 Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906 Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906 Capital Recovery for a 20- year equipment life and a 7% interest rate 164,717 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798 Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB FGR 1/8/2008 Page 53 of 106

250 Draft BART Emission Control Cost Analysis Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 1, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 5% of flue gas is recirculated) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.7 kw-hr 2, $/kwh, 3 kw-hr, hr/yr, 0% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB FGR 1/8/2008 Page 54 of 106

251 Draft BART Emission Control Cost Analysis Table A.13.a: NO x Control - Regenerative Selective Catalytic Reduction Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,201,308 Total Direct Capital Cost, DC 1,201,308 Total Capital Investment (TCI) = DC + IC 1,690,961 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,879 Notes & Assumptions 1 Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #1 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 55 of 106

252 Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction CAPITAL COSTS 2 Direct Capital Costs Purchased Equipment 1 (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,201,308 Indirect Installation General Facilities 5% of purchased equip cost (A) 60,065 Engineerin & Home Office 10% of purchased equip cost (A) 120,131 Process Contingency 5% of purchased equip cost (A) 60,065 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262 Project Contingeny (C) 15% of (A + B) 216,235 Total Plant Cost (D) A + B + C 1,657,804 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 33,156 Inventory Capital Reagent Vol * $/gal 0 Intial Catalyst and Chemicals 0 for SCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961 OPERATING COSTS 2 Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 25,364 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 51 kw-hr, 3156 hr/yr, 28% utilization 2,321 Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933 Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25 Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204 Total Annual Direct Operating Costs 79,021 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 159,615 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #1 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 56 of 106

253 Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 3 Years CRF Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total cost 87,139 Annualized Cost 33,204 Electrical Use Power consumed 51 kwhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total 51.5 Reagent Use & Other Operating Costs Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 51.5 kw-hr 45,502 2,321 $/kwh, 51 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 4.8 scfm $/kscf, 5 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 0 ft ,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #1 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 57 of 106

254 Draft BART Emission Control Cost Analysis Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction Duct Burner Fuel Usage Estimate Auxiliary Fuel Use Equation 3.19 Input Numbers T wi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency T wo 713 Deg F - Temperature of waste gas out of heat recovery T fo 417 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg Btu/lb - Deg F Heat Capacity of waste gas (moist air) p wg lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F p af Q wg 11,811 scfm - Flow of waste gas Q af 28 scfm - Flow of auxiliary fuel NOx Due to Duct Burner 1,703 scf/hr Flow of natural gas required 1.8 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.6 tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #1 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 58 of 106

255 Draft BART Emission Control Cost Analysis Table A.13.b: NO x Control - Regenerative Selective Catalytic Reduction Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,201,308 Total Direct Capital Cost, DC 1,201,308 Total Capital Investment (TCI) = DC + IC 1,690,961 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,638 Notes & Assumptions 1 Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #2 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 59 of 106

256 Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction CAPITAL COSTS 2 Direct Capital Costs Purchased Equipment 1 (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,201,308 Indirect Installation General Facilities 5% of purchased equip cost (A) 60,065 Engineerin & Home Office 10% of purchased equip cost (A) 120,131 Process Contingency 5% of purchased equip cost (A) 60,065 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262 Project Contingeny (C) 15% of (A + B) 216,235 Total Plant Cost (D) A + B + C 1,657,804 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 33,156 Inventory Capital Reagent Vol * $/gal 0 Intial Catalyst and Chemicals 0 for SCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961 OPERATING COSTS 2 Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 25,364 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 51 kw-hr, 3156 hr/yr, 28% utilization 2,321 Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933 Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25 Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204 Total Annual Direct Operating Costs 79,021 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 159,615 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615 Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #2 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 60 of 106

257 Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 3 Years CRF Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total cost 87,139 Annualized Cost 33,204 Electrical Use Power consumed 51 kwhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total 51.5 Reagent Use & Other Operating Costs Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 51.5 kw-hr 45,502 2,321 $/kwh, 51 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 4.8 scfm $/kscf, 5 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 0 ft ,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #2 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 61 of 106

258 Draft BART Emission Control Cost Analysis Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction Duct Burner Fuel Usage Estimate Auxiliary Fuel Use Equation 3.19 Input Numbers T wi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency T wo 713 Deg F - Temperature of waste gas out of heat recovery T fo 417 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg Btu/lb - Deg F Heat Capacity of waste gas (moist air) p wg lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F p af Q wg 11,811 scfm - Flow of waste gas Q af 28 scfm - Flow of auxiliary fuel NOx Due to Duct Burner 1,703 scf/hr Flow of natural gas required 1.8 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.1 lb/hr Additional NOx from duct burners 0.6 tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #2 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 62 of 106

259 Draft BART Emission Control Cost Analysis Table A.13.c: NO x Control - Regenerative Selective Catalytic Reduction Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,532,177 Total Direct Capital Cost, DC 1,532,177 Total Capital Investment (TCI) = DC + IC 2,156,692 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,633 Notes & Assumptions 1 Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #4 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 63 of 106

260 Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction CAPITAL COSTS 2 Direct Capital Costs Purchased Equipment 1 (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,532,177 Indirect Installation General Facilities 5% of purchased equip cost (A) 76,609 Engineerin & Home Office 10% of purchased equip cost (A) 153,218 Process Contingency 5% of purchased equip cost (A) 76,609 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435 Project Contingeny (C) 15% of (A + B) 275,792 Total Plant Cost (D) A + B + C 2,114,404 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 42,288 Inventory Capital Reagent Vol * $/gal 0 Intial Catalyst and Chemicals 0 for SCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692 OPERATING COSTS 2 Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 32,350 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 77 kw-hr, 3156 hr/yr, 28% utilization 3,481 Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899 Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38 Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807 Total Annual Direct Operating Costs 112,705 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 203,577 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #4 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 64 of 106

