uss minntac bart report...minntac bart report september 8, 2006 y:\23\00 mn taconite bart...
TRANSCRIPT
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
i
Minntac BART Report September 8, 2006
Table of Contents
1. Executive Summary............................................................................................................................. iv
2. Introduction........................................................................................................................................... 1 2.A BART Eligibility......................................................................................................................... 3
2.B BART Determinations ................................................................................................................ 3
3. Streamlined BART Analysis ................................................................................................................ 9 3.A Indurating Furnaces .................................................................................................................... 9
3.B PM-Only Taconite MACT Emission Units ................................................................................ 9
3.C Sources of fugitive PM that are subject to MACT standards.................................................... 10
3.D Non-MACT Units and Fugitive Sources (PM only) ................................................................. 11
3.E Other Combustion Units ........................................................................................................... 11
3.F Visibility Impact Modeling for Negligible Impacts.................................................................. 12
4. Baseline Conditions and Visibility Impacts for BART Eligible Units ............................................... 17 4.A MPCA Subject-to-BART Modeling ......................................................................................... 17
4.B Facility Baseline Emission Rates.............................................................................................. 18
4.C Facility Baseline Modeling Results .......................................................................................... 19
5. BART Analysis for BART Eligible Emission Units .......................................................................... 22 5.A Indurating Furnace .................................................................................................................... 22
5.A.i Sulfur Dioxide Controls............................................................................................... 25
5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 25
5.A.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 25
5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 32
5.A.i.d STEP 4 – Evaluate Impacts and Document the Results ............................... 33
5.A.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 35
5.A.ii Nitrogen Oxide Controls.............................................................................................. 40
5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 40
5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options.................................... 40
5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 54
5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results ............................... 54
5.A.ii.e STEP 5 – Evaluate Visibility Impacts.......................................................... 57
5.B External Combustion Sources................................................................................................... 62
5.B.i Nitrogen Oxide Controls.............................................................................................. 62
5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies ................. 62
5.B.i.b STEP 2 – Eliminate Technically Infeasible Options.................................... 63
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
ii
5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies ................................................................................................ 70
5.B.i.d STEP 4 – Evaluate Impacts and Document the Results ............................... 71
5.B.i.e STEP 5 – Evaluate Visibility Impacts.......................................................... 73
6. Visibility Impacts................................................................................................................................ 77 6.A Post-BART Modeling Scenarios............................................................................................... 77
6.B Post-BART Modeling Results .................................................................................................. 77
7. Select BART....................................................................................................................................... 81 7.A Indurating Furnaces .................................................................................................................. 81
7.B External Combustion Sources................................................................................................... 84
List of Tables
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis ...14
Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data .............15
Table 3-3 De Minimis Visibility Modeling Results....................................................................16
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data ..20
Table 4-2 Baseline Visibility Modeling Results ..........................................................................21
Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................32
Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness .........................................32
Table 5-3 Indurating Furnace SO2 Control Cost Summary ..........................................................34
Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates ..........................................................................................................................37
Table 5-5 Indurating Furnace Post-BART SO2 Modeling Scenarios - Visibility Modeling Results39
Table 5-6 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility ..................................................................................................53
Table 5-7 Indurating Furnace NOx Control Technology Effectiveness ........................................54
Table 5-8 Indurating Furnace NOx Control Cost Summary .........................................................55
Table 5-9 Indurating Furnace NOx Control Technology Impacts Assessment ..............................57
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates ..........................................................................................................................60
Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results61
Table 5-12 Boiler NOx Control Technology – Availability, Applicability, and Technical Feasibility70
Table 5-13 Boiler NOx Control Technology Effectiveness ............................................................71
Table 5-14 Boiler NOx Control Cost Summary .............................................................................72
Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates .........75
Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results ................76
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results ...................................80
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
iii
List of Figures
Figure 2-1 Minnesota’s BART Geography.....................................................................................2
List of Appendices
Appendix A Control Cost Analysis Spreadsheets
Appendix B Changes to MPCA BART Modeling Protocol
Appendix C Visibility Impacts Modeling Report
Appendix D NOX Emissions Analysis – Pre and Post Installation of Air Injection Ports on Line 7
at USS/Minntac
Appendix E Indurating Furnace – Applicable and Available Retrofit Technologies
Appendix F Summary of Relevant Economic Feasibility ($/ton) Control Costs
Appendix G Process Heating Boiler – Applicable and Available Retrofit Technologies
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
iv
1. Executive Summary
U.S. Steel Corporation’s Minnesota Ore Operations (Minntac) is located in northern Minnesota, with
taconite mining and processing facilities near Mountain Iron, Minnesota. This report describes the
background and methods for the selection of the Best Available Retrofit Technology (BART) as
proposed by Minntac for its taconite processing plant.
Within the pellet making process, there are many pieces of equipment with pollution control devices
to reduce emissions. Based on the regulatory definitions and the details provided in this report,
Minntac’s BART-eligible units include emission units that were installed within the BART time
window (1962-1977). These BART-eligible units include the indurating furnaces, heating boilers,
minor combustions sources, and several material handling and storage units for ore, product, and
additives. Preliminary visibility modeling conducted by the MPCA found that the BART-eligible air
emissions from Minntac “cause or contribute to visibility impairment” in a federally protected Class I
area, therefore making the facility subject-to-BART. As a subject-to-BART facility, a BART
analysis was required to determine BART for the affected emission units.
Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include
a streamlined approach for BART analyses1. The streamlined approach allows both the states and the
facilities to focus their resources on the main contributors to visibility impairment. As described in
section 3 of this document, the emissions from several of the sources at this facility meet the criteria
for a streamlined analysis.
The streamlined analysis includes the specific provision that compliance with the Taconite MACT
(40 CFR Part 63 Subpart RRRRR) for PM emissions as equivalent to BART. This provision is
applicable to all indurating furnaces, ore crushing and handling operations, and finished pellet
handling operations that are subject to BART. The Taconite MACT standard includes requirements
for performance testing and continuous parametric monitoring for compliance demonstration.
After completion of the streamlined analysis, the focus of the BART analysis was the NOx emissions
from four heating boilers and the SO2 and NOx emissions from the five indurating furnaces. The four
boilers that underwent the BART analysis are relatively small, and have limited hours of operation
and utilization. The Indurating Furnaces operate with existing control equipment which include: wet
1 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
v
scrubbers for each of the five stacks designed to control of particulate matter (PM) with collateral
control of sulfur dioxide (SO2); ported kilns on two of the furnaces designed for energy efficiency
with collateral control of nitrogen oxides (NOx); and low-NOx burners installed on the preheat
section of one of the furnaces.
Guidelines included in 40 CFR §51 Appendix Y and MPCA Attachments 2 and 3 were used to
determine BART for these sources. A dispersion modeling sequence of CALMET, CALPUFF, and
CALBART was used to assess the visibility impacts of the baseline emissions and after the
application of candidate BART controls. Visibility impacts were evaluated in the selection of BART.
Other criteria that the BART rules require to be considered include the availability of control
technologies, cost of control, energy and environmental impacts, existing pollution control
technology in use at the source, and the remaining useful life of the source.
Based on the consideration of all of the above criteria, Minntac proposes no additional controls,
emission limits, or monitoring requirements for the NOx emissions from four heating boilers. This is
based on the conclusion that low-NOx burners were the only control technology that meet the cost
screening threshold, but the technology did not provide significant improvement in the visibility
modeling. In addition, the control cost for this technology is higher than the anticipated level for a
BART analysis. It is also important to note that due to the relatively small size of the boilers and the
low hours of operation, the actual visibility impact of the boilers is small.
Based on consideration of all of the above criteria, Minntac proposes the following as BART for SO2
and NOX for the Indurating Furnaces:
• BART for SO2:
o SO2 emissions will be controlled by the existing wet scrubbers, which will be
operated as required in accordance with provisions of the Taconite MACT.
o SO2 emission limit for the Indurating Furnace on Line 3 will be determined based
on upcoming performance testing to determine the actual emission rate from the
furnace with the addition of the new scrubber. A proposed SO2 limit for the
furnace in the draft PSD permit for Minntac does not reflect the recently installed
wet scrubber.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
vi
o SO2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the
limits which are based on using the existing wet scrubbers and reflect air
dispersion modeling results for regional haze as proposed in the draft PSD
permit:
⋅ Line 4 = 182 lbs/hr
⋅ Line 5 = 182 lbs/hr
⋅ Line 6 = 284 lbs/hr
⋅ Line 7 = 284 lbs/hr
o Compliance will be initially be demonstrated by a performance test at each
furnace.
o Continuous compliance will be demonstrated by continuous monitoring of
scrubber water flow rate and scrubber pressure drop, which are the same
parameters that will be monitored under the Taconite MACT. The operating
limits will be determined based on the MACT compliance test and will be based
on a 24-hour block average. Therefore, the compliance demonstration will be
consistent with the Taconite MACT.
• BART for NOx:
o NOx emissions will be controlled as follows:
⋅ Line 3: Existing combustion controls and fuel blending. Line 3 does not
currently use burners in its pre-heat section, and therefore low-NOx burners
cannot be applied at this furnace.
⋅ Line 4: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
⋅ Line 5: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
vii
⋅ Line 6: Operation of low-NOx burners on the pre-heat section (installed as
replacement and reconfigured burners in April 2006), existing combustion
controls, and fuel blending.
⋅ Line 7: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
o NOx emission limits will be proposed by the facility 12-months after the
installation of the low-NOx burners to allow the facility sufficient time for
process and emissions monitoring using NOx CEMS to determine the actual
emission rates under a variety of operating conditions. Although the facility
anticipates a significant reduction in NOx emissions with the installation of the
low-NOx burners, the actual emissions reduction cannot be determined until the
burners are operated under a variety of operation conditions.
o Initial and continuous compliance will be demonstrated after the appropriate
emission limits have been determined. Compliance will be demonstrated using
the NOx CEMS and will be based on a 30-day rolling average.
The schedule for implementation of these controls, specifically installation of low-NOx burners and
subsequent testing to demonstrate the appropriate BART emission limit, is within the 5-year time-
frame required for BART implementation. In addition, Minntac will continue to evaluate energy
efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission
rates.
Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for
the installation of low-NOx burners, the proposed BART controls will result in visibility
improvement on the 98th percentile day of approximately 0.488 deciviews (dV) when burning gas in
the kiln and 0.465 dV when burning solid fuels in the kiln. This is a visibility improvement of
approximately 7% compared to the baseline (pre-BART) operating conditions.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
1
2. Introduction
To meet the Clean Air Act’s requirements, the U.S. Environmental Protection Agency (U.S. EPA)
published regulations to address visibility impairment in our nation’s largest national parks and
wilderness (“Class I”) areas in July 1999. This rule is commonly known as the “Regional Haze
Rule” [64 Fed. Reg. 35714 (July, 1999) and 70 Fed. Reg. 39104 (July 6, 2005), and] and is found in
40 CFR part 51, in §51.300 through §51.309.
Within its boundary, Minnesota has two Class I areas – the Boundary Water Canoe Area Wilderness
and Voyageurs National Park. In addition, emissions from Minnesota may contribute to visibility
impairment in other states’ Class I areas, such as Michigan’s Isle Royale National Park and Seney
Wilderness Area. By December 2007, MPCA must submit to U.S. EPA a Regional Haze State
Implementation Plan (SIP) that identifies sources that cause or contribute to visibility impairment in
these areas. The Regional Haze SIP must also include a demonstration of reasonable progress toward
reaching the 2018 visibility goal for each of the state’s Class I areas.
One of the provisions of the Regional Haze Rule is that certain large stationary sources that were put
in place between 1962 and 1977 must conduct a Best Available Retrofit Technology (BART)
analysis. The purpose of the BART analysis is to analyze available retrofit control technologies to
determine if a technology should be installed to improve visibility in Class I areas. The chosen
technology is referred to as the BART controls, or simply BART. The SIP must require BART on all
BART-eligible sources and mandate a plan to achieve natural background visibility by 2064.
Figure 2-1 illustrates the BART-eligible facilities and the two Class I areas in Minnesota. When
reviewing Figure 2-1, it is important to note that Minnesota Steel Industries (MSI) and Mesabi
Nugget (Nugget), which are illustrated in the figure, are not currently constructed or in operation.
The SIP must also include milestones for establishing reasonable progress towards the visibility
improvement goals and plans for the first five-year period. Upon submission of the Regional Haze
SIP, states must make the requirements for BART sources federally enforceable through rules,
administrative orders or Title V permit amendments.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
2
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.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
3
2.A BART Eligibility BART eligibility is established on the basis of three criteria. In order to be BART-eligible, sources
must meet the following three conditions:
1. Contain emission units in one or more of the 26 listed source categories under the PSD rules
(e.g., taconite ore processing plants, fossil-fuel-fired steam electric plants larger than 250
MMBtu/hr, fossil-fuel boilers larger than 250 MMBtu/hr, petroleum refineries, coal cleaning
plants, sulfur recovery plants, etc.);
2. Were in existence on August 7, 1977, but were not in operation before August 7, 1962;
3. Have total potential emissions greater than 250 tons per year for at least one visibility-
impairing pollutant from the emission units meeting the two criteria above.
Under the BART rules, large sources that have previously installed pollution-control equipment
required under another standard (e.g., MACT, NSPS and BACT) are required to conduct visibility
analyses to determine if the source is subject-to-BART. Installation of additional controls may be
required to further reduce emissions of visibility impairing pollutants such as PM, PM10, PM2.5, SO2,
NOx, and possibly Volatile Organic Compounds (VOCs) and ammonia. Sources built before the
implementation of the Clean Air Act (CAA), which had previously been grandfathered, may also
have to conduct such analyses and possibly install controls, even though they have been exempted to
date from any other CAA requirements.
Once BART eligibility is determined, a source must then determine if it is ‘subject-to-BART.’ A
source is subject-to-BART if emissions ‘cause or contribute’ to visibility impairment at any Class I
area. Visibility modeling conducted with CALPUFF or another U.S. EPA -approved visibility model
is necessary to make a definitive visibility impairment determination (>0.5 deciviews). Sources that
do not cause or contribute to visibility impairment are exempt from BART requirements, even if they
are BART-eligible.
2.B BART Determinations Each source that is subject to BART must determine BART on a case-by-case basis. Even if a source
was previously part of a group BART determination, individual BART determinations must be made
for each source. The BART analysis takes into account six criteria and is analyzed using five steps.