261 Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 3 Years CRF Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total cost 130,708 Annualized Cost 49,807 Electrical Use Power consumed 77 kwhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total 77.2 Reagent Use & Other Operating Costs Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 77.2 kw-hr 68,253 3,481 $/kwh, 77 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 7.1 scfm $/kscf, 7 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 0 ft ,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #4 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 65 of 106

262 Draft BART Emission Control Cost Analysis Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction Duct Burner Fuel Usage Estimate Auxiliary Fuel Use Equation 3.19 Input Numbers T wi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency T wo 713 Deg F - Temperature of waste gas out of heat recovery T fo 417 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg Btu/lb - Deg F Heat Capacity of waste gas (moist air) p wg lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F p af Q wg 17,716 scfm - Flow of waste gas Q af 43 scfm - Flow of auxiliary fuel NOx Due to Duct Burner 2,555 scf/hr Flow of natural gas required 2.7 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.2 lb/hr Additional NOx from duct burners 0.9 tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #4 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 66 of 106

263 Draft BART Emission Control Cost Analysis Table A.13.d: NO x Control - Regenerative Selective Catalytic Reduction Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 1,532,177 Total Direct Capital Cost, DC 1,532,177 Total Capital Investment (TCI) = DC + IC 2,156,692 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,710 Notes & Assumptions 1 Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective. P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #5 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 67 of 106

264 Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction CAPITAL COSTS 2 Direct Capital Costs Purchased Equipment 1 (A) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 1,532,177 Indirect Installation General Facilities 5% of purchased equip cost (A) 76,609 Engineerin & Home Office 10% of purchased equip cost (A) 153,218 Process Contingency 5% of purchased equip cost (A) 76,609 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435 Project Contingeny (C) 15% of (A + B) 275,792 Total Plant Cost (D) A + B + C 2,114,404 Allowance for Funds During Construction (E) 0 for SCR 0 Royalty Allowance (F) 0 for SCR 0 Pre Production Costs (G) 2% of (D+E)) 42,288 Inventory Capital Reagent Vol * $/gal 0 Intial Catalyst and Chemicals 0 for SCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692 OPERATING COSTS 2 Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total 1.50 % of Total Capital Investment 32,350 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 77 kw-hr, 3156 hr/yr, 28% utilization 3,481 Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899 Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38 Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130 SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807 Total Annual Direct Operating Costs 112,705 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 203,577 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577 Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #5 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 68 of 106

265 Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Replacement Catayst Equipment Life 3 Years CRF Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total cost 130,708 Annualized Cost 49,807 Electrical Use Power consumed 77 kwhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Total 77.2 Reagent Use & Other Operating Costs Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5 Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate. Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators Auxiliary Fuel Use Equation 3.19 Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh 77.2 kw-hr 68,253 3,481 $/kwh, 77 kw-hr, 3156 hr/yr, 28% utilization Natural Gas 9.26 $/mscf scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization Comp Air 0.32 $/kscf 7.1 scfm $/kscf, 7 scfm, 3156 hr/yr, 28% utilization Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization SCR Catalyst 0.00 $/ft 3 0 ft ,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #5 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 69 of 106

266 Draft BART Emission Control Cost Analysis Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction Duct Burner Fuel Usage Estimate Auxiliary Fuel Use Equation 3.19 Input Numbers T wi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers 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 90% Factional Heat Recovery % Heat recovery section efficiency T wo 713 Deg F - Temperature of waste gas out of heat recovery T fo 417 Deg F - Temperature of flue gas into of heat recovery -h caf Btu/lb Heat of combustion auxiliary fuel (methane) -h wg 0 Btu/lb Heat of combustion waste gas C p wg Btu/lb - Deg F Heat Capacity of waste gas (moist air) p wg lb/scf - Density of waste gas (air) at 77 Deg F lb/scf - Density of auxiliary fuel (methane) at 77 Deg F p af Q wg 17,716 scfm - Flow of waste gas Q af 43 scfm - Flow of auxiliary fuel NOx Due to Duct Burner 2,555 scf/hr Flow of natural gas required 2.7 mmbtu/hr Heat required, assuming 1050 btu/scf 0.08 lb/mmbtu NOx emission factor for natural gas combustion 0.2 lb/hr Additional NOx from duct burners 0.9 tpy Additional NOx from duct burners Reference: OAQPS Control Cost Manual 5th Ed Feb Chapter 3 Thermal & Catalytic Incinerators (EPA 453/B ) P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility #5 R-SCR Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART Page 70 of 106

267 Draft BART Emission Control Cost Analysis Table A.14.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 361,408 Purchased Equipment Total (B) 22% of control device cost (A) 439,111 Installation - Standard Costs 30% of purchased equip cost (B) 131,733 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 1,131,149 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,282 Notes & Assumptions 1 Price based on installation of LNB with OFA in a similar application 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB OFA 1/8/2008 Page 71 of 106