The criteria that comprise the engineering analysis include: the availability of the control technology,
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
4
existing controls at a facility, the cost of compliance, the remaining useful life of a source, the energy
and non-air quality environmental impacts of the technology, and the visibility impacts.2
The five steps of a BART analysis are:
Step 1 - Identify all Control Technologies
The first step in the analysis is to identify all available retrofit control technologies for
each applicable emission unit. U.S. EPA is very specific about the criteria to be met
for a technology to be considered available. In preambles to the interim and final rules
U.S. EPA defines “available” as follows:
Available retrofit technologies are those air pollution control technologies
with a practical potential for application to the emissions unit and the
regulated pollutant under evaluation. Air pollution control technologies can
include a wide variety of available methods, systems, and techniques for
control of the affected pollutant. Technologies required as BACT or LAER
are available for BART purposes and must be included as control
alternatives. The control alternatives can include not only existing controls
for the source category in question, but also take into account technology
transfer of controls that have been applied to similar source categories or gas
streams. Technologies which have not yet been applied to (or permitted for)
full scale operations need not be considered as available; we do not expect
the source owner to purchase or construct a process or control device that
has not been demonstrated in practice.3
Step 2 - Eliminate Technically Infeasible Options In the second step, the technical feasibility of each control option identified in step one
is evaluated by answering three specific questions:
1. Is the control technology “available” to the specific source which is undergoing the
BART analysis?
The U.S. EPA states that a control technique is considered “available” to a specific
source “if it has reached the stage of licensing and commercial availability.”
2 40 CFR 51 Appendix Y 3 Federal Register 70, No. 128 (July 6, 2005): 39164
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
5
However, the U.S. EPA further states that they “do not expect a source owner to
conduct extended trials to learn how to apply a technology on a totally new and
dissimilar source type.” 4
2. Is the control technology an “applicable technology” for the specific source which
is undergoing the BART analysis?
In general, a commercially available control technology, as defined in question 1,
“will be presumed applicable if it has been used on the same or a similar source
type.” If a control technology has not been demonstrated on a same or a similar
source type, the technical feasibility is determined by “examining the physical and
chemical characteristics of the pollutant-bearing stream and comparing them to the
gas stream characteristics of the source types to which the technology has been
applied previously.”5
3. Are there source-specific issues/conditions that would make the control technology
not technically feasible?
This question addresses specific circumstances that “preclude its application to a
particular emission unit.” This demonstration typically includes an “evaluation of
the characteristics of the pollutant-bearing gas stream and the capabilities of the
technology.” This also involves the identification of “un-resolvable technical
difficulties.” However, when the technical difficulties are merely a matter of
increased cost, the technology should be considered technically feasible and the
technological difficulty evaluated as part of the economic analysis.6
It is also important to note that vendor guarantees can provide an indication of
technical feasibility but the U.S. EPA does not “consider a vendor guarantee alone
to be sufficient justification that a control option will work.” Conversely, the U.S.
EPA does not consider the lack of a vender guarantee as “sufficient justification
that a control option or emission limit is technically infeasible.” In general, the
decisions on technical feasibility should be based on a combination of the
4 Federal Register 70, No. 128 (July 6, 2005): 39165 5 IBID 6 IBID
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
6
evaluation of the chemical and engineering analysis and the information from
vendor guarantees.7
Step 3 - Evaluate Control Effectiveness
In step three, the remaining controls are ranked based on the control efficiency at the
expected emission rate (post-BART) as compared to the emission rate before addition
of controls (pre-BART) for the pollutant of concern.
Step 4 - Evaluate Impacts and Document Results
In the fourth step, an engineering analysis documents the impacts of each remaining
control technology option. The economic analysis compares dollar per ton of pollutant
removed for each technology. In addition it includes incremental dollar per ton cost
analysis to illustrate the economic effectiveness of one technology in relation to the
others. Finally, step four includes an assessment of energy impacts and other non-air
quality environmental impacts.
Economic impacts were analyzed using the procedures found in the U.S. EPA Air
Pollution Control Cost Manual – Sixth Edition (EPA 452/B-02-001). Equipment cost
estimates from the U.S. EPA Air Pollution Control Cost Manual or U.S. EPA’s Air
Compliance Advisor (ACA) Air Pollution Control Technology Evaluation Model
version 7.5 were used. Vendor cost estimates for this project were used when
applicable. The source of the control equipment cost data are noted in each of the
control cost analysis worksheets as found in Appendix A.
Step 5 - Evaluate Visibility Impacts The fifth step requires a modeling analysis conducted with U.S. EPA -approved models
such as CALPUFF. The modeling protocol8, including receptor grid, meteorological
data, and other factors used for this part of the analysis were provided by the Minnesota
Pollution Control Agency. The model outputs, including the 98th percentile deciview
(dV) value and the number of days the facility contributes more than a 0.5 dV of
visibility impairment at each of the Class I areas, are used to establish the degree of
improvement that can be reasonably attributed to each technology.
7 IBID 8 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject to
BART in the State of Minnesota.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
7
The final step in the BART analysis is to select the “best alternative” using the results of steps 1
through 5. When selecting the “best alternative,” the U.S. EPA and MPCA guidance states that the
“affordability” of the controls should be considered, and specifically states:
1. Even if the control technology is cost effective, there may be cases where the installation
of controls would affect the viability of plant operations.
2. There may be unusual circumstances that justify taking into consideration the conditions
of the plant and the economic effects requiring the use of a given control technology.
These effects would include effects on product prices, the market share, and profitability
of the source. Where there are such unusual circumstances that are judged to affect
plant operations, you may take into consideration the conditions of the plant and the
economic effects of requiring the use of a control technology. Where these effects are
judged to have severe impacts on plant operations you may consider them in the selection
process, but you may wish to provide an economic analysis that demonstrates, in
sufficient detail for public review, the specific economic effects, parameters, and
reasoning. (We recognize that this review process must preserve the confidentiality of
sensitive business information). Any analysis may also consider whether competing
plants in the same industry have been required to install BART controls if this
information is available.9
To complete the BART process, the analysis must “establish enforceable emission limits that reflect
the BART requirements and requires compliance within a reasonable period of time.”10 Those limits
must be developed for inclusion in the state implementation plan (SIP) that is due to U.S. EPA in
December of 2007. In addition, the analysis must include requirements that the source “employ
techniques that ensure compliance on a continuous basis”11 which could include the incorporation of
other regulatory requirements for the source, including Compliance Assurance Monitoring (40 CFR
64), Periodic Monitoring (40 CFR 70.6(a)(3)) and Sufficiency Monitoring (40 CFR 70(6)(c)(1)). If
technological or economic limitations make measurement methodology for an emission unit
9 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 20. 10 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 23. 11 IBID
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
8
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
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
9
3. Streamlined BART Analysis
Within the preamble to the final federal BART rule, U.S. EPA explicitly encouraged states to include
a streamlined approach for BART analyses13. The streamlined approach will allow both states and the
facilities to focus their resources on the main contributors to visibility impairment. The following
outlines the MPCA-approved streamlined BART analysis for taconite facilities and presents the
results of the streamlined approach in Table 3-1.
3.A Indurating Furnaces The indurating furnace is a source of three visibility impairing pollutants: NOx, SO2, and PM.
Relative to NOx and SO2, PM is not a major visibility impairing pollutant. Further, the indurating
furnace is subject to the taconite MACT standard [40 CFR Part 63 Subpart RRRRR-NESHAPS:
Taconite Iron Ore Processing] for the PM emissions. MPCA’s guidance for conducting a BART
review states that “MPCA will rely on MACT standards to represent BART level of control for those
visibility impairing pollutants addressed by the MACT standard unless there are new technologies
subsequent to the MACT standard, which would lead to cost-effective increases in the level of
control.”14 Since the MACT standard was established very recently and becomes effective in 2006,
the technology analysis is up-to-date. As a result, BART will be presumed to be equivalent to
MACT for PM and no further analysis will be required to establish BART for PM for these sources.
A full BART analysis will be conducted for NOx and SO2 where applicable.
3.B PM-Only Taconite MACT Emission Units In addition to the indurating furnaces, the taconite MACT standard also regulates PM emissions from
Ore Crushing and Handling operations, Pellet Coolers, and Finished Pellet Handling operations.
These sources operate near ambient temperature, only emit PM, and do not emit NOx or SO2. The
Ore Crushing and Handling sources and the Finished Pellet Handling sources operate with control
equipment to meet the applicable MACT limits (0.008 gr/dscf for existing sources and 0.005 gr/dscf
for new sources). The Pellet Cooler sources are excluded from additional control under the MACT
standard due to the large size of the particles and the relatively low concentration of particle
emissions.15 Therefore, the emissions from the pellet coolers are considered to have a negligible
13 Federal Register 70, no. 128 (July 6, 2005): 39107 and 39116 14 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 2. 15 Federal Register 67, no. 143 (December 18, 2002): 77570
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
10
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 NOx or SO2. Taconite MACT fugitive sources include the following:
• Stockpiles (includes, but is not limited to, stockpiles of uncrushed ore, crushed ore, or
finished pellets),
• Material Transfer Points,
• Plant Roadways,
• Tailings basins,
• Pellet loading areas, and
• Yard areas.
Control of emissions from these fugitive PM sources is maintained through a fugitive control plan, as
required by the MACT standard and as required by the facility’s Title V air permit. The fugitive
control plans consist of monitoring, primary controls, and contingent measures to prevent or mitigate
fugitive PM emissions. The controls and measures are site specific and are appropriate to seasonal
and weather conditions. Since the MACT standard was established recently and will become
effective in 2006, the technology analysis is up-to-date. Again, for these units subject to a MACT
standard, BART will be presumed to be equivalent to MACT according to MPCA guidance.
No further analysis will be required to establish BART for these sources.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
11
3.D Non-MACT Units and Fugitive Sources (PM only) A few sources of PM emissions and sources of fugitive PM are not subject to a MACT standard.
They include units such as:
• Bentonite storage and handling
• Additive storage and handling
• Concentrate storage and handling
• Coal and/or solid fuel storage and handling Considering all PM emissions which are subject to the BART standard, the PM emissions from the
above units typically represent approximately 1% of PM emissions from the facility, which are
subject-to-BART. Relative to NOx and SO2, PM is not a major visibility impairing pollutant.
The point source emission units are controlled by either baghouses or scrubbers, which are
technologies that achieve high levels of control for PM. Since these units already have control
equipment for PM emissions, and since the PM emissions from these sources are small relative to the
total PM emissions that are subject to the BART standard, additional control of these sources can be
presumed to have minimal impact on visibility improvement in Class I areas. For the controlled
sources, existing controls will be considered BART consistent with direction from MPCA in the May
18, 2006 meeting, and no further analysis will be required to establish BART for these sources. If
any sources do not have existing controls, the facility will conduct an analysis for these sources to
demonstrate that the impact on visibility in Class I areas is negligible. The procedure for the analysis
is detailed in section 3.F of this document. Assuming that the modeling demonstrates that the
sources have a negligible impact on visibility in Class I areas and no further analysis will be required
to establish BART for these sources.
3.E Other Combustion Units This facility has several other combustion units that are subject-to-BART. The combustion units are
sources of three visibility impairing pollutants: NOx, SO2, and PM. The remaining combustion
sources include process heaters, boilers, emergency generators, air compressors, and fire pumps. It is
important to note that the emissions from the indurating furnaces represent the vast majority of
emissions of all visibility impairing pollutants, with the all other emission units contributing less than
1% of the total emissions of each pollutant from sources that are subject-to-BART. The emissions
from all the remaining sources are small relative to the total emissions that are subject to the BART
standard. Additional control of these sources can be presumed to have minimal impact on visibility
improvement in Class I areas. As directed by MPCA in the May 18, 2006 meeting, the existing
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
12
operations for emergency generators and fire pumps will be considered BART. This facility has
conducted an analysis for the remaining sources to demonstrate that the impact on visibility is
negligible. The procedure for the analysis is detailed in section 3.F of this document. For the
sources for which the modeling demonstrates negligible impact on visibility in Class I areas, no
further analysis will be required to establish BART for these sources.
3.F Visibility Impact Modeling for Negligible Impacts As described in section 3.D and 3.E of this document, this facility contains several sources that are
assumed to have a negligible impact on visibility in Class I areas. In order to confirm this
assumption, a modeling analysis was conducted to determine the impact of the emissions from these
sources on visibility in Class I areas. The analysis consisted of the following:
(1) Conduct air dispersion modeling for uncontrolled BART-eligible emission units and
fugitive sources for the facility, as described in sections 3.D and 3.E above. The
modeling was conducted based on MPCA modeling protocol16. One modeling
analysis was conducted. The modeling was conducted on a focused grid (as
previously agreed to with MPCA) which is based on the facility impacts as presented
by MPCA in “Results of Best Available Retrofit Technology (BART) Modeling to
Determine Sources Subject-to-BART in the State of Minnesota” (March 2006).
(2) Count the days with a 98th percentile (21 over 3-yrs, 7 each year) change in visibility
greater than or equal to 0.05 deciviews (based on 10% of the facility threshold of 0.5
deciviews) at the modeled receptors with in the boundaries of each Class I area
assessed over the 3-year period 2002-2004.
(3) If the modeled emission sources result in a 98th percentile change in visibility less
than or equal to 0.05 deciviews, the point and fugitive sources will be considered to
not cause or contribute to visibility impairment in Class I areas. Therefore, the
existing operations will be considered BART. No further analysis will be required to
establish BART for these sources.
16 MPCA. October 10, 2005. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-
BART in the State of Minnesota.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
13
(4) If the modeled emissions result in a 98th percentile change in visibility greater than or
equal to 0.05 deciviews, a full BART analysis will be conducted on the emission
sources.
The de minimis modeling input data is presented in Table 3-2. A summary of the results of the de
minimis modeling is presented in Table 3-3. The details of the de minimis modeling are presented in
Appendix C.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
14
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
15
Table 3-2 De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
16
Table 3-3 De Minimis Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
17
4. Baseline Conditions and Visibility Impacts for BART Eligible Units
As indicated in U.S. EPA’s final BART guidance17, one of the factors to consider when determining
BART for an individual source is the degree of visibility improvement resulting from the retrofit
technology. The visibility impacts for this facility were determined using CALPUFF, a U.S. EPA
approved model. The CALPUFF program models how a pollutant contributes to visibility
impairment with consideration for the background atmospheric ammonia, ozone and meteorological
data. Additionally, the interactions between the visibility impairing pollutants NOx, SO2, PM2.5 and
PM10 can play a large part in predicting impairment. It is therefore important to take a multi-pollutant
approach when assessing visibility impacts.
In order to determine the visibility improvement resulting from the retrofit technology, the source
must first be modeled at baseline conditions. Per MPCA guidance, the baseline, or pre-BART
conditions, shall represent the average emission rate in units of pounds per hour (lbs/hr) and reflect
the maximum 24-hour actual emissions18.