268 Draft BART Emission Control Cost Analysis Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 361,408 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 36,141 MN Sales Taxes 6.5% of control device cost (A) 23,492 Freight 5% of control device cost (A) 18,070 Purchased Equipment Total (B) 22% 439,111 Installation Foundations & supports 8% of purchased equip cost (B) 35,129 Handling & erection 14% of purchased equip cost (B) 61,476 Electrical 4% of purchased equip cost (B) 17,564 Piping 2% of purchased equip cost (B) 8,782 Insulation 1% of purchased equip cost (B) 4,391 Painting 1% of purchased equip cost (B) 4,391 Installation Subtotal Standard Expenses 30% 131,733 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 43,911 Construction & field expenses 5% of purchased equip cost (B) 21,956 Contractor fees 10% of purchased equip cost (B) 43,911 Start-up 2% of purchased equip cost (B) 8,782 Performance test 1% of purchased equip cost (B) 4,391 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 13,173 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 706,968 Retrofit Factor (3) 60% of TCI 424,181 TCI Retrofit Installed 1,131,149 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 7.2 kw-hr, 3156 hr/yr 326 Total Annual Direct Operating Costs 1,084 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070 Capital Recovery for a 20- year equipment life and a 7% interest rate 106,773 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB OFA 1/8/2008 Page 72 of 106

269 Draft BART Emission Control Cost Analysis Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 3, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 20% of flue gas used for OFA) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 7.2 kw-hr 6, $/kwh, 7.2 kw-hr, 3156 hr/yr See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB OFA 1/8/2008 Page 73 of 106

270 Draft BART Emission Control Cost Analysis Table A.14.b: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 361,408 Purchased Equipment Total (B) 22% of control device cost (A) 439,111 Installation - Standard Costs 30% of purchased equip cost (B) 131,733 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 1,131,149 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,778 Notes & Assumptions 1 Price based on installation of LNB with OFA in a similar application 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB OFA 1/8/2008 Page 74 of 106

271 Draft BART Emission Control Cost Analysis Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 361,408 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 36,141 MN Sales Taxes 6.5% of control device cost (A) 23,492 Freight 5% of control device cost (A) 18,070 Purchased Equipment Total (B) 22% 439,111 Installation Foundations & supports 8% of purchased equip cost (B) 35,129 Handling & erection 14% of purchased equip cost (B) 61,476 Electrical 4% of purchased equip cost (B) 17,564 Piping 2% of purchased equip cost (B) 8,782 Insulation 1% of purchased equip cost (B) 4,391 Painting 1% of purchased equip cost (B) 4,391 Installation Subtotal Standard Expenses 30% 131,733 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 570,844 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 43,911 Construction & field expenses 5% of purchased equip cost (B) 21,956 Contractor fees 10% of purchased equip cost (B) 43,911 Start-up 2% of purchased equip cost (B) 8,782 Performance test 1% of purchased equip cost (B) 4,391 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 13,173 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124 Total Capital Investment (TCI) = DC + IC 706,968 Retrofit Factor (3) 60% of TCI 424,181 TCI Retrofit Installed 1,131,149 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 7.2 kw-hr, 3156 hr/yr 326 Total Annual Direct Operating Costs 1,084 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139 Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070 Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070 Capital Recovery for a 20- year equipment life and a 7% interest rate 106,773 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506 Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB OFA 1/8/2008 Page 75 of 106

272 Draft BART Emission Control Cost Analysis Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 3, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 20% of flue gas used for OFA) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 7.2 kw-hr 6, $/kwh, 7.2 kw-hr, 3156 hr/yr See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB OFA 1/8/2008 Page 76 of 106

273 Draft BART Emission Control Cost Analysis Table A.14.c: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 455,609 Purchased Equipment Total (B) 22% of control device cost (A) 553,565 Installation - Standard Costs 30% of purchased equip cost (B) 166,070 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 1,425,985 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,294 Notes & Assumptions 1 Price based on installation of LNB with OFA in a similar application 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB OFA 1/8/2008 Page 77 of 106

274 Draft BART Emission Control Cost Analysis Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 455,609 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 45,561 MN Sales Taxes 6.5% of control device cost (A) 29,615 Freight 5% of control device cost (A) 22,780 Purchased Equipment Total (B) 22% 553,565 Installation Foundations & supports 8% of purchased equip cost (B) 44,285 Handling & erection 14% of purchased equip cost (B) 77,499 Electrical 4% of purchased equip cost (B) 22,143 Piping 2% of purchased equip cost (B) 11,071 Insulation 1% of purchased equip cost (B) 5,536 Painting 1% of purchased equip cost (B) 5,536 Installation Subtotal Standard Expenses 30% 166,070 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 55,357 Construction & field expenses 5% of purchased equip cost (B) 27,678 Contractor fees 10% of purchased equip cost (B) 55,357 Start-up 2% of purchased equip cost (B) 11,071 Performance test 1% of purchased equip cost (B) 5,536 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,607 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 891,240 Retrofit Factor (3) 60% of TCI 534,744 TCI Retrofit Installed 1,425,985 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 10.8 kw-hr, 3156 hr/yr 489 Total Annual Direct Operating Costs 1,247 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912 Capital Recovery for a 20- year equipment life and a 7% interest rate 134,603 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB OFA 1/8/2008 Page 78 of 106

275 Draft BART Emission Control Cost Analysis Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 5, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 20% of flue gas used for OFA) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 10.8 kw-hr 9, $/kwh, 10.8 kw-hr, 3156 hr/yr See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB OFA 1/8/2008 Page 79 of 106