4.A MPCA Subject-to-BART Modeling In order to determine which sources are “Subject-to-BART” in the state of Minnesota, the MPCA
completed modeling of the BART-eligible emission units at various facilities in Minnesota in
accordance with the Regional Haze rule. The modeling by MPCA was conducted using CALPUFF,
as detailed in the “Best Available Retrofit Technology (BART) Modeling Protocol to Determine
Sources Subject-to-BART in the State of Minnesota,” finalized in March 2006. The modeling by
MPCA was conducted using emission rate information submitted by the facility. The emissions were
reported in units of pounds per hour (lbs/hr) and were to reflect the maximum actual emissions
during a 24-hour period under steady-state operating conditions during periods of high capacity
utilization. The results of the modeling were presented in the document titled “Results of Best
Available Retrofit Technology (BART) Modeling to Determine Sources Subject-to-BART in the
State of Minnesota ,” finalized in March 2006. The modeling conducted by MPCA demonstrated that
this facility is subject-to-BART.
17 Federal Register 70, no. 128 (July 6, 2005): 39106. 18 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-BART in the State of Minnesota. Page 8.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
18
It is important to note that the MPCA subject-to-BART modeling only included the induration
furnace sources. This is due to the fact that this facility contains 375 BART-eligible emission units,
which would have added increased complexity to the modeling. However, the modeling results of
only the indurating furnaces demonstrated that the facility is subject-to-BART.
4.B Facility Baseline Emission Rates Prior to re-creating the MPCA visibility impairment model, the modeling protocol was re-revaluated.
On behalf of this facility and the other Minnesota taconite facilities, Barr Engineering proposed
changes to the modeling protocol. The changes, as submitted to MPCA on May 16, 2006 are
presented in Appendix B. The MPCA has given verbal approval to the proposed changes to the
modeling protocol.
Consistent with MPCA modeling and as agreed upon in the MPCA-approved changed to the
modeling protocol, only the induration furnaces were required to be modeled for this facility.
However, the NOx emissions from Boilers #1, #2, #4 and #5 were also added to the visibility model
as these sources are also subject to a full BART analysis for NOx.
In addition, the maximum 24-hour emission rates were re-evaluated and adjusted, as appropriate, to
confirm that the emission rates represent the maximum steady-state operating conditions during
periods of high capacity utilization. The maximum 24-hour emission rates were adjusted to reflect
the highest emission rate as measured during a representative stack test, as opposed to the emission
rate as measured during the most recent stack test. The baseline emission rates from the following
sources were adjusted using this criteria:
o Line 3 Rotary Kiln (EU 225 / SV 103) - NOx and SO2
o Line 4 Rotary Kiln (EU 261 / SV 118) - NOx and SO2
o Line 5 Rotary Kiln (EU 280 / SV 127) - NOx and SO2
o Line 6 Rotary Kiln (EU 315 / SV 144) - NOx and SO2
o Line 7 Rotary Kiln (EU 334 / SV 151) - NOx and SO2
The MPCA visibility impairment modeling evaluated the impacts of the maximum 24-hour emissions
of SO2, NOx, and PM. However, it is important to note that the worst-case SO2 emissions scenario is
based on solid fuel operation and the worst-case NOx emissions scenario is based on natural gas
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
19
operation. Therefore, baseline modeling was conducted for two separate operating scenarios for fuel
burning in the kiln: (1) burning natural gas and (2) burning solid fuel. It is important to note that
natural gas is the only fuel that is burned in the preheat section of the kiln.
The facility baseline data reflecting these changes is summarized in the Table 4-1. The full modeling
analysis is presented in Appendix C.
4.C Facility Baseline Modeling Results The Minnesota BART modeling protocol also describes the post processing elements of the
analysis.19 The CALBART output files provide the following two methods to assess the expected
post-BART visibility improvement:
• 98th Percentile: As defined by federal guidance and as stated in the MPCA’s document which
identifies the Minnesota facilities that are subject to BART20, a source "contributes to
visibility impairment” if the 98th percentile of any year’s modeling results (i.e. 7th highest
day) meets or exceeds the threshold of five-tenths (0.5) of a deciview (dV) at a Federally
protected Class I area receptor.
• Number of Days Exceeding 0.5 dV: The severity of the visibility impairment contribution, or
reasonably attributed visibility impairment, can be gauged by assessing the number of days
on which a source exceeds a visibility impairment threshold of 0.5 dV.
A summary of the baseline visibility modeling is presented in Table 4-2. As illustrated in the table,
the modeling of the revised baseline emissions confirms that the facility is considered to contribute to
visibility impairment in Class I areas because the modeled 98th percentile of the baseline conditions
exceeds the threshold of 0.5 dV. The results of this modeling are also utilized in the post-BART
modeling analysis in section 6 of this document.
The full modeling analysis is presented in Appendix C.
19 MPCA. March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject-to-BART in the State of Minnesota. Page 8. 20 MPCA. March 2006. Results of Best Available Retrofit Technology (BART) Modeling to Determine Sources
Subject-to-BART in the State of Minnesota.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
20
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
21
Table 4-2 Baseline Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
22
5. BART Analysis for BART Eligible Emission Units
BART eligible sources at this facility can be divided into groups based upon type of process. The
Minntac facility had two types of processes which were required to undergo a full BART analysis:
• Indurating Furnaces for NOx and SO2 (Section 5.A)
o Line 3 Rotary Kiln (EU 225 / SV 103)
o Line 4 Rotary Kiln (EU 261 / SV 118)
o Line 5 Rotary Kiln (EU 282 / SV 127)
o Line 6 Rotary Kiln (EU 315 / SV 144)
o Line 7 Rotary Kiln (EU 334 / SV 151)
• External Combustion Sources for NOx (Section 5.B)
o Utility Plant Heating Boiler #1 (EU 001 / SV 001)
o Utility Plant Heating Boiler #2 (EU 002 / SV 002)
o Utility Plant Heating Boiler #4 (EU 004 / SV 004)
o Utility Plant Heating Boiler #5 (EU 005 / SV 005)
5.A Indurating Furnace “Soft” or “green” pellets are oxidized and heat-hardened in the induration furnace. The induration
process involves pellet pre-heating, drying, hardening, oxidation and cooling.
This facility has five grate/kiln induration furnaces, in which the pellets are dried on a grate and then
transferred to a rotary kiln for hardening and oxidation. The pellet hardening and oxidation section of
the induration furnace is designed to operate at 2,400 ºF and higher. This temperature is required to
meet taconite pellet product specifications. Fuel combustion in the induration furnace is carried out at
approximately 15% to 18% oxygen to provide sufficient oxygen for pellet oxidation.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
23
Air is used for combustion, pellet cooling, and as a source of oxygen for pellet oxidation. Due to the
high-energy demands of the induration process, induration furnaces have been designed to recover as
much heat as possible using hot exhaust gases to heat up incoming pellets. Pellet drying and preheat
zones are heated with the hot gases generated in the pellet hardening/oxidation section and the pellet
cooler sections. Each of these sections is designed to maximize heat recovery within process
constraints. The pellet coolers are also used to preheat combustion air so more of the fuel’s energy to
be directed to the process instead of heating ambient air to combustion temperatures.
The five grate/kiln induration furnaces at this facility utilize the following fuels:
• Line 3 Rotary Kiln (EU 225 / SV 103) – natural gas, biomass, and fuel oil
• Line 4 Rotary Kiln (EU 261 / SV 118) – natural gas, biomass, and fuel oil
• Line 5 Rotary Kiln (EU 282 / SV 127) – natural gas, biomass, and fuel oil
• Line 6 Rotary Kiln (EU 315 / SV 144) – natural gas, biomass, fuel oil and coal
• Line 7 Rotary Kiln (EU 334 / SV 151) – natural gas, biomass, fuel oil and coal
Emissions from the induration furnaces are controlled as follows:
• PM / PM10: PM emissions are controlled by a wet scrubbers with water used as the scrubbing
solution. The PM emissions from the indurating furnace are subject to the taconite MACT
standard. are regulated by the Taconite MACT. As addressed in section 3.A, BART will be
presumed to be equivalent to MACT for PM and no further analysis will be required to
establish BART for PM for these sources.
On lines 4, 5, 6 and 7, the water from the scrubber passes through the scrubber once, with
some of the discharge water being used immediately used as process water in the
concentrator with the remainder of the water being discharged to the tailings basin. The wet
scrubbers are designed to remove PM and are considered a high efficiency PM wet scrubbers
and will be evaluated as such within this BART analysis.
The Line 3 wet scrubber was installed after the BART baseline period and started operation
on June 2006. The scrubber is a recirculating scrubber with the scrubber blowdown water
being treated before being discharged to the tailings basin. The wet scrubber is designed to
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
24
remove PM and is considered a high efficiency PM wet scrubber and will be evaluated as
such within this BART analysis. Since the scrubber was installed after the baseline date, the
emissions in the post-BART modeling analysis were adjusted to account for the improved
removal efficiency.
• SO2: SO2 emissions are controlled as collateral SO2 reductions by the existing wet scrubbers.
Therefore, the existing wet scrubbers are considered a low-efficiency SO2 scrubbers and will
be evaluated as such within this BART analysis.
• NOX: NOX is controlled through existing combustion practices and fuel switches (lower NOx
emissions when burning solid fuels). NOX emissions are monitored using NOX continuous
emissions monitoring systems (CEMS).
Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of
the ports is to allow air injection into the pellet bed as it travels down the kiln bed. In March
2002, Minntac submitted a report to MPCA presenting an analysis of the NOX emissions from
Line 7 before and after the installation of the ports. This report is presented in Appendix D.
As described in the report, the NOX emissions from the kiln decreased by approximately 5%
when burning natural gas. However, no emission reduction was noted when burning solid
fuels. When evaluating the use of air injection ports for the reduction of NOX emissions, it is
important to note that solid fuels are typically burned in the furnaces and therefore, the actual
improvement in NOX emissions would be significantly less than 5% estimate.
In April 2006, replacement and reconfigured burners were installed into the preheat section
of Line 6. The burners were installed as an energy efficiency project. However, after
installation of the burners, the emissions from the kiln were evaluated using the data from the
NOx CEMS. This evaluation showed a reduction in NOX emissions from the kiln of
approximately 10% when the preheat section was in operation. Since the low-NOX burners
were installed after the baseline date, the emissions in the post-BART modeling analysis
were adjusted to account for the reduced emissions from Line 6. Additional information
regarding the post-BART modeling is presented in Step 5 of this BART analysis.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
25
5.A.i Sulfur Dioxide Controls
5.A.i.a STEP 1 – Identify All Available Retrofit Control Technologies
Step 1 identifies a comprehensive list of all potential retrofit control technologies that were
evaluated. Many emerging technologies were identified that are not currently commercially
available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the
technology as it was understood at that time. In regards to the availability of the technology with
respect to Step 1 of the BART analysis, the list has not changed from the information submitted at
that time. The comprehensive list of control technologies is presented in Appendix E.
5.A.i.b STEP 2 – Eliminate Technically Infeasible Options
Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As
stated in section 2.B of this document, the technical feasibility of each option is determined by
answering three specific questions:
1. Is the control technology “available” to the specific source which is undergoing the
BART analysis?
2. Is the control technology an “applicable technology” for the specific source which
is undergoing the BART analysis?
3. Are there source-specific issues/conditions that would make the control technology
not technically feasible?
A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the
technology as it was understood at that time. As work on this evaluation progressed, additional
information became apparent regarding the limited scope and scale of some of the technology
applications. Appendix E presents the current status of the availability and applicability of each
technology.
The following section describes retrofit SO2 control technologies that were identified as available and
applicable in the May 9 submittal and discusses aspects of those technologies that determine whether
or not the technology is technically feasible for the indurating furnace.
Wet Walled Electrostatic Precipitator (WWESP)
An electrostatic precipitator (ESP) applies electrical forces to separate suspended particles from the
flue gas stream. The suspended particles are given an electrical charge by passing through a high
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
26
voltage DC corona region in which gaseous ions flow. The charged particles are attracted to and
collected on oppositely charged collector plates. Particles on the collector plates are released by
rapping and fall into hoppers for collection and removal.
A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a dry
ESP and uses a water spray to remove particulate matter from the collection plates. For SO2 removal,
caustic is added to the water spray system, allowing the WWESP spray system to function as an SO2
absorber.
The SO2 control efficiency for a WWESP is dependent upon various process specific variables, such
as SO2 flue gas concentration, fuel used, and ore composition. Since the induration furnaces at this
facility currently employ a wet scrubbers designed for removal of particulate matter, the scrubbers
also perform as low efficiency SO2 wet scrubbers. The addition of a WWESP would act as a
polishing SO2 control device and would experience reduced control efficiency due to lower SO2 inlet
concentrations. A control efficiency as a polishing WWESP ranges from 30-80% dependent upon the
process specific operating parameters.
Based on the definitions contained within this report, a WWESP is considered an available
technology for SO2 reduction for this BART analysis.
Wet Scrubbing (High and Low Efficiency)
Wet scrubbing, when applied to remove SO2, is generally termed flue-gas desulfurization (FGD).
FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting
liquid, to remove SO2 in the waste gas. Crushed limestone, lime, or caustic are typically used as
scrubbing agents. Most FGD wet scrubbers recirculate the scrubbing solution, which minimizes the
wastewater discharge flow. However, higher concentrations of solids exist within the recirculated
wastewater.
For a wet scrubber to be considered a high efficiency SO2 wet scrubber, the scrubber would require
designs for removal efficiency up to 95% SO2. Typical high efficiency SO2 wet scrubbers are packed-
bed spray towers using a caustic scrubbing solution. Whereas, a low efficiency SO2 wet scrubber can
have a control efficiency of 30% or lower. A low efficiency SO2 could be a venturi rod scrubber
design using water as a scrubbing solvent. Venturi rod scrubbers, which are frequently used for PM
control at taconite facilities, will also remove some of the SO2 from the flue gas as collateral
emission reduction.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
27
Limestone scrubbing introduces limestone slurry with the water in the scrubber. The sulfur dioxide is
absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall
reactions are shown in the following equations:
CaCO3 + SO2 → CaSO3 • 1/2 H2O + CO2
CaSO3 •1/2 H2O + 3H2O + O2 → 2 CaSO4 •2 H2O
Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that lime is a
more reactive reagent than limestone. The reactions for lime scrubbing are as follows:
Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O
Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O
When caustic (sodium hydroxide solution) is the scrubbing agent, the SO2 removal reactions are as
follows:
Na+ + OH- + SO2 + → Na2SO3
2Na+ + 2OH- + SO2 + → Na2SO3 + H2O
Caustic scrubbing produces a liquid waste, and requires less equipment as compared to lime or
limestone scrubbers. If lime or limestone is used as the reagent for SO2 removal, additional
equipment is needed for preparing the lime/limestone slurry and collecting and concentrating the
resultant sludge. Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land
filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air
injection blower is needed to supply the oxygen for the second reaction to occur.
The normal SO2 control efficiency range for SO2 scrubbers on coal-fired utility boilers with low
excess air is 80% to 90% for low efficiency scrubbers and 90% to 95% for high efficiency scrubbers.
The highest control efficiencies can be achieved when SO2 concentrations are the highest. Unlike
coal-fired boilers, indurating furnaces operate with maximum excess air to enable proper oxidation of
the pellet. The excess air dilutes the SO2 concentration and creates higher flow rates to control.
Additionally, the varying sulfur concentration within the ore causes fluctuations of the SO2
concentrations in the exhaust gas stream. This could also impact the SO2 control efficiency of the
wet scrubber.
As previously stated, wet scrubbers are currently in place on the furnaces exhausts and are believed
to remove 15% to 30% of the SO2 in the exhaust based on Barr’s experience and testing which has
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
28
been completed. Taking into consideration the removal of SO2 from the low-efficiency primary PM
scrubber as well as a high efficiency SO2 polishing wet scrubber, an estimated overall efficiency of
the control train would then be approximately 80%.
In theory, the SO2 removal efficiency of the existing scrubbers could be improved through the
additions of caustic, lime, or limestone in the scrubber water to raise the pH. The existing scrubber
on lines 4-7 currently operates at approximately a neutral pH. However, the scrubbers, piping,
pumps and water tanks were not designed to operate at a higher pH so corrosion of the system would
be a concern. The addition of the chemicals and increased SO2 removal would create additional
solids and sulfates in the scrubber discharged to the tailings basin which would require substantial
and expensive treatment to maintain an acceptable water quality which could be discharged through
the existing NPDES permit. The new scrubber on Line 3 is a recirculating scrubber which operates
at a pH which is typically less than 7. The scrubber was operated temporarily at a higher pH, but
plugging and other operational problems resulted and the scrubber was returned to the current
operating pH. Based on these concerns, the improvement of SO2 removal efficiency of the existing
scrubbers is not a practical solution and is not considered further in this report.
Based on the information contained within this report, a wet scrubber is considered an available
technology for SO2 reduction for this BART analysis.
Dry Sorbent Injection (Dry Scrubbing Lime/Limestone Injection)
Lime/limestone injection is a post-combustion SO2 control technology in which pulverized lime or
limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO2 onto the
lime or limestone particle occurs and the solid particles are collected with a fabric filter. Further SO2
removal occurs as the flue gas flows through the filter cake on the bags. The normal SO2 control
efficiency range for dry SO2 scrubbers is 70% to 90 % for coal fired utility boilers.
Induration waste gas streams are high in water content and are exhausted at or near their dew points.
Gases leaving the induration furnace are currently treated for removal of particulate matter using a
wet scrubber. The exhaust temperature is typically in the range of 100°F to 150°F and is saturated
with water. For comparison, a utility boiler exhaust operates at 350 °F or higher and is not saturated
with water. Under induration furnace waste gas conditions, the baghouse filter cake would become
saturated with moisture and plug both the filters and the dust removal system. Although this may be
an available and applicable control option, it is not technically feasible due to the high moisture
content and will not be further evaluated in this report.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
29
Spray Dryer Absorption (SDA)
Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is
absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water
evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the
gas and collected with a fabric filter. When used to specifically control SO2, the term flue-gas
desulfurization (FGD) may also be used.
Under induration furnace waste gas conditions, the baghouse filter cake would become saturated with
moisture and plug both the filters and the dust removal system. In addition, because of the moisture
in the exhaust, the lime slurry would not dry properly and it would plug up the dust collection
system. Similarly to the dry sorbent injection control option, this is an available and applicable
control option, but is not technically feasible due to the high moisture content. This option will not
be further evaluated in this report.
Energy Efficiency Projects
Energy efficiency projects provide opportunities for a facility to reduce their fuel consumption,
which results in lower operating costs. Typically reduced fuel usage translates into reduced air
emissions. An example of an energy efficiency project would be to use waste heat to preheat
incoming make-up air or pellet feed. Each project is very dependent upon the fuel usage, process
equipment, type of product and many other variables.
Due to the increased price of fuel, this facility has already implemented several energy efficiency
projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission
reductions. It would be impossible to assign a general potential emission reduction for the energy
efficient category. Due to the uncertainty and generalization of this category, this will not be further
evaluated in this report. However, it should be noted that the facility will continue to evaluate and
implement energy efficiency projects as they arise.
Alternate Fuels
As described within the energy efficiency description, increased price of fuel has pushed taconite
facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources.
These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO2 emissions
through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal,
and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one
visibility impairment pollutant (SO2) for another (NOx), as induration furnaces typically emit
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
30
significantly less NOx when burning solid fuels. Therefore, if this option is pursued, the impact on
emissions of all visibility pollutants must be quantified and the cumulative visibility impact modeled
to determine the net benefit of a particular alternative fuel.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.21
Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility
impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative
fuels as an air pollution control technology will not be further evaluated in this report.
However, similar to energy efficiency, the facility will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
Coal Processing
Pre-combustion coal processing techniques have been proposed as one strategy to reduce
uncontrolled SO2 emissions. Coal processing technologies are being developed to remove moisture
and potential contaminants from the coal prior to use.
These processes typically employ both mechanical and thermal means to increase the quality of coal
by removing moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine
enters a first stage separator where it is crushed and screened to remove large rock and rock
material.22 The processed coal is then passed on to an intermediate storage facility prior to being sent
to the next stage in the process, the thermal process. In this stage, coal passes through pressure locks
into the thermal processors where steam is injected. Moisture in the coal is released under these
conditions. Mineral inclusions are also fractured under thermal stress, removing both included rock
and sulfur-bearing pyrites. After treatment, the coal is discharged into a second pressurized lock.
The second pressurized lock is vented into a water condenser to return the processor to atmospheric
pressure and to flash cool the coal. Water, removed from the process at various points, and
condensed process steam are reused within the process or treated prior to being discharged.
21 Federal Register 70, no. 128 (July 6, 2005): 39164
22 The coal processing description provided herein is based on the K-Fuel® process under development by KFx, Inc.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
31
To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coal-
fired boiler. Using processed fuels at a taconite plant would require research, test burns, and
extended trials to identify potential impacts on plant systems, including the furnaces, material
handling, and emission control systems. Therefore, processed fuels are not considered commercially
available, and will not be analyzed further in this BART analysis.
Coal drying is currently being explored at a coal-fired utility in North Dakota as a potential viable
option a pre-combustion control for SO2 reduction. In the process, raw coal is crushed and screened
to remove rocks and other impurities, such as pyretic sulfur. The crushed coal is then thermally
processed to remove excess moisture. For this option to be viable, excess heat or low pressure steam
must be available to dry the coal. Since this heat source is not available at this facility, coal drying is
not feasible and will not be further evaluated in this report.
Step 2 Conclusion
Based upon the determination within Step 2, the remaining SO2 control technologies that are
available and applicable to the indurating furnace process are identified in Table 5-1. The technical
feasibility as determined in Step 2 is also included in Table 5-1.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
32
Table 5-1 Indurating Furnace SO2 Control Technology – Availability, Applicability, and Technical Feasibility
Step 1 Step 2
SO2 Pollution Control Technology Is
th
is a
g
en
era
lly
a
va
ila
ble
co
ntr
ol
tec
hn
olo
gy
?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
va
ila
ble
to
in
du
rati
ng
fu
rna
ce
s?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
pp
lic
ab
le t
o t
his
s
pe
cif
ic s
ou
rce
?
Is i
t te
ch
nic
all
y
fea
sib
le f
or
this
s
ou
rce
?
Wet Walled Electrostatic Precipitator (WWESP)
Y Y Y Y
Secondary Wet Scrubber Y Y Y Y
Modifications to Existing Wet Scrubbing (Low Efficiency)
Y Y N N
Dry Sorbent Injection Y Y Y N
Spray Dry Absorption Y Y Y N
Energy Efficiency Projects Y Y Y N
Alternative Fuels Y Y Y
N
(not required by BART)
Coal Processing Y Y Y N
5.A.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-2 describes the expected control efficiency from each of the remaining feasible control
options. WWESP and wet scrubbing control options listed in Table 5-2 would be considered
polishing control devices since wet scrubber currently operate as primary control.
Table 5-2 Indurating Furnace SO2 Control Technology Effectiveness
SO2 Pollution Control Technology Approximate Control Efficiency
Wet Walled Electrostatic Precipitator (WWESP) 80%
Secondary Wet Scrubber 60%
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
33
5.A.i.d STEP 4 – Evaluate Impacts and Document the Results
As illustrated in Table 5-2 above, the technically feasible control technologies remaining provide
varying levels of emission reduction. Therefore, it is necessary to consider the economic, energy,
and environmental impacts to better differentiate as presented below.
Economic Impacts
Table 5-3 details the expected costs associated with installation of a secondary wet scrubber or a wet
walled electrostatic precipitator (WWESP) after the existing scrubber on each stack. Equipment
design was based on the maximum 24-hour emissions, vendor estimates, and U.S. EPA cost models.
Capital costs were based on recent vendor quotations. The cost for that unit was scaled to each
stack’s flow rate using the 6/10 power law as shown in the following equation:
Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6
Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S.
EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours
per year (EPA default value). Operating costs of consumable materials, such as electricity, water, and
chemicals were established based on the U.S. EPA control cost manual23 and engineering experience,
and were adjusted for the specific flow rates and pollutant concentrations.
Due to space considerations, 60% of the total capital investment was included in the costs to account
for a retrofit installation.24 After discussions with facility staff and management, it was determined
the space surrounding the furnaces is congested and the area surrounding the building supports
vehicle and rail traffic to transport materials to and from the building. Additionally, the structural
design of the existing building would not support additional equipment, such as an SO2 scrubber or
WWESP, on the roof. Therefore, the cost estimates provide for additional site-work and construction
costs to accommodate the new equipment within the facility. A site-specific estimate for site work,
foundations, and structural steel was added to arrive at the total retrofit installed cost of the control
technology. The site specific estimate was based on recent actual retrofit costs for installation of a
secondary wet scrubber at the facility. The detailed cost analysis is provided in Appendix A.
23 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition. 24 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
34
Table 5-3 Indurating Furnace SO2 Control Cost Summary
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
35
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 rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant25.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The cost of SO2 control for both of the technically feasible technologies is greater than $12,000 per
ton of pollutant removed. This cost is higher than the MPCA-directed annualized cost screening
level and is far in excess of any cost that is considered to be cost effective for BART. Therefore,
these alternatives are removed from further consideration in this analysis.
Energy and Environmental Issues
Because the cost of SO2 controls for Minntac is so high and does not meet a reasonable definition of
cost effective technology, these alternatives are removed from further consideration in this analysis.
5.A.i.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
25 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
36
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document. Because the cost of SO2 controls is so high and does not meet a reasonable definition of
cost effective technology, visibility impacts were not modeled for SO2.
However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline
period and started operation on June 2006. The scrubber is considered a high efficiency scrubber for
PM and a low efficiency scrubber for SO2. Since the scrubber was installed after the baseline date,
the emissions in the post-BART modeling analysis must be adjusted to account for the improved
removal efficiency. Also as previously stated, replacement and reconfigured burners were installed
into the preheat section of Line 6 on April 2006 which reduced the NOX emissions from the kiln of
approximately 10% when the preheat section was in operation. Since the low-NOX burners were
installed after the baseline date, the emissions in the post-BART modeling analysis must also be
adjusted to account for the reduced emissions from Line 6. Therefore, the visibility impacts
modeling presented in this section represent the post-baseline (i.e. post-BART) current operations of
the facility.
Predicted 24-Hour Maximum Emission Rates
Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts,
the post-BART emissions to be used for the visibility impacts analysis should also reflect a
maximum 24-hour average projected emission rate. In the visibility impacts modeling analysis, the
emissions from the Line 3 indurating furnaces were adjusted to account for the new wet scrubber and
the emissions from the Line 6 indurating furnace was adjusted to account for replacement and
reconfigured low-NOx burners which have been installed in the preheat section. The emissions from
all other Subject-to-BART sources were not changed. Table 5-4 provides a summary of the modeled
SO2, NOX, and PM 24-hour maximum emission rates for the post-baseline (i.e. post-BART) current
operations. Similar to the modeling for the baseline or pre-BART operating conditions, modeling
was conducted for two separate operating scenarios for fuel burning in the kiln: (1) burning natural
gas and (2) burning solid fuel. It is important to note that natural gas is the only fuel that is burned in
the preheat section of the kiln. The stack parameters (location, height, velocity, and temperature)
were assumed to remain unchanged from the baseline modeling.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
37
Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
38
Post-BART Visibility Impacts Modeling Results
Results of the post-BART visibility impacts modeling for current operations are presented in Table
5-5. The results summarize 98th percentile dV value and the number of days the facility contributes
more than a 0.5 dV of visibility impairment at each of the Class I areas.
As illustrated in tables 5-5, the current operation of the facility results in a visibility improvement of
0.196 dV when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln.
Both of these values represent a 3% improvement compared to the baseline or pre-BART emissions.
A summary of visibility impacts for the total facility BART analysis are presented in Section 6.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
39
Table 5-5 Indurating Furnace Post-BART SO2 Modeling Scenarios - Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
40
5.A.ii Nitrogen Oxide Controls
To be able to control NOx it is important to understand how NOx is formed. There are three
mechanisms by which NOx production occurs:
• Fuel bound nitrogen compounds in the fuel are oxidized in the combustion process to NOx.
• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen
molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.
Thermal NOx production is a function of the residence time, free oxygen, and temperature.
• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the
result of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NOx are emitted as prompt NOx.
The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the heater, the balance
of NO2 is formed in the atmosphere when NO reacts with oxygen in the air.
5.A.ii.a STEP 1 – Identify All Available Retrofit Control Technologies
Step 1 identifies a comprehensive list of all potential retrofit control technologies that were
evaluated. Many emerging technologies were identified that are not currently commercially
available. A preliminary list of technologies was submitted to MPCA on May 9 with the status of the
technology as it was understood at that time. In regards to the availability of the technology with
respect to Step 1 of the BART analysis, the list has not changed from the information submitted at
that time. The comprehensive list of control technologies is presented in Appendix E.
5.A.ii.b STEP 2 – Eliminate Technically Infeasible Options
Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As
stated in section 2.B of this document, the technical feasibility of each option is determined by
answering three specific questions:
1. Is the control technology “available” to the specific source which is undergoing the
BART analysis?
2. Is the control technology an “applicable technology” for the specific source which
is undergoing the BART analysis?
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
41
3. Are there source-specific issues/conditions that would make the control technology
not technically feasible?
A preliminary list of technologies was submitted to MPCA on May 9, 2006 with the status of the
technology as it was understood at that time. As work on this evaluation progressed, additional
information became apparent regarding the limited scope and scale of some of the technology
applications. Appendix E presents the current status of the availability and applicability of each
technology.