276 Draft BART Emission Control Cost Analysis Table A.14.d: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 455,609 Purchased Equipment Total (B) 22% of control device cost (A) 553,565 Installation - Standard Costs 30% of purchased equip cost (B) 166,070 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 1,425,985 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,634 Notes & Assumptions 1 Price based on installation of LNB with OFA in a similar application. 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost 3 CUECost Workbook Version 1.0, USEPA Document Page 2 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB OFA 1/8/2008 Page 80 of 106

277 Draft BART Emission Control Cost Analysis Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 455,609 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 45,561 MN Sales Taxes 6.5% of control device cost (A) 29,615 Freight 5% of control device cost (A) 22,780 Purchased Equipment Total (B) 22% 553,565 Installation Foundations & supports 8% of purchased equip cost (B) 44,285 Handling & erection 14% of purchased equip cost (B) 77,499 Electrical 4% of purchased equip cost (B) 22,143 Piping 2% of purchased equip cost (B) 11,071 Insulation 1% of purchased equip cost (B) 5,536 Painting 1% of purchased equip cost (B) 5,536 Installation Subtotal Standard Expenses 30% 166,070 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 719,635 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 55,357 Construction & field expenses 5% of purchased equip cost (B) 27,678 Contractor fees 10% of purchased equip cost (B) 55,357 Start-up 2% of purchased equip cost (B) 11,071 Performance test 1% of purchased equip cost (B) 5,536 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 16,607 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605 Total Capital Investment (TCI) = DC + IC 891,240 Retrofit Factor (3) 60% of TCI 534,744 TCI Retrofit Installed 1,425,985 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 10.8 kw-hr, 3156 hr/yr 489 Total Annual Direct Operating Costs 1,247 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825 Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912 Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912 Capital Recovery for a 20- year equipment life and a 7% interest rate 134,603 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707 Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB OFA 1/8/2008 Page 81 of 106

278 Draft BART Emission Control Cost Analysis Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use Flow acfm P in H2O Efficiency Hp kw Fan motor 5, EPA Cost Cont Manual 6th ed - Oxidizders Chapter (assume 20% of flue gas used for OFA) Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 10.8 kw-hr 9, $/kwh, 10.8 kw-hr, 3156 hr/yr See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB OFA 1/8/2008 Page 82 of 106

279 Draft BART Emission Control Cost Analysis Table A.15.a: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 175,993 Purchased Equipment Total (B) 22% of control device cost (A) 213,832 Installation - Standard Costs 30% of purchased equip cost (B) 64,150 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,653 Notes & Assumptions 1 Equipment cost based on estimate from John Zink 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB 1/8/2008 Page 83 of 106

280 Draft BART Emission Control Cost Analysis Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 175,993 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 17,599 MN Sales Taxes 6.5% of control device cost (A) 11,440 Freight 5% of control device cost (A) 8,800 Purchased Equipment Total (B) 22% 213,832 Installation Foundations & supports 8% of purchased equip cost (B) 17,107 Handling & erection 14% of purchased equip cost (B) 29,936 Electrical 4% of purchased equip cost (B) 8,553 Piping 2% of purchased equip cost (B) 4,277 Insulation 1% of purchased equip cost (B) 2,138 Painting 1% of purchased equip cost (B) 2,138 Installation Subtotal Standard Expenses 30% 64,150 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 21,383 Construction & field expenses 5% of purchased equip cost (B) 10,692 Contractor fees 10% of purchased equip cost (B) 21,383 Start-up 2% of purchased equip cost (B) 4,277 Performance test 1% of purchased equip cost (B) 2,138 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,415 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Total Annual Direct Operating Costs 758 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443 Capital Recovery for a 20- year equipment life and a 7% interest rate 32,497 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB 1/8/2008 Page 84 of 106

281 Draft BART Emission Control Cost Analysis Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 LNB 1/8/2008 Page 85 of 106

282 Draft BART Emission Control Cost Analysis Table A.15.b: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 175,993 Purchased Equipment Total (B) 22% of control device cost (A) 213,832 Installation - Standard Costs 30% of purchased equip cost (B) 64,150 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,883 Notes & Assumptions 1 Equipment cost based on estimate from John Zink 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB 1/8/2008 Page 86 of 106

283 Draft BART Emission Control Cost Analysis Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 175,993 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 17,599 MN Sales Taxes 6.5% of control device cost (A) 11,440 Freight 5% of control device cost (A) 8,800 Purchased Equipment Total (B) 22% 213,832 Installation Foundations & supports 8% of purchased equip cost (B) 17,107 Handling & erection 14% of purchased equip cost (B) 29,936 Electrical 4% of purchased equip cost (B) 8,553 Piping 2% of purchased equip cost (B) 4,277 Insulation 1% of purchased equip cost (B) 2,138 Painting 1% of purchased equip cost (B) 2,138 Installation Subtotal Standard Expenses 30% 64,150 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 277,981 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 21,383 Construction & field expenses 5% of purchased equip cost (B) 10,692 Contractor fees 10% of purchased equip cost (B) 21,383 Start-up 2% of purchased equip cost (B) 4,277 Performance test 1% of purchased equip cost (B) 2,138 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 6,415 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288 Total Capital Investment (TCI) = DC + IC 344,269 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Total Annual Direct Operating Costs 758 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885 Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443 Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443 Capital Recovery for a 20- year equipment life and a 7% interest rate 32,497 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722 Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB 1/8/2008 Page 87 of 106