The following section describes retrofit NOx control technologies that were identified as available
and applicable in the May 9 submittal and discusses aspects of those technologies that determine
whether or not the technology is technically feasible for the indurating furnace.
External Flue Gas Recirculation (EFGR)
External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures
thereby reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is
collected from the heater or stack and returned to the burner via a duct and blower. The flue gas is
mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas
reduces the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen
level in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. For
this technology to be effective, the combustion conditions must have the ability to be controlled at
the burner tip.
The typical NOx control efficiency range for EFGR on a boiler is 30% to 50%.
Application for EFGR technology in taconite induration is problematic for three reasons:
1. The process exhaust gas in an induration furnace has approximately 15% - 18% oxygen
versus a boiler which has 2% - 3% oxygen. In a boiler, the flue gas is relatively inert so
it can be used as a diluent for oxygen for flame temperature reduction. Taconite waste
gas has much higher oxygen level; thus use of taconite waste gas for EFGR would be
equivalent to adding combustion air instead of an inert gas.
2. The oxidation zone of induration furnaces needs to be above 2,400oF in order to meet
product specifications. Existing burners are designed to meet these process conditions.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
42
Application of EFGR would reduce flame temperatures. Lower flame temperatures
would reduce furnace temperatures to the point that product quality could be jeopardized.
3. Application of EFGR technology increases flame length. Dilution of the combustion
reactants increases the reaction time needed for fuel oxidation to occur; so, flame length
increases. Therefore, application of EFGR could result in flame impingement on furnace
components. That would subject those components to excessive temperatures and cause
equipment failures.
Although this may be an available and applicable control option, it is not technically feasible due to
the high oxygen content of the flue gas and will not be further evaluated in this report.
Low-NOx Burners
Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through
the restriction of oxygen, flame temperature, and/or residence time. LNB is typically a staged
combustion process that is designed to split fuel combustion into two zones, primary combustion and
secondary combustion. This analysis utilizes the staged fuel design in the cost analysis because lower
emission rates can be achieved with staged fuel burner than with a staged air burner.
In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high
fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx formation. In
the secondary combustion zone, incomplete combustion products formed in the primary zone act as
reducing agents. In a reducing atmosphere, nitrogen compounds are preferentially converted to
molecular nitrogen (N2) over nitric oxide (NO).
If LNB were to be applied in the indurating section of the furnace, the reduced flame temperatures
associated with LNB would adversely affect taconite pellet product quality. In addition, the oxygen
concentration cannot be controlled at the burner tip in the induration section of the furnace.
Therefore, LNB is not feasible in the induration section of the permit.
However, the use LNB in the pre-heat section of the furnace is feasible and NOx reductions could be
credited for that section of the furnace. However, the NOx emissions from the pre-heat section
cannot be measured separately from the total furnace NOx emissions, so the actual emission reduction
from the burners is unknown. However, in April 2006 replacement and reconfigured burners were
installed into the preheat section of Line 6. The burners were installed as an energy efficiency
project. After installation of the burners, the emissions from the kiln were evaluated using the data
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
43
from the NOx CEMS. This analysis showed a reduction in NOX emissions from the kiln of
approximately 10% when the preheat section was in operation. Based on this information, a 10%
reduction was assumed for the installation of low-NOx burners on the preheat sections of lines 4, 5,
and 7 (Line 3 does not currently use burners in the preheat section). However, due to differences in
design and operation of the various kilns, the 10% reduction should only be treated as an estimate as
the actual emissions reduction would not be known until after installation and testing. Low-NOx
burners will be considered an available and applicable technology for lines with preheat sections.
It is also important to note that there are other methods being developed for low NOx burners which
are not yet commercially available. Some incorporate various fuel dilution techniques to reduce
flame temperatures; such as mixing an inert gas like CO2 with natural gas. Water injection to cool
the burner peak flame temperature was also being investigated. This technique has already been
successfully used for reducing NOx emissions from gas turbines. The water injection technique
shows promise for high temperature applications, but will not be further investigated in this report as
the technology is still in the research and development phase.
Induced Flue Gas Recirculation Burners
Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of
flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue
gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel
combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR
burners in high temperature applications is 25-50%.
As previously noted, taconite furnaces are designed to operate with oxygen levels of approximately
15% to 18%. At these oxygen levels, flue gas recirculation is ineffective at NOx reduction, and it
would adversely affect combustion because excessive amounts of oxygen would be injected into the
flame pattern. In addition, IFGR relies on convective flow of flue gas through the burner and
requires burners to be up-fired; meaning that the burner is mounted in the furnace floor and the flame
rises up. Furthermore, IFGR is not feasible in the kiln because the reduced flame temperatures
associated with IFGR could adversely affect taconite pellet product quality.
Although this may be an available and applicable control option, it is not technically feasible due to
the high oxygen content of the flue gas and will not be further evaluated in this report.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
44
Energy Efficiency Projects
Energy efficiency projects provide opportunities for a facility to reduce their fuel consumption,
which results in lower operating costs. Typically reduced fuel usage translates into reduced pollution
emissions. An example of an energy efficiency project could be to preheat incoming make-up air or
pellet feed. Each project is very dependent upon the fuel usage, process equipment, type of product
and many other variables.
Due to the increased price of fuel, this facility has already implemented several energy efficiency
projects. Each project carries its own fuel usage reductions and, potentially, corresponding emission
reductions. It would be impossible to assign a general potential emission reduction for the energy
efficient category. Due to the uncertainty and generalization of this category, this will not be further
evaluated in this report. However, it should be noted that the facility will continue to evaluate and
implement energy efficiency projects as they arise.
Ported Kilns
Ported kilns are rotary kilns that have air ports installed at specified points along the length of the
kiln. The purpose of the ports is to allow air injection into the pellet bed as it travels down the kiln
bed. Ports are installed about the circumference of the kiln. Each port is equipped with a closure
device that opens when it is at the bottom position to inject air in the pellet bed, and closed when it
rotates out of position. The purpose of air injection is to provide additional oxygen for pellet
oxidation. The oxidation reaction extracts enough heat to offset the heat loss associated with air
injection. Air injection reduces the overall energy use of the kiln and produces a higher quality
taconite pellet. Air injection also prevents carry over of the oxidation reaction into the pellet coolers.
Air injection ports were installed on the kilns on Line 7 in 2001 and Line 6. The purpose of the ports
is to allow air injection into the pellet bed as it travels down the kiln bed. In March 2002, Minntac
submitted a report to MPCA presenting an analysis of the NOX emissions from Line 7 before and
after the installation of the ports. This report is presented in Appendix D. As described in the report,
the NOX emissions from the kiln decreased by approximately 5% when burning natural gas.
However, no emission reduction was noted when burning solid fuels. When evaluating the use of air
injection ports for the reduction of NOx emissions, it is important to note that solid fuels are typically
burned in the furnaces and therefore, the actual improvement in NOX emissions would be
significantly less than 5% estimate.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
45
Alternate Fuels
As described within the energy efficiency description, increased price of fuel has pushed taconite
facilities to reduce fuel costs. One option for reducing fuel costs is to evaluate alternate fuel sources.
These fuel sources come in all forms – solid, liquid and gas. To achieve reduction of SO2 emissions
through alternative fuel usage, the source must be currently burning a high-sulfur fuel, typically coal,
and would switch to a lower-sulfur fuel such as natural gas. However, a fuel switch would trade one
visibility impairment pollutant (SO2) for another (NOx), as induration furnaces typically emit
significantly less NOx when burning solid fuels. Therefore, if this option is pursued, the impact on
emissions of all visibility pollutants must be quantified and the cumulative visibility impact modeled
to determine the net benefit of a particular alternative fuel.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.26
Therefore, due to the uncertainty of alternative fuel costs, the potential of replacing one visibility
impairment pollutant for another, and the fact that BART cannot mandate a fuel switch, alternative
fuels as an air pollution control technology will not be further evaluated in this report.
However, similar to energy efficiency, the facility will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
Process Optimization with NOx CEMS or Other Parametric Monitoring
MPCA guidance lists “NOx CEMS” as a work practice/operational change for controlling NOx
emissions27. Based on conversations with MPCA staff, this work practice would include process
adjustments, or optimization, to minimize NOx emissions. The impact of the process adjustments
would be measured using the NOx CEMS. If NOx CEMS are not installed, it may also be possible to
measure the impact of the process changes using parametric monitoring.
As part of the negotiation of the draft PSD permit, Minntac has installed NOx CEMS on all five
indurating furnaces. The use of the NOx CEMS has resulted in lower emissions being reported in the
annual emissions inventory. However, this decrease may be due to having actual emission data
available for the report rather than using the emissions from stack tests which were conducted at
26 Federal Register 70, no. 128 (July 6, 2005): 39164
27 MPCA. March 2006. Guidance for Facilities Conducting a BART Analysis. Page 4.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
46
worst-case operating conditions. In addition, the NOx CEMS has allowed Minntac to quantify the
emissions rates for all fuel combinations.
Although the NOx CEMS has allowed the facility to use better data for reporting, the facility has not
yet identified specific operating parameters which can be controlled to reduce emissions without
sacrificing unit efficiency or product quality.
Based upon this information, there is no indication that further emission reductions would be
achieved through the use of the process optimization, using NOx CEMS as a control technology.
Therefore, process optimization as a control option will not be evaluated further in this report.
Post Combustion Controls
NOx can be controlled using add-on systems located downstream of the furnace area of the
combustion process. The two main techniques in commercial service include the selective non
catalytic reduction (SNCR) process and the selective catalytic reduction (SCR) process. There are a
number of different process systems in each of these categories of control techniques.
In addition to these treatment systems, there are a large number of other processes being developed
and tested on the market. These approaches involve innovative techniques of chemically reducing,
absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives
are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these
alternatives are described below.
Non-Selective Catalytic Reduction (NSCR)
A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied
primarily in natural gas combustion applications.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
47
NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx,
unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx
emission reductions of 90 percent. In order to operate properly, the combustion process must be near
stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO,
resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal
are:
2CO + 2NO → 2CO2 + N2 (1)
[UBH] + NO → N2 + CO2 + H2O (2)
NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part
to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to the
indurating furnace. In addition, we are not aware of any NSCR installations on taconite induration
furnaces or similar combustion equipment. Therefore, this technology will not be further evaluated in
this report.
Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction
SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue
gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:
4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)
A catalyst bed containing metals in the platinum family is used to lower the activation energy
required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a
normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to
become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and
corrosion problems. A high temperature zeolite catalyst is also available; it can operate in the 600 °F
to 1000°F temperature range. However, these catalysts are very expensive.
Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia
increases during load changes due to the instability of the temperature in the catalyst bed as well as at
low loads because of the low gas temperature.
Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR)
control process as described below with a preheat process step to reheat the flue gas stream up to
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
48
SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink
(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR
and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the
preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow
alternates between vessels. Each of the vessels alternates between preheating/treating and heat
recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95%
versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to
70%.
To date, RSCR has been applied to wood-fired utility boilers. Application of this technology has not
been applied to taconite induration furnaces, to airflows of the magnitude of taconite furnace
exhausts, nor to exhaust streams with similar, high moisture content. Using RSCR at a taconite plant
would require research, test runs, and extended trials to identify potential issues related to catalyst
selection, and impacts on plant systems, including the furnaces and emission control systems. It is
not reasonable to assume that vendor guarantees of performance would be forthcoming in advance of
a demonstration project. The timeline required to perform such a demonstration project would likely
be two years to develop and agree on the test plan, obtain permits for the trial, commission the
equipment for the test runs, perform the test runs for a reasonable study period, and evaluate and
report on the results. The results would not be available within the time window for establishing
emission limits to be incorporated in the state implementation plan (SIP) by December 2007.
There are several concerns about the technical feasibility and applicability of SCR on an indurating
furnace:
• The composition of the indurating furnace flue gas is significantly different from the
composition of the flue gas from the boilers that utilize SCR;
• The taconite dust is highly erosive and can cause significantly equipment damage. R-SCR
has a number of valves which must be opened and closed frequently to switch catalyst/heat
recovery beds. These valves could be subject to excessive wear in a taconite application due
to the erosive nature of the taconite dust;
• SCR has not been applied downstream of a wet scrubber. Treating a stream saturated with
water may present design problems in equipment sizing for proper heat transfer and in
corrosion protection;
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
49
• SCR catalyst had been shown to oxidize mercury. Oxidized mercury can be absorbed by the
local environment and have adverse impact. The impact of SCR on mercury emissions needs
to be studied to determine whether or not mercury oxidation is a problem and to identify
mitigation methods if needed.
Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to
learn how to apply a control technology to a completely new and significantly different source type.
Therefore, RSCR is not considered to be technically feasible, and will not be analyzed further in this
BART analysis.
However, SCR with reheat through a conventional duct burner (rather than using a regenerative
heater) has been successfully implemented more widely and in higher airflow applications and will
be carried forward in this analysis as available and applicable technology that is reasonably expected
to be technically feasible.
Low Temperature Oxidation (LTO)
The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2,
and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas
(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium
hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The
nitrates are removed from the scrubbing system and discharged to an appropriate water treatment
system. Commercially available LTO systems include Tri-NOx® and LoTOx®.
NO + O3 → NO2 + O2 (1)
NO2 + O3 → NO3 + O2 (2)
NO3 + NO2 → N2O5 (3)
N2O5 + H2O → 2HNO3 (4)
HNO3 + NaOH → NaNO3 + H2O (5)
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
50
Low Temperature Oxidation (Tri-NOx®)
This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a
primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:
O3 + NO → O2 + NO2 (1)
2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)
Tri-NOx® is a multi-staged wet scrubbing process in industrial use. Several process columns, each
assigned a separate processing stage, are involved. In the first stage, the incoming material is
quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent
stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Another possible
advantage of the Tri-NOx® process is that concurrent scrubbing of sulfuric acid mist can be achieved.
Tri-NOx® is typically applied at small to medium sized sources with high NOx concentration in the
exhaust gas (1,000 ppm NOx). NOx concentrations in taconite exhaust are typically no higher than
300 ppm. Therefore, Tri-NOx® is not applicable to taconite processing and will not be analyzed
further in this BART analysis.
Low Temperature Oxidation (LoTOx®)
BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone
to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same
scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a
scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an
electrically powered ozone generator. The ozone generation rate is controlled to match the amount
needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be
economically feasible, a source of low cost oxygen must be available from a pipeline or on site
generation.
The first component of the technical feasibility review includes determining if the technology would
apply to the process being reviewed. This would include a review and comparison of the chemical
and physical properties required. Although it appears that the chemistry involved in the LTO
technology applies to an indurating furnace, the technology has not been demonstrated on a taconite
pellet indurating furnace. This raises uncertainties about how or whether the technology will
transfer. The second component of the technical feasibility review includes determining if the
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
51
technology is commercially available. Evaluations of LTO found that it has only been applied to
small to medium sized coal or gas fired boiler applications, and has never been demonstrated on a
large-scale facility. For example, the current installations of LoTOx® are on sources with flue gas
flow rates from 150 – 35,000 acfm, which is quite small, compared to the indurating furnace flue gas
flow rates of more than 500,000 acfm. This large scale-up is contrary to good engineering practices
and could be problematic in maintaining the current removal efficiencies.
In addition, only two of BOC’s LoTOx® installations are fully installed and operational applications.
Therefore, although this is an emerging technology, the limited application means that it has not been
demonstrated to be an effective technology in widespread application.
There are several other concerns about the technical feasibility and applicability of LTO on an
indurating furnace:
• The composition of the indurating furnace flue gas is significantly different than the
composition of the flue gas from the boilers and process heaters that utilize LTO;
• The taconite dust in the flue gas is primarily magnetite (Fe3O4) which would react with the
ozone to form hematite (Fe2O3); since the ozone injection point would be before the scrubber,
there can be more than 400 pounds per hour of taconite dust in the flue gas which could
consume a significant amount of the ozone being generated which may change the reaction
kinetics; consequently, this would necessitate either an increase in the amount of ozone
generated or a decrease in the estimated control efficiency;
• The ozone that would be injected into the flue gas would react with the SO2, converting the
material to SO3 which could result in the generation of sulfuric acid mist from the scrubber;
• Since LTO has not been installed at a taconite plant, it is likely that the application of LTO to
an indurating furnace waste gas could present technical problems which were not
encountered, or even considered, in the existing LTO applications;
• An LTO system at a taconite facility would also be a source of nitrate discharge to the
tailings basin which would change the facility water chemistry which could cause operational
problems and would likely cause additional problems with National Pollutant Discharge
Elimination System (NPDES) discharge limits and requirements.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
52
In addition, application of this technology has not been applied to taconite induration furnaces, to
airflows of the magnitude of taconite furnace exhausts, nor to exhaust streams with similar, high
moisture content. Using LTO at a taconite plant would require research, test runs, and extended trials
to identify potential issues related to design for high airflows and impacts on plant systems, including
the furnaces and emission control systems. It is not reasonable to assume that vendor guarantees of
performance would be forthcoming in advance of a demonstration project. The timeline required to
perform such a demonstration project would likely be two years to develop and agree on the test
plan, obtain permits for the trial, commission the equipment for the test runs, perform the test runs
for a reasonable study period, and evaluate and report on the results. The results would not be
available within the time window for establishing emission limits to be incorporated in the state
implementation plan (SIP) by December 2007.
Recalling U.S. EPA’s intention regarding “available” technologies to be considered for BART, as
mentioned in Section 2.B, facility owners are not expected to undergo extended trials in order to
learn how to apply a control technology to a completely new and significantly different source type.
Consequently, the technical feasibility of LTO on an indurating furnace is technically infeasible for
this application and will not be evaluated further.
Step 2 Conclusion
Based upon the determination within Step 2, the remaining NOx control technologies that are
available and applicable to the indurating furnace process are identified in Table 5-4. The technical
feasibility as determined in Step 2 is also included in Table 5-6.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
53
Table 5-6 Indurating Furnace NOx Control Technology – Availability, Applicability, and Technical Feasibility
Step 1 Step 2
SO2 Pollution Control Technology Is
th
is a
g
en
era
lly
a
va
ila
ble
co
ntr
ol
tec
hn
olo
gy
?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
va
ila
ble
to
in
du
rati
ng
fu
rna
ce
s?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
pp
lic
ab
le t
o t
his
s
pe
cif
ic s
ou
rce
?
Is i
t te
ch
nic
all
y
fea
sib
le f
or
this
s
ou
rce
?
External Flue Gas Recirculation (EFGR)
Y Y N ---
Low-NOx Burners Y Y
Y
(preheat section)
Y
Induced Flue Gas Recirculation Burners
Y Y N ---
Energy Efficiency Projects Y Y Y N
Ported Kilns Y Y Y Y
Alternative Fuels Y Y N
N
(not required by BART)
Process Optimization using
NOx CEMS Y Y Y N
Non-Selective Catalytic Reduction (NSCR)
Y N --- ---
Selective Catalytic Reduction (SCR) with conventional reheat
Y Y Y Y
Regenerative SCR Y N --- ---
Selective Non-Catalytic Reduction (SNCR)
Y N --- ---
Low Temperature Oxidation (LTO)
Y N --- ---
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
54
5.A.ii.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-7 describes the expected control efficiency from each of the remaining technically feasible
control options as identified in Step 2.
Table 5-7 Indurating Furnace NOx Control Technology Effectiveness
NOx Pollution Control Technology
Approximate Control Efficiency
SCR with Conventional Reheat
80%
Low-NOx Burners 10%
Ported Kilns 5%
5.A.ii.d STEP 4 – Evaluate Impacts and Document the Results
Table 5-8 details the expected costs associated with installation of SCR with conventional reheat, low
NOx burners, ported kilns, and a combination of low-NOx burners and ported kilns.
Equipment design was based on the maximum 24-hour emissions, vendor estimates (when available),
and U.S. EPA cost models. Capital costs were based on a recent vendor quotation. The cost for that
unit was scaled to each stack’s flow rate using the 6/10 power law as shown in the following
equation:
Cost of equipment A = Cost of equipment B * (capacity of A/capacity of B)0.6
Direct and indirect costs were estimated as a percentage of the fixed capital investment using U.S.
EPA models and factors. Operating costs were based on 93% utilization and 7946 operating hours
per year. Operating costs of consumable materials, such as electricity, water, and chemicals were
established based on the U.S. EPA control cost manual28 and engineering experience, and were
adjusted for the specific flow rates and pollutant concentrations.
28 U.S. EPA, January 2002, EPA Air Pollution Control Cost Manual, Sixth Edition.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
55
Table 5-8 Indurating Furnace NOx Control Cost Summary
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
56
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 rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant30.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
29 U.S. EPA, CUE Cost Workbook Version 1.0. Page 2. 30 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
57
The cost of NOx control for using SCR with conventional reheat is far in excess of any cost that is
considered to be cost effective for BART, or even for BACT. Therefore, this technology is not
carried forward in the analysis. The costs for ported kilns, low-NOx burners, and ported kilns with
low-NOx burners, where appropriate, are below the MPCA recommended screening threshold of
$12,000 per ton, and therefore are carried forward in the BART analysis.
Energy and Environmental Issues
The energy and non-air quality impacts for ported kilns, low-NOx burners, and ported kilns with low-
NOx burners, where appropriate, are presented in Table 5-9.
Table 5-9 Indurating Furnace NOx Control Technology Impacts Assessment
Control Technology Energy Impacts Other Impacts
Ported Kilns • None • None
Low-NOx Burners • Improved efficiency of preheat section
• None
Ported Kilns with
Low-NOx Burners • Improved efficiency
of preheat section • None
5.A.ii.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document.
However, as previously stated, a new scrubber was installed on Line 3 after the BART baseline
period and started operation in June 2006. The scrubber is considered a high efficiency scrubber for
PM and a low efficiency scrubber for SO2. Since the scrubber was installed after the baseline date,
the emissions in the post-BART modeling analysis must be adjusted to account for the improved
removal efficiency. Also as previously stated, replacement and reconfigured burners were installed
into the preheat section of Line 6 which reduced the NOX emissions from the kiln of approximately
10% when the preheat section was in operation. Since the low-NOX burners were installed after the
baseline date, the emissions in the post-BART modeling analysis must also be adjusted to account for
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
58
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-NOx burners which have been installed in the preheat section.
• The emissions during current operations for all indurating furnaces were adjusted for each
control technology, as appropriate; and
• The emissions from all other Subject-to-BART sources were not changed.
Table 5-10 provides a summary of the modeled SO2, NOX, and PM 24-hour maximum emission rates
for the post-baseline (i.e. post-BART) current operations.
Post-BART Visibility Impacts Modeling Results
Results of the post-BART visibility impacts modeling for current operations are presented in Table
5-11. The results summarize 98th percentile dV value and the number of days the facility contributes
more than a 0.5 dV of visibility impairment at each of the Class I areas. As illustrated in tables 5-11,
post-BART modeled visibility improvements are as follows:
• The current operation of the facility results in a visibility improvement of 0.196 dV when
burning natural gas in the kiln and 0.188 dV when burning solid fuels in the kiln. Both of
these values represent a 3% improvement compared to the baseline emissions.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
59
• The installation of ported kilns on lines 3, 4, and 5 could result in a visibility improvement of
0.330 dV when burning natural gas in the kiln, which represents a 5% improvement from the
baseline when burning natural gas in the kiln. Since ported kilns do not reduce emissions
when burning solid fuels, there is no additional visibility improvement for that scenario
compared to current operations. It is very important to note that normal operation of the
indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no
improvement in visibility for ported kilns under normal operation.
• The installation of low-NOx burners on the preheat sections of lines 4, 5, and 7 results in a
visibility improvement of 0.488 dV when burning natural gas in the kiln, and 0.465 dV when
burning solid fuels in the kiln. Both of these values represent a 7% improvement compared
to the baseline emissions.
• The combined installation of ported kilns on lines 3, 4, and 5 and low-NOx burners on lines 4,
5, and 7 results in a visibility improvement of 0.627 dV when burning natural gas in the kiln
and 0.465 dV when burning solid fuels in the kiln. Since ported kilns do not reduce
emissions when burning solid fuels, it is again very important to note that normal operation
of the indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no
improvement in visibility for ported kilns under normal operation and the visibility
improvement for normal operation is only due to the low-NOX burners on the preheat
sections of lines 4, 5, and 7.
A summary of visibility impacts for the total facility BART analysis are presented in Section 6.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
60
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
61
Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
62
5.B External Combustion Sources
Five utility plant heating boilers are subject-to-BART at this facility. As shown in section 4, the five
boilers underwent a streamlined analysis for SO2 and PM and one of the boilers underwent a
streamlined analysis for NOx. Therefore, the remaining four boilers require a full BART analysis for
NOX.
The utility plant heating boilers are permitted to burn natural gas and fuel oil. The boilers are
generally operated on a seasonal basis to provide heat to the facility. The highest emitting days are
typically cold days in which the facility has a high heat demand and on which a natural gas
curtailment occurs which requires the burning of the higher-emitting fuel oil.
5.B.i Nitrogen Oxide Controls
To be able to control NOx it is important to understand how NOx is formed. There are three
mechanisms by which NOx production occurs:
• Fuel bound nitrogen compounds in the fuel are oxidized in the combustion process to NOx.
• Thermal NOx production arises from the thermal dissociation of nitrogen and oxygen
molecules within the furnace. Combustion air is the primary source of nitrogen and oxygen.
Thermal NOx production is a function of the residence time, free oxygen, and temperature.
Conditions for formation of thermal NOx exist primarily in the burner flame.
• Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the
result of reactions between nitrogen and carbon radicals generated during combustion. Only
minor amounts of NOx are emitted as prompt NOx.
The majority of NOx is emitted as NO. Minor amounts of NO2 are formed in the heater, the balance
of NO2 is formed in the atmosphere when NO reacts with oxygen in the air.
5.B.i.a STEP 1 – Identify All Available Retrofit Control Technologies
With some understanding of how NOx is formed, available and applicable control technologies were
evaluated. Step 1 identifies a comprehensive list of all potential retrofit control technologies that
were evaluated. Many emerging technologies were identified that are not currently commercially
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
63
available. Appendix G presents the current status of the availability and applicability of each
technology.
5.B.i.b STEP 2 – Eliminate Technically Infeasible Options
Step 2 eliminates technically infeasible options which were identified as “available” in Step 1. As
stated in section 2.B of this document, the technical feasibility of each option is determined by
answering three specific questions:
1. Is the control technology “available” to the specific source which is undergoing the
BART analysis?
2. Is the control technology an “applicable technology” for the specific source which is
undergoing the BART analysis?
3. Are there source-specific issues/conditions that would make the control technology not
technically feasible?
The following describes retrofit NOx control technologies that were identified as available and
applicable and discusses aspects of those technologies that determine whether or not the technology
is technically feasible for indurating furnaces.
External Flue Gas Recirculation (EFGR)
External flue gas recirculation (EFGR) uses flue gas as an inert material to reduce flame temperatures thereby
reducing thermal NOx formation. In an external flue gas recirculation system, flue gas is collected from the
heater or stack and returned to the burner via a duct and blower. The flue gas is mixed with the combustion air
and this mixture is introduced into the burner. The addition of flue gas reduces the oxygen content of the
“combustion air” (air + flue gas) in the burner. The lower oxygen level in the combustion zone reduces flame
temperatures; which in turn reduces NOx emissions. For a boiler to accommodate EFGR, air ducts and registers
need to be able to withstand higher temperatures and flow rates, burners must be able to produce a stable flame
with the flue gas added, and the firebox must be able to accommodate longer flame length to avoid flame
impingement. Based on conversations with utility plant staff, the existing equipment cannot meet these
requirements. Therefore, this option is not technically feasible and will not be further evaluated in this report.
Low NOx Burners (LNB)
Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation through
the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged combustion
process that is designed to split fuel combustion into two zones. In the primary zone, NOx formation
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
64
is limited by either one of two methods. Under staged air rich (high fuel) condition, low oxygen
levels limit flame temperatures resulting in less NOx formation. The primary zone is then followed by
a secondary zone in which the incomplete combustion products formed in the primary zone act as
reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will reduce
flame temperature to reduce NOx formation. In the secondary zone, combustion products formed in
the primary zone act to lower the local oxygen concentration, resulting in a decrease in NOx
formation. Low NOx burners typically achieve NOx emission reductions of 25% - 50% for process
boilers. LNB is a technology commonly used on boilers and is considered a available and applicable
technology.
Overfire Air (OFA)
Overfire air diverts a portion of the total combustion air from the burners and injects it through
separate air ports above the top level of burners. OFA is the typical NOx control technology used in
boilers and is primarily geared to reduce thermal NOx. Staging of the combustion air creates an initial
fuel-rich combustion zone for a cooler fuel-rich combustion zone. This reduces the production of
thermal NOx by lowering combustion temperature and limiting the availability of oxygen in the
combustion zone where NOx is most likely to be formed. LNB is a technology commonly used on
boilers and is considered a available and applicable technology. In addition, OFA can also be used in
combination with LNB.
Induced Flue Gas Recirculation Burners
Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits of
flue gas recirculation and low-NOx burner control technologies. The burner is designed to draw flue
gas to dilute the fuel in order to reduce the flame temperature. These burners also utilize staged fuel
combustion to further reduce flame temperature. The estimated NOx control efficiency for IFGR
burners in high temperature applications is 50-75%. This technology is considered an available and
applicable technology.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
65
Energy Efficiency Projects
Energy efficiency projects provide opportunities for a company to reduce their fuel consumption.