284 Draft BART Emission Control Cost Analysis Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 LNB 1/8/2008 Page 88 of 106

285 Draft BART Emission Control Cost Analysis Table A.15.c: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 221,866 Purchased Equipment Total (B) 22% of control device cost (A) 269,567 Installation - Standard Costs 30% of purchased equip cost (B) 80,870 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,024 Notes & Assumptions 1 Equipment cost based on estimate from John Zink 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB 1/8/2008 Page 89 of 106

286 Draft BART Emission Control Cost Analysis Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 221,866 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 22,187 MN Sales Taxes 6.5% of control device cost (A) 14,421 Freight 5% of control device cost (A) 11,093 Purchased Equipment Total (B) 22% 269,567 Installation Foundations & supports 8% of purchased equip cost (B) 21,565 Handling & erection 14% of purchased equip cost (B) 37,739 Electrical 4% of purchased equip cost (B) 10,783 Piping 2% of purchased equip cost (B) 5,391 Insulation 1% of purchased equip cost (B) 2,696 Painting 1% of purchased equip cost (B) 2,696 Installation Subtotal Standard Expenses 30% 80,870 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 26,957 Construction & field expenses 5% of purchased equip cost (B) 13,478 Contractor fees 10% of purchased equip cost (B) 26,957 Start-up 2% of purchased equip cost (B) 5,391 Performance test 1% of purchased equip cost (B) 2,696 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 8,087 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Total Annual Direct Operating Costs 758 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680 Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340 Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340 Capital Recovery for a 20- year equipment life and a 7% interest rate 40,967 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB 1/8/2008 Page 90 of 106

287 Draft BART Emission Control Cost Analysis Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 LNB 1/8/2008 Page 91 of 106

288 Draft BART Emission Control Cost Analysis Table A.15.d: NO X Control - Low NO X Burner with Flue Gas Recirculation Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Chemical Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/ Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 221,866 Purchased Equipment Total (B) 22% of control device cost (A) 269,567 Installation - Standard Costs 30% of purchased equip cost (B) 80,870 Installation - Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540 Emission Control Cost Calculation Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,646 Notes & Assumptions 1 Equipment cost based on estimate from John Zink 2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2 Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB 1/8/2008 Page 92 of 106

289 Draft BART Emission Control Cost Analysis Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) 221,866 Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC Instrumentation 10% of control device cost (A) 22,187 MN Sales Taxes 6.5% of control device cost (A) 14,421 Freight 5% of control device cost (A) 11,093 Purchased Equipment Total (B) 22% 269,567 Installation Foundations & supports 8% of purchased equip cost (B) 21,565 Handling & erection 14% of purchased equip cost (B) 37,739 Electrical 4% of purchased equip cost (B) 10,783 Piping 2% of purchased equip cost (B) 5,391 Insulation 1% of purchased equip cost (B) 2,696 Painting 1% of purchased equip cost (B) 2,696 Installation Subtotal Standard Expenses 30% 80,870 Site Preparation, as required Site Specific n/a Buildings, as required Site Specific n/a Site Specific - Other Site Specific n/a Total Site Specific Costs n/a Installation Total n/a Total Direct Capital Cost, DC 350,437 Indirect Capital Costs Engineering, supervision 10% of purchased equip cost (B) 26,957 Construction & field expenses 5% of purchased equip cost (B) 13,478 Contractor fees 10% of purchased equip cost (B) 26,957 Start-up 2% of purchased equip cost (B) 5,391 Performance test 1% of purchased equip cost (B) 2,696 Model Studies 0% of purchased equip cost (B) 0 Contingencies 3% of purchased equip cost (B) 8,087 Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566 Total Capital Investment (TCI) = DC + IC 434,003 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Supervisor 15% 15% of Operator Costs 36 Maintenance Maintenance Labor $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241 Maintenance Materials 100% of maintenance labor costs 241 Utilities, Supplies, Replacements & Waste Management Total Annual Direct Operating Costs 758 Indirect Operating Costs Overhead 60% of total labor and material costs 455 Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680 Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340 Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340 Capital Recovery for a 20- year equipment life and a 7% interest rate 40,967 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782 Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB 1/8/2008 Page 93 of 106

290 Draft BART Emission Control Cost Analysis Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28.0% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA 36 15% of Operator Costs Maintenance Maint Labor $/Hr 0.01 hr/8 hr shift $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Maint Mtls 100 % of Maintenance Labor NA % of Maintenance Labor Utilities, Supplies, Replacements & Waste Management See Summary page for notes and assumptions *annual use rate is in same units of measurement as the unit cost factor P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 LNB 1/8/2008 Page 94 of 106

291 Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR) Operating Unit: Utility Plant Heater Boiler #1 Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 769,260 Purchased Equipment Total (B) 0% of control device cost (A) 769,260 Installation - Standard Costs 15% of purchased equip cost (B) 138,467 Total Capital Investment (TCI) = DC + IC 1,084,406 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,037 Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SNCR #1 SNCR 95 of 106

292 Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 769,260 Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 38,463 Engineerin & Home Office 10% of purchased equip cost (A) 76,926 Process Contingency 5% of purchased equip cost (A) 38,463 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852 Project Contingeny ( C) 15% of (A + B) 138,467 Total Plant Cost D A + B + C 1,061,579 Allowance for Funds During Construction (E) 0 for SNCR 0 Royalty Allowance (F) 0 for SNCR 0 Pre Production Costs (G) 2% of (D+E)) 21,232 Inventory Capital Reagent Vol * $/gal 1,596 Intial Catalyst and Chemicals 0 for SNCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406 Retrofit Installation Factor 30% 325,322 Total Capital Investment, Retrofit Installed 1,409,728 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total % of Total Capital Investment 162,661 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kw-hr, 3156 hr/yr, 28% utilization 89 Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1 Urea $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198 Total Annual Direct Operating Costs 166,949 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 133,068 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SNCR #1 SNCR 96 of 106

293 Draft BART Emission Control Cost Analysis Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use NOx in 0.28 lb/mmbtu kw NSR 1.37 equation 1.14 Power 2.0 Total 2.0 Reagent Use & Other Operating Costs Urea Use lb/hr Neat equation % solution 71.0 lb/ft 3 Density 50% Solution lb/hr 2.5 gal/hr 831 gal $1,596 Inventory Cost Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.0 kw-hr 1, $/kwh, 2 kw-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #1 SNCR #1 SNCR 97 of 106

294 Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR) Operating Unit: Utility Plant Heater Boiler #2 Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 32º F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 68º F Dry Std Flow Rate 10,240 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 769,260 Purchased Equipment Total (B) 0% of control device cost (A) 769,260 Installation - Standard Costs 15% of purchased equip cost (B) 138,467 Total Capital Investment (TCI) = DC + IC 1,084,406 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,495 Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 98 of 106

295 Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 769,260 Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 38,463 Engineerin & Home Office 10% of purchased equip cost (A) 76,926 Process Contingency 5% of purchased equip cost (A) 38,463 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852 Project Contingeny ( C) 15% of (A + B) 138,467 Total Plant Cost D A + B + C 1,061,579 Allowance for Funds During Construction (E) 0 for SNCR 0 Royalty Allowance (F) 0 for SNCR 0 Pre Production Costs (G) 2% of (D+E)) 21,232 Inventory Capital Reagent Vol * $/gal 1,596 Intial Catalyst and Chemicals 0 for SNCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406 Retrofit Installation Factor 30% 325,322 Total Capital Investment, Retrofit Installed 1,409,728 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total % of Total Capital Investment 162,661 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 2 kw-hr, 3156 hr/yr, 28% utilization 89 Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1 Urea $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198 Total Annual Direct Operating Costs 166,949 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 133,068 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068 Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 99 of 106

296 Draft BART Emission Control Cost Analysis Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use NOx in 0.28 lb/mmbtu kw NSR 1.37 equation 1.14 Power 2.0 Total 2.0 Reagent Use & Other Operating Costs Urea Use lb/hr Neat equation % solution 71.0 lb/ft 3 Density 50% Solution lb/hr 2.5 gal/hr 831 gal $1,596 Inventory Cost Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.0 kw-hr 1, $/kwh, 2 kw-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #2 SNCR #2 SNCR 100 of 106

297 Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR) Operating Unit: Utility Plant Heater Boiler #4 Emission Unit Number EU 004 Stack/Vent Number 0 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 905,717 Purchased Equipment Total (B) 0% of control device cost (A) 905,717 Installation - Standard Costs 15% of purchased equip cost (B) 163,029 Total Capital Investment (TCI) = DC + IC 1,277,232 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,792 Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 101 of 106

298 Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 905,717 Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 45,286 Engineerin & Home Office 10% of purchased equip cost (A) 90,572 Process Contingency 5% of purchased equip cost (A) 45,286 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143 Project Contingeny ( C) 15% of (A + B) 163,029 Total Plant Cost D A + B + C 1,249,889 Allowance for Funds During Construction (E) 0 for SNCR 0 Royalty Allowance (F) 0 for SNCR 0 Pre Production Costs (G) 2% of (D+E)) 24,998 Inventory Capital Reagent Vol * $/gal 2,345 Intial Catalyst and Chemicals 0 for SNCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232 Retrofit Installation Factor 30% 383,169 Total Capital Investment, Retrofit Installed 1,660,401 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total % of Total Capital Investment 191,585 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kw-hr, 3156 hr/yr, 28% utilization 131 Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1 Urea $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166 Total Annual Direct Operating Costs 197,883 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 156,730 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 102 of 106

299 Draft BART Emission Control Cost Analysis Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use NOx in 0.28 lb/mmbtu kw NSR 1.37 equation 1.14 Power 2.9 Total 2.9 Reagent Use & Other Operating Costs Urea Use lb/hr Neat equation % solution 71.0 lb/ft 3 Density 50% Solution lb/hr 3.6 gal/hr 1,220 gal $2,345 Inventory Cost Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.9 kw-hr 2, $/kwh, 3 kw-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #4 SNCR #4 SNCR 103 of 106

300 Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR) Operating Unit: Utility Plant Heater Boiler #5 Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 32º F Plant Cost Index Expected Utiliztion Rate 28% Temperature 380 Deg F Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18 Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 68º F Dry Std Flow Rate 15,360 68º F CONTROL EQUIPMENT COSTS Capital Costs Direct Capital Costs Purchased Equipment (A) 905,717 Purchased Equipment Total (B) 0% of control device cost (A) 905,717 Installation - Standard Costs 15% of purchased equip cost (B) 163,029 Total Capital Investment (TCI) = DC + IC 1,277,232 Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613 Emission Control Cost Calculation Max Emis Annual Control Eff Controlled Emis Reduction Control Cost Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem Nitrous Oxides (NOx) % ,494 Notes & Assumptions 1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19 Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI 2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21 P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 104 of 106