Typically reduced fuel usage translates into reduced pollution emissions. An example energy
efficiency project would be to reduce steam consumption which would decrease fuel burning
requirements. Each project is very dependent upon the fuel usage, process equipment, type of
product and many other variables.
Due to the increased price of fuel, Minntac has already implemented several energy efficiency
projects. Each project carries its own fuel usage reductions and potentially emission reductions. It
would be impossible to assign a general potential emission reduction for the energy efficient
category. Due to the uncertainty and generalization of this category, this will not be further evaluated
in this report. However, it should be noted that Minntac will continue to evaluate and implement
energy efficiency projects as they arise.
Alternate Fuels
The increased price of fuel has pushed companies to evaluate alternate fuel consumption and
available fuel sources. These fuel sources come in all forms – solid, liquid and gas. The heating
boilers at Minntac are capable of burning natural gas and fuel oil. Since the boilers do not burn solid
fuels, the options for alternate fuels are limited. Normal operation is on natural gas which is
generally the lowest emitting fuel for a boiler.
It is also important to note that U.S. EPA’s intent is for facilities to consider alternate fuels as their
option, not to direct the fuel choice.31
Therefore, due to the uncertainty of alternative fuel costs, the limited options available, the fact that
natural gas is the typical fuel burned in the boilers and the fact that BART is not intended to mandate
a fuel switch, alternative fuels as an air pollution control technology will not be further evaluated in
this report
However, similar to energy efficiency, Minntac will continue to evaluate and implement alternate
fuel usage as the feasibility arises.
31 Federal Register 70, no. 128 (July 6, 2005): 39164
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
66
Post Combustion Controls
NOx can be controlled using add-on systems located downstream of the boiler combustion process.
The two main techniques in commercial service include the selective non catalytic reduction (SNCR)
process and the selective catalytic reduction (SCR) process. There are a number of different process
systems in each of these categories of control techniques.
In addition to these treatment systems, there are a large number of other processes being developed
and tested on the market. These approaches involve innovative techniques of chemically reducing,
absorbing, or adsorbing NOx downstream of the combustion chamber. Examples of these alternatives
are nonselective catalytic reduction (NSCR) and Low Temperature Oxidation (LTO). Each of these
alternatives is described below.
Non-Selective Catalytic Reduction (NSCR)
A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas
treatment system. NSCR catalyst is very sensitive to poisoning; so; NSCR is usually applied
primarily in natural gas combustion applications.
NSCR is often referred to as “three-way conversion” catalyst because it simultaneously reduces NOx,
unburdened hydrocarbons (UBH), and carbon monoxide (CO). Typically, NSCR can achieve NOx
emission reductions of 90 percent. In order to operate properly, the combustion process must be near
stoichiometric conditions. Under this condition, in the presence of a catalyst, NOx is reduced by CO,
resulting in nitrogen (N2) and carbon dioxide (CO2). The most important reactions for NOx removal
are:
2CO + 2NO → 2CO2 + N2 (1)
[UBH] + NO → N2 + CO2 + H2O (2)
NSCR catalyst has been applied primarily in clean combustion applications. This is due in large part
to the catalyst being very sensitive to poisoning, making it infeasible to apply this technology to
liquid fuels. Since the highest emitting days occur while burning fuel oil, this technology will not be
further evaluated in this report.
Selective Catalytic Reduction and Regenerative Selective Catalytic Reduction
SCR is a post-combustion NOx control technology in which ammonia (NH3) is injected into the flue
gas stream in the presence of a catalyst. NOx is removed through the following chemical reaction:
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
67
4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O (1)
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (2)
A catalyst bed containing metals in the platinum family is used to lower the activation energy
required for NOx decomposition. SCR requires a temperature range of about 570°F – 850°F for a
normal catalyst. At temperature exceeding approximately 670ºF, the oxidation of ammonia begins to
become significant. At low temperatures, the formation of ammonium bisulfate causes scaling and
corrosion problems.
A high temperature zeolite catalyst is also available; it can operate in the 600 °F – 1000°F
temperature range. However, these catalysts are very expensive.
Ammonia slip from the SCR system is usually less than 3 to 5 ppm. The emission of ammonia
increases during load changes due to the instability of the temperature in the catalyst bed as well as at
low loads because of the low gas temperature.
Regenerative Selective Catalytic Reduction (RSCR) applies the Selective Catalytic Reduction (SCR)
control process as described below with a preheat process step to reheat the flue gas stream up to
SCR catalyst operating temperatures. The preheating process combines use of a thermal heat sink
(packed bed) and a duct burner. The thermal sink recovers heat from the hot gas leaving the RSCR
and then transfers that heat to gas entering the RSCR. The duct burner is used to complete the
preheating process. RSCR operates with several packed bed/SCR reactor vessels. Gas flow
alternates between vessels. Each of the vessels alternates between preheating/treating and heat
recovery. The benefit of RSCR compared to SCR is that it has a thermal efficiency of 90% - 95%
versus the heat exchange system in a reheat SCR system which has a thermal efficiency of 60% to
70%.
SCR and R-SCR have both been applied to boilers. Although there may be concerns about the actual
applicability of the technology to the boilers at this facility, the technologies will be considered
feasible for the purposes of this report.
Selective Non-Catalytic Reduction (SNCR)
In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to
convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% - 60%.
Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The
relevant reactions are as follows:
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
68
NO + NH3 + ¼O2 → N2 + 3/2H2O (1)
NH3 + ¼O2 → NO + 3/2H2O (2)
At temperature ranges of 1470 to 1830°F reaction (1) dominates. At temperatures above 2000°F,
reaction (2) will dominate. This control option is considered feasible.
Low Temperature Oxidation (LTO)
The LTO system utilizes an oxidizing agent such as ozone to oxidize various pollutants including
NOx. In the system, the NOx in the flue gas is oxidized to form nitrogen pentoxide (equations 1, 2,
and 3). The nitrogen pentoxide forms nitric acid vapor as it contacts the water vapor in the flue gas
(4). Then the nitric acid vapor is absorbed as dilute nitric acid and is neutralized by the sodium
hydroxide or lime in the scrubbing solution forming sodium nitrate (5) or calcium nitrate. The
nitrates are removed from the scrubbing system and discharged to an appropriate water treatment
system. Commercially available LTO systems include Tri-NOx® and LoTOx®.
NO + O3 → NO2 + O2 (1)
NO2 + O3 → NO3 + O2 (2)
NO3 + NO2 → N2O5 (3)
N2O5 + H2O → 2HNO3 (4)
HNO3 + NaOH → NaNO3 + H2O (5)
Low Temperature Oxidation (Tri-NOx®)
This technology uses an oxidizing agent such as ozone or sodium chlorite to oxidize NO to NO2 in a
primary scrubbing stage. Then NO2 is removed through caustic scrubbing in a secondary stage. The
reactions are as follows:
O3 + NO → O2 + NO2 (1)
2NaOH + 2NO2 + ½ O2 → 2NaNO3 + H2O (2)
Tri-NOx® is a multi-staged wet scrubbing process in industrial use. Several process columns, each
assigned a separate processing stage, are involved. In the first stage, the incoming material is
quenched to reduce its temperature. The second, oxidizing stage, converts NO to NO2. Subsequent
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
69
stages reduce NO2 to nitrogen gas, while the oxygen becomes part of a soluble salt. Tri-NOx® is
typically applied at small to medium sized sources with high NOx concentration in the exhaust gas
(1,000 ppm NOx).
Low Temperature Oxidation (LoTOx®)
BOC Gases’ Lo-TOx® is an example of a version of an LTO system. LoTOx® technology uses ozone
to oxidize NO to NO2 and NO2 to N2O5 in a wet scrubber (absorber). This can be done in the same
scrubber used for particulate or sulfur dioxide removal, The N2O5 is converted to HNO3 in a
scrubber, and is removed with lime or caustic. Ozone for LoTOx® is generated on site with an
electrically powered ozone generator. The ozone generation rate is controlled to match the amount
needed for NOx control. Ozone is generated from pure oxygen. In order for LoTOx® to be
economically feasible, a source of low cost oxygen must be available from a pipeline or on site
generation.
Although only two of BOC’s LoTOx® installations are fully installed and operational applications,
LoTOx has been applied to gas and coal fired boilers. Therefore, although LoTOx is an emerging
technology, has limited installations, and there may be concerns about the actual applicability of the
technology to the boilers at this facility, the technologies will be considered feasible for the purposes
of this report.
Step 2 Conclusion
Based upon the determination within Step 2, the remaining NOx control technologies that are
available and applicable to the indurating furnace process are identified in Table 5-12. The technical
feasibility as determined in Step 2 is also included in Table 5-13.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
70
Table 5-12 Boiler NOx Control Technology – Availability, Applicability, and Technical Feasibility
Step 1 Step 2
SO2 Pollution Control Technology Is
th
is a
g
en
era
lly
a
va
ila
ble
co
ntr
ol
tec
hn
olo
gy
?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
va
ila
ble
to
h
ea
tin
g b
oil
er?
Is t
he
co
ntr
ol
tec
hn
olo
gy
a
pp
lic
ab
le t
o t
his
s
pe
cif
ic s
ou
rce
?
Is i
t te
ch
nic
all
y
fea
sib
le f
or
this
s
ou
rce
?
External Flue Gas Recirculation (EFGR)
Y Y N ---
Low-NOx Burners Y Y Y Y
Overfired Air Y Y Y Y
Induced Flue Gas Recirculation (IFGR)
Y Y Y Y
Energy Efficiency Projects Y Y Y N
Alternative Fuels Y Y Y N
Non-Selective Catalytic Reduction (NSCR)
Y Y Y N
Selective Catalytic Reduction (SCR)
Y Y Y Y
Regenerative SCR Y Y Y Y
Selective Non-Catalytic Reduction (SNCR)
Y Y Y Y
Low Temperature Oxidation (LTO)
Y Y Y Y
5.B.i.c STEP 3 – Evaluate Control Effectiveness of Remaining Control Technologies
Table 5-13 describes the expected control efficiency from each of the remaining technically feasible
control options as identified in Step 2.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
71
Table 5-13 Boiler NOx Control Technology Effectiveness
NOx Pollution Control Technology Approximate Control
Efficiency
LoTOx 90%
SCR 80%
Low-NOx Burners with IFGR 75%
R-SCR 70%
Low-NOx Burners with OFA 67%
Low-NOx Burners 50%
Selective Non-Catalytic Reduction (SNCR) 50%
5.B.i.d STEP 4 – Evaluate Impacts and Document the Results
Table 5-14 details the expected costs associated with installation of NOx controls. Capital costs were
calculated based on the maximum 24-hour emissions, U.S. EPA cost models, and vendor estimates.
Vendor estimates for capital costs based on a specific flow rate were scaled to each stack’s flow rate
using the 6/10 power law to account for the economy of scale. Operating costs were based on 93%
utilization and 3,156 operating hours per year, which is based on historic operating records.
Operating costs were proportionally adjusted to reflect site specific flow rates and pollutant
concentrations. Where applicable, a site-specific estimate for site-work, foundations, and structural
steel was added based upon the facility site to arrive at the total retrofit installed cost of the control
technology. The detailed cost analysis is provided in Appendix A.
Based on the BART final rule, court cases on cost-effectiveness, guidance from other regulatory
bodies, and other similar regulatory programs like Clean Air Interstate Rule (CAIR), cost-effective
air pollution controls in the electric utility industry for large power plants are in the range $1,000 to
$1,300 per ton removed as illustrated in Appendix F. This cost-effective threshold is also an indirect
measure of affordability for the electric utility industry used by USEPA to support the BART rule-
making process. For the purpose of this taconite BART analysis, the $1,000 to $1,300 cost
effectiveness threshold is used as the cutoff in proposing BART. The taconite industry is not
afforded the same market stability or guaranteed cost recovery mechanisms that are afforded to the
electric utility industry. Therefore, the $1,000 to $1,300 per ton removed is considered a greater
business risk to the taconite industry. Thus it is reasonable to use it as a cost effective threshold for
proposing BART in lieu of developing industry and site specific data.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
72
Table 5-14 Boiler NOx Control Cost Summary
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
73
The annualized pollution control cost value was used to determine whether or not additional impacts
analyses would be conducted for the technology. If the control cost was less than a screening
threshold established by MPCA, then visibility modeling impacts, and energy and other impacts are
evaluated. MPCA set the screening level to eliminate technologies from requiring the additional
impact analyses at an annualized cost of $8,000 to $12,000 per ton of controlled pollutant32.
Therefore, all air pollution controls with annualized costs less than this screening threshold will be
evaluated for visibility improvement, energy and other impacts.
The costs of NOx control for SCR, low-NOx burners with flue gas recirculation, low-NOX burners
with overfire air, and SNCR are far in excess of any cost that is considered to be cost effective for
BART, or even for BACT. Therefore, these technologies are not carried forward in the analysis.
The costs for low-NOx burners are below the MPCA recommended screening threshold of $12,000
per ton, and therefore are carried forward in the BART analysis.
Energy and Environmental Impacts
The energy and environmental impacts for low-NOx burners are minimal.
5.B.i.e STEP 5 – Evaluate Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality impacts, when determining BART for an individual
source. The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this
document.
Predicted 24-Hour Maximum Emission Rates
Consistent with the use of the highest daily emissions for baseline, or pre-BART, visibility impacts,
the post-BART emissions to be used for the visibility impacts analysis should also reflect a
maximum 24-hour average project emission rate. The stack parameters (location, height, velocity,
and temperature) were assumed to remain unchanged from the baseline modeling.
Table 5-15 provides a summary of the modeled NOX 24-hour maximum emission rates for the post-
baseline (i.e. post-BART) operating scenario for installing low-NOX burners on the four boilers.
32 Minnesota Pollution Control Agency (MPCA). Air Permit for Cenex Harvest States Cooperative Soybean Processing Plant, Fairmont, MN Permit 09100059-002.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
74
Post-BART Visibility Impacts Modeling Results
Results of the post-BART visibility impacts modeling summarize 98th percentile dV value and the
number of days the facility contributes more than a 0.5 dV of visibility impairment at each of the
Class I areas. As illustrated in tables 5-16, post-BART modeled visibility improvements are as
follows:
• The installation of low-NOx burners on the boilers results in a visibility improvement of
0.008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these
modeling results, the visibility improvement for the installation of low-NOx burners on the
boilers is basically negligible.
A summary of visibility impacts for the total facility BART analysis are presented in Section 6.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
75
Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
76
Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
77
6. Visibility Impacts
As previously stated in section 4 of this document, states are required to consider the degree of
visibility improvement resulting from the retrofit technology, in combination with other factors such
as economic, energy and other non-air quality, when determining BART for an individual source.
The baseline, or pre-BART, visibility impacts modeling was presented in section 4 of this document.
The visibility impacts of individual control technologies were presented in Step 5 of sections 5.A.i.e,
5.A.ii.e, and 5.B.i.e. This section of the report evaluates the various BART control scenarios
utilizing both SO2 and NOx controls, and determines the resulting degree of visibility improvement.
The intent of this section is to present the modeling scenarios for combinations of SO2 and NOx
controls. However, since there were no control technologies for SO2 that required visibility impacts
analysis, there are no SO2/NOx combinations that need to be evaluated. Therefore, no new or
additional modeling scenarios are presented in this section.
6.A Post-BART Modeling Scenarios All of the modeling scenario results, as presented in sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e or this
report, are presented in Table 6-1. As previously stated, no new or additional modeling scenarios are
presented.
6.B Post-BART Modeling Results Results of all post-BART modeling scenarios are presented in Table 6-1. These results were also
presented in Step 5 of sections 5.A.i.e, 5.A.ii.e, and 5.B.i.e. As previously stated, no new or
additional modeling scenarios are presented. The results summarize 98th percentile dV value and the
number of days the facility contributes more than a 0.5 dV of visibility impairment at each of the
Class I areas.
When reviewing the modeling results for the indurating furnaces, it is important to note the
following:
• Current Operation:
o The current operation of the facility results in a visibility improvement of 0.196 dV
when burning natural gas in the kiln and 0.188 dV when burning solid fuels in the
kiln. Both of these values represent a 3% improvement compared to the baseline
emissions.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
78
• Ported Kilns:
o Natural Gas Operation: The installation of ported kilns on lines 3, 4, and 5 results in a
visibility improvement of 0.330 dV when burning natural gas in the kiln, which
represents an addition 0.134 dV compared to the current operation when burning
natural gas in the kiln. This is a 5% improvement from the baseline when burning
natural gas in the kiln and a 2% improvement from the current operation when
burning natural gas in the kiln.
o Solid Fuel Operation: Since ported kilns do not reduce emissions when burning solid
fuels, there is no additional visibility improvement for that scenario compared to
current operations. It is very important to note that normal operation of the
indurating furnaces at Minntac includes the use of solid fuels. Therefore, there is no
improvement in visibility for ported kilns under normal operation.
• Low-NOX Burners:
o Natural Gas Operation: The installation of low-NOx burners on the preheat sections
of lines 4, 5, and 7 results in a visibility improvement of 0.488 dV when burning
natural gas in the kiln which represents an addition 0.292 dV compared to the current
operation when burning natural gas in the kiln. This is a 7% improvement from the
baseline when burning natural gas and a 4% improvement from the current operation
when burning natural gas.
o Solid Fuel Operation: The installation of low-NOx burners on the preheat sections of
lines 4, 5, and 7 results in a visibility improvement of 0.465 dV when burning solid
fuels in the kiln which represents an addition 0.277 dV compared to the current
operation when burning solid fuels in the kiln. This is a 7% improvement from the
baseline when burning solid fuels in the kiln and a 4% improvement from the current
operation when burning solid fuels in the kiln.
• Ported Kilns with Low-NOX Burners:
o Natural Gas Operation: The combined installation of ported kilns on lines 3, 4, and 5
and low-NOx burners on lines 4, 5, and 7 results in a visibility improvement of 0.627
dV when burning natural gas in the kiln which represents an addition 0.431 dV
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
79
compared to the current operation when burning natural gas in the kiln. This is a 9%
improvement from the baseline when burning natural gas in the kiln and a 6%
improvement from the current operation when burning natural gas in the kiln.
o Solid Fuel Operation: The combined installation of ported kilns on lines 3, 4, and 5
and low-NOx burners on lines 4, 5, and 7 results in a visibility improvement of 0.465
dV when burning solid fuels in the kiln which represents an addition 0.277 dV
compared to the current operation when burning solid fuels in the kiln. This is a 7%
improvement from the baseline when burning solid fuels in the kiln and a 7%
improvement from the current operation when burning solid fuels in the kiln.
When reviewing the modeling results for the boilers, it is important to note the following:
• The installation of low-NOx burners on the boilers results in a visibility improvement of
0.008 dV which is a 0.1% improvement compared to the baseline emissions. Based on these
modeling results, the visibility improvement for the installation of low-NOx burners on the
boilers is basically negligible.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
80
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
81
7. Select BART
The final step in the BART analysis is to select the “best alternative” using the results of steps 1
through 5, as presented in section 5 of this report.
7.A Indurating Furnaces Minntac operates five indurating furnaces which are subject-to-BART:
• Line 3 Rotary Kiln (EU 225 / SV 103)
• Line 4 Rotary Kiln (EU 261 / SV 118)
• Line 5 Rotary Kiln (EU 282 / SV 127)
• Line 6 Rotary Kiln (EU 315 / SV 144)
• Line 7 Rotary Kiln (EU 334 / SV 151)
As presented in section 3 of the report, the PM emissions from the indurating furnaces were subject
to a streamlined BART analysis based on the specific provision that compliance with the Taconite
MACT (40 CFR Part 63 Subpart RRRRR) for PM emissions is equivalent to BART. The Taconite
MACT standard includes requirements for performance testing and continuous parametric monitoring
for compliance demonstration.
As presented in section 5.A of this report, the five indurating furnaces at Minntac were required to
undergo a full BART analysis for NOx and SO2.
As presented in section 5.A of this report, the indurating furnace was required to undergo a full
BART analysis for SO2 and NOx. The selection is based on consideration of all of the criteria
presented in MPCA and U.S. EPA guidance for determining BART, as presented in this report.
The following technologies were identified as technically feasible and subject to the full BART
analysis: new wet scrubbers that control PM and SO2, add-on secondary wet scrubber to control
additional SO2 control, ported kiln, SCR (with conventional flue gas reheat), and NOx CEMS. The
secondary wet scrubber, ported kiln, and SCR alternatives were not proposed as BART for the
following reasons:
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
82
Ported Kiln
Converting the kilns 3, 4 and 5 to ported kilns would result in only an estimated 5% decrease
in NOx emissions when burning gas in the kiln and the corresponding impact on visibility is
also minimal. It would not result in emissions reductions when burning solid fuel in the kiln,
which is the primary fuel used by Minntac. Therefore, the technology will not result in any
significant visibility improvement at the Class I areas compared to the current operation.
Further, it is not cost effective at an estimated amount of more than $5,000/ton NOx removed.
Based on the consideration of all of the criteria presented in the BART analysis, Minntac proposes
the following as BART for SO2 and NOX for the Indurating Furnaces:
• BART for SO2:
o SO2 emissions will be controlled by the existing wet scrubbers, which will be
operated as required in accordance with provisions of the Taconite MACT.
o SO2 emission limit for the Indurating Furnace on Line 3 will be determined based
on upcoming performance testing to determine the actual emission rate from the
furnace with the addition of the new scrubber. A proposed SO2 limit for the
furnace in the draft PSD permit for Minntac does not reflect the recently installed
wet scrubber.
o SO2 emission limits for the Indurating Furnaces on lines 4, 5, 6, and 7 will be the
limits which are based on using the existing wet scrubbers and reflect air
dispersion modeling results for regional haze as proposed in the draft PSD
permit:
⋅ Line 4 = 182 lbs/hr
⋅ Line 5 = 182 lbs/hr
⋅ Line 6 = 284 lbs/hr
⋅ Line 7 = 284 lbs/hr
o Compliance will be initially be demonstrated by a performance test at each
furnace.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
83
o Continuous compliance will be demonstrated by continuous monitoring of
scrubber water flow rate and scrubber pressure drop, which are the same
parameters that will be monitored under the Taconite MACT. The operating
limits will be determined based on the initial SO2 compliance test and will be
based on a 24-hour block average, consistent with the Taconite MACT.
• BART for NOx:
o NOx emissions will be controlled as follows:
⋅ Line 3: Existing combustion controls and fuel blending. Line 3 does not
currently use burners in its pre-heat section, and therefore low-NOx burners
cannot be applied at this furnace.
⋅ Line 4: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
⋅ Line 5: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
⋅ Line 6: Operation of low-NOx burners on the pre-heat section (installed as
replacement and reconfigured burners in April 2006), existing combustion
controls, and fuel blending.
⋅ Line 7: Installation of low-NOx burners on the pre-heat section, existing
combustion controls, and fuel blending.
o NOx emission limits will be proposed by the facility 12-months after the
installation of the low-NOx burners to allow the facility sufficient time for
process and emissions monitoring using NOx CEMS to determine the actual
emission rates under a variety of operating conditions. Although the facility
anticipates a significant reduction in NOx emissions with the installation of the
low-NOx burners, the actual emissions reduction cannot be determined until the
burners are operated under a variety of operation conditions.
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
84
o Initial and continuous compliance will be demonstrated after the appropriate
emission limits have been determined. Compliance will be demonstrated using
the NOx CEMS and will be based on a 30-day rolling average.
The schedule for implementation of these controls, specifically installation of low-NOx burners and
subsequent testing to demonstrate the appropriate BART emission limit, will be within the 5-year
time-frame required for BART implementation. In addition, Minntac will continue to evaluate energy
efficiency projects and other mechanisms to reduce their visibility impairment pollutants emission
rates.
Using the modeling protocol as described above and a NOx emission reduction estimate of 10% for
the installation of low-NOx burners, the proposed BART controls will result in visibility
improvement on the 98th percentile day of approximately 0.488 dV when burning gas in the kiln and
0.465 dV when burning solid fuels in the kiln. This is a visibility improvement of approximately 7%
compared to the baseline (pre-BART) operating conditions.
7.B External Combustion Sources Minntac operates 5 utility plant heating boilers which are subject-to-BART:
o Utility Plant Heating Boiler #1 (EU 001 / SV 001)
o Utility Plant Heating Boiler #2 (EU 002 / SV 002)
o Utility Plant Heating Boiler #3 (EU 003 / SV 003)
o Utility Plant Heating Boiler #4 (EU 004 / SV 004)
o Utility Plant Heating Boiler #5 (EU 005 / SV 005)
As presented in section 3 of the report, the SO2 and PM emissions from all five boilers underwent a
streamlined BART analysis based on the de minimis modeling results as presented in section 3.F. In
addition, the NOx emissions from boiler #3 underwent a streamlined BART analysis for NOx. Based
on the consideration of all of the criteria presented in the BART analysis, Minntac proposes no
additional controls, emission limits, or monitoring requirements for the NOx emissions from four
heating boilers. This is based on the conclusion that the control technologies that meet the cost
screening threshold do not provide significant improvement in the visibility modeling. It is also
Minntac BART Report September 8, 2006
Y:\23\00 MN Taconite BART (2006)\Facility BART Reports\Minntac BART Report\BART Rpt Minntac FINAL 2006-09-08.doc
85
important to note that due to the relatively small size of the boilers and the low hours of operation,
the actual visibility impact of the boilers is small.
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis
Emission
Unit # Emission Unit Description
NOx Max. 24-hr
Actual
Emissions (lb/day)
SO2 Max. 24-
hr Actual
Emissions
(lb/day)
PM10 Max. 24-
hr Actual
Emissions
(lb/day)
MACT
PM Emission
Limit*
(g/dscf)
Stack
Number Actions Required
3.A. Indurating Furnaces
EU 223 Traveling Grate (Line 3) --- --- 655.2 0.01 SV 103 BART Analysis for SO2 + NOx
EU 225 Rotary Kiln (Line 3) --- --- Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOx
EU 226 Pellet Cooler Secondary Air (Line 3) --- --- Incl with EU223 0.01 SV 103 BART Analysis for SO2 + NOx
EU 259 Traveling Grate (Line 4) --- --- 1,504.8 0.01 SV 118 BART Analysis for SO2 + NOx
EU 260 Recouperative System Air (Line 4) --- --- Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOx
EU 261 Rotary Kiln (Line 4) --- --- Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOx
EU 262 Pellet Cooler Secondary Air (Line 4) --- --- Incl with EU259 0.01 SV 118 BART Analysis for SO2 + NOx
EU 280 Traveling Grate (Line 5) --- --- 2,568.0 0.01 SV 127 BART Analysis for SO2 + NOx
EU 281 Recouperative System Air (Line 5) --- --- Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOx
EU 282 Rotary Kiln (Line 5) --- --- Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOx
EU 283 Pellet Cooler Secondary Air (Line 5) --- --- Incl with EU280 0.01 SV 127 BART Analysis for SO2 + NOx
EU 313 Traveling Grate (Line 6) --- --- 1,944.0 0.01 SV 144 BART Analysis for SO2 + NOx
EU 314 Recoup System (Line 6) --- --- Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOx
EU 315 Rotary Kiln (Line 6) --- --- Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOx
EU 316 Pellet Cooler Secondary Air (Line 6) --- --- Incl with EU314 0.01 SV 144 BART Analysis for SO2 + NOx
EU 332 Traveling Grate (Line 7) --- --- 1,968.0 0.01 SV 151 BART Analysis for SO2 + NOx
EU 333 Recoup System (Line 7) --- --- Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOx
EU 334 Rotary Kiln (Line 7) --- --- Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOx
EU 335 Pellet Cooler Secondary Air (Line 7) --- --- Incl with EU332 0.01 SV 151 BART Analysis for SO2 + NOx
3.B. PM-Only Taconite MACT Emission Units
EU 013 Dump Pocket --- --- 62.4 0.008 SV 013 None
EU 014 Crusher --- --- Incl with EU013 0.008 SV 013 None
EU 015 Dump Pocket --- --- 62.4 0.008 SV 014 None
EU 016 Crusher --- --- Incl with EU015 0.008 SV 014 None
EU 017 Dump Pocket --- --- 62.4 0.008 SV 015 None
EU 018 Crusher --- --- Incl with EU017 0.008 SV 015 None
EU 019 Dump Pocket --- --- Incl with EU017 0.008 SV 015 None
EU 020 Crusher --- --- Incl with EU017 0.008 SV 015 None
EU 022 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 016 None
EU 023 Pre-1969 Panfeeder --- --- Incl with EU022 0.008 SV 016 None
EU 024 Pre-1969 Panfeeder --- --- 11.0 0.008 SV 017 None
EU 025 Pre-1969 Panfeeder --- --- Incl with EU024 0.008 SV 017 None
EU 026 Post-1969 Panfeeder --- --- 11.0 0.008 SV 018 None
EU 027 Post-1969 Panfeeder --- --- Incl with EU026 0.008 SV 018 None
EU 034 Ore Transfer From 061-02-1 to 005-02-1 --- --- 31.2 0.008 SV 021 None
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 061-02-1 to 005-02-1 --- --- Incl with EU034 0.008 SV 021 None
EU