301 Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR) CAPITAL COSTS Direct Capital Costs Purchased Equipment (A) (1) Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717 Instrumentation 10% of control device cost (A) NA MN Sales Taxes 6.5% of control device cost (A) NA Freight 5% of control device cost (A) NA Purchased Equipment Total (A) 905,717 Indirect Installation [1] General Facilities 5% of purchased equip cost (A) 45,286 Engineerin & Home Office 10% of purchased equip cost (A) 90,572 Process Contingency 5% of purchased equip cost (A) 45,286 Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143 Project Contingeny ( C) 15% of (A + B) 163,029 Total Plant Cost D A + B + C 1,249,889 Allowance for Funds During Construction (E) 0 for SNCR 0 Royalty Allowance (F) 0 for SNCR 0 Pre Production Costs (G) 2% of (D+E)) 24,998 Inventory Capital Reagent Vol * $/gal 2,345 Intial Catalyst and Chemicals 0 for SNCR 0 Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232 Retrofit Installation Factor 30% 383,169 Total Capital Investment, Retrofit Installed 1,660,401 OPERATING COSTS Direct Annual Operating Costs, DC Operating Labor Operator NA - Supervisor NA - Maintenance Maintenance Total % of Total Capital Investment 191,585 Maintenance Materials NA % of Maintenance Labor - Utilities, Supplies, Replacements & Waste Management Electricity 0.05 $/kwh, 3 kw-hr, 3156 hr/yr, 28% utilization 131 Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1 Urea $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166 Total Annual Direct Operating Costs 197,883 Indirect Operating Costs Overhead NA of total labor and material costs NA Administration (2% total capital costs) NA of total capital costs (TCI) NA Property tax (1% total capital costs) NA of total capital costs (TCI) NA Insurance (1% total capital costs) NA of total capital costs (TCI) NA Capital Recovery for a 20- year equipment life and a 7% interest rate 156,730 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730 Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613 See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 105 of 106

302 Draft BART Emission Control Cost Analysis Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR) Capital Recovery Factors Primary Installation Interest Rate 7.00% Equipment Life 20 years CRF Electrical Use NOx in 0.28 lb/mmbtu kw NSR 1.37 equation 1.14 Power 2.9 Total 2.9 Reagent Use & Other Operating Costs Urea Use lb/hr Neat equation % solution 71.0 lb/ft 3 Density 50% Solution lb/hr 3.6 gal/hr 1,220 gal $2,345 Inventory Cost Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr Operating Cost Calculations Annual hours of operation: 3,156 Utilization Rate: 28% Unit Unit of Use Unit of Annual Annual Comments Item Cost $ Measure Rate Measure Use* Cost Operating Labor Op Labor $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr Supervisor 15% of Op. NA - 15% of Operator Costs Maintenance Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor Utilities, Supplies, Replacements & Waste Management Electricity $/kwh 2.9 kw-hr 2, $/kwh, 3 kw-hr, 3156 hr/yr, 28% utilization Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization Urea 405 $/ton ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization ** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor See Summary page for notes and assumptions P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART #5 SNCR #5 SNCR 106 of 106

303 Barr Engineering Company Appendix B 4700 West 77th Street Minneapolis, MN Phone: Fax: An EEO Employer Minneapolis, MN Hibbing, MN Duluth, MN Ann Arbor, MI Jefferson City, MO Memorandum To: Margaret McCourtney From: Andrew Skoglund Subject: Revisions per your comments Date: May 16, 2006 Project: Taconite Industry BART Clients c: Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps. Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files and a figure depicting the proposed modeling domain are also included, as requested. The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with observations for review. The values noted are representative of those that were used after receiving comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005, with FLM response on June 14, 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) askoglund@barr.com

304 Legend Modeling Domain Class I Area BWCA Voyageurs!;N Barr Footer: Date: 6/3/2004 4:10:56 PM File: C:\Temp\Test.mxd User: bal Kilometers Miles MODELING DOMAIN Taconite BART Modeling Taconite Industry Group Minnesota

305 TERREL Variable Description Value Default Comments Input Group 0b GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used Input Group 2 XREFKM Reference point coordinates for grid 168 n/a YREFKM Reference point coordinates for grid 720 n/a NX Number of X grid cells 40 n/a NY Number of Y grid cells 30 n/a CTGPROC Variable Description Value Default Comments Input Group 2 XREFKM Reference point coordinates for grid 168 n/a YREFKM Reference point coordinates for grid 720 n/a NX Number of X grid cells 40 n/a NY Number of Y grid cells 30 n/a CALMET Variable Description Value Default Comments NUSTA Number of upper air stations , 14918, 94983, 4837 Input Group 2 NX Number of X grid cells 40 n/a NY Number of Y grid cells 30 n/a XORIGKM Reference point coordinates for grid 168 n/a YORIGKM Reference point coordinates for grid 720 n/a Input Group 4 NOOBS No Observation Mode 0 Y Include Surface, Upper Air and Precipitation Observations NSSTA Number of Surface Stations 74 n/a 74 surface weather stations NPSTA Number of Precipitation Stations 68 n/a 68 precipitation stations Input Group 5 RMAX2 Maximum radius of influence over land aloft 50 n/a Similar to PSD with Observations RMAX3 Maximum radius of influence over water 500 n/a Similar to PSD with Observations R1 Relative weighting of the first guess field and observations in the surface layer (km) 10 n/a Similar to PSD with Observations R2 Relative weighting of the first guess field and observations in the layers aloft (km) 20 n/a Similar to PSD with Observations ISURFT Surface met. Stations to use for the surface temperature - n/a Hibbing Met station IUPT Upper air station to use for the domain scale lapse rate - n/a International Falls Upper Air station Input Group 6 ITPROG 3D temperature from observations or from prognostic data? 0 Y Inclusion of Surface and Upper Air TRADKM Radius of influence for temperature interpolation 500 Y Similar to PSD with Observations JWAT1 Beginning land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater data JWAT2 Ending land use category for temperature interpolation over water 99 n/a CALMET may fail when using 55 with no overwater data SIGMAP Radius of influence (km) 100 Y Precipitation Observations are included

306 CALPUFF Variable Description Value Default Comments Input Group 4 NX Number of X grid cells in met grid 40 n/a NY Number of Y grid cells in met grid 30 n/a XORIGKM Reference point coordinates for met grid 168 n/a YORIGKM Reference point coordinates for met grid 720 n/a IBCOMP X index of LL corner 1 n/a JBCOMP Y index of LL corner 1 n/a IECOMP X index of UR corner 40 n/a JECOMP Y index of UR corner 30 n/a Input Group 11 MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, and MI observation stations Input Group 17 NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyageurs from MPCA protocol

307 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 Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to BART in the State of Minnesota.

308 CALMET Three years ( ) of MM5 prognostic mesoscale meteorological data, surface weather data, precipitation data, and upper air data were used to generate the CALMET data set for use in the CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells (north-south) with a grid spacing of 12 km. This grid encompasses MinnTac sources, the BWCAW and Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files required by CALMET were obtained from the MPCA. CALPUFF CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to the values specified in the revised modeling protocol (Appendix B). The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5µ to 10µ), and PM2.5 (fine particulate matter, under 2.5µ). The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates of transformation. The MESOPUFF-generated transformation rates are a function of the background ozone and ammonia concentrations, the former set by observations, the latter using monthly average values provided by MPCA. The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and Voyageurs National Park provided by the MPCA in the original subject-to-bart modeling files. CALPOST CALPOST converted the hourly concentration and monthly average relative humidity files generated by CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction coefficients were compared to the 20% best days background extinction coefficients designated in the modeling protocol.

309 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 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota.

310 De minimis Modeling As a part of the streamlined BART approach, a method for removing insignificant sources from further BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dv was used in this analysis. For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98 th percentile modeled impact for these sources was 0.04 dv, meeting the required de minimis threshold of 0.05 dv. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below. Modeled 98th Percentile Impact Maximum BWCA Voyageurs Predicting 24-Hour Maximum Emission Rates Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for pre- BART visibility impacts, the post-bart emissions to be used for the visibility impacts analysis should reflect a maximum 24-hour average basis. Table 4-1 & Table 6-2 within this report describe the pre and post-bart model input parameters, respectively. Modeled Results Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for the predicted post-bart emission scenario(s). Results for the 98th percentile and number of days above 0.5 dv at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are included in Table 6-3.

311 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 Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to BART in the State of Minnesota.

312 CALMET Three years ( ) of MM5 prognostic mesoscale meteorological data, surface weather data, precipitation data, and upper air data were used to generate the CALMET data set for use in the CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells (north-south) with a grid spacing of 12 km. This grid encompasses MinnTac sources, the BWCAW and Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files required by CALMET were obtained from the MPCA. CALPUFF CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to the values specified in the revised modeling protocol (Appendix B). The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5µ to 10µ), and PM2.5 (fine particulate matter, under 2.5µ). The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates of transformation. The MESOPUFF-generated transformation rates are a function of the background ozone and ammonia concentrations, the former set by observations, the latter using monthly average values provided by MPCA. The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and Voyageurs National Park provided by the MPCA in the original subject-to-bart modeling files. CALPOST CALPOST converted the hourly concentration and monthly average relative humidity files generated by CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction coefficients were compared to the 20% best days background extinction coefficients designated in the modeling protocol.

313 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 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subjectto-Bart in the State of Minnesota.

314 De minimis Modeling As a part of the streamlined BART approach, a method for removing insignificant sources from further BART evaluation was developed, with guidance from MPCA. Sources meeting a de minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dv was used in this analysis. For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98 th percentile modeled impact for these sources was 0.04 dv, meeting the required de minimis threshold of 0.05 dv. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below. Modeled 98th Percentile Impact Maximum BWCA Voyageurs Predicting 24-Hour Maximum Emission Rates Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for pre- BART visibility impacts, the post-bart emissions to be used for the visibility impacts analysis should reflect a maximum 24-hour average basis. Table 4-1 & Table 6-2 within this report describe the pre and post-bart model input parameters, respectively. Modeled Results Visibility impairment was modeled using the meteorological data for the years 2002, 2003 and 2004 for the predicted post-bart emission scenario(s). Results for the 98th percentile and number of days above 0.5 dv at Boundary Waters Canoe Area Wilderness (BWCA) and Voyageurs National Park (VNP) are included in Table 6-3.

315 Barr Footer: Date: 7/5/2006 1:27:58 PM File: I:\projects\23\00\Minntac.mxd User: ams Meters Meters N Minntac Aerial Photo

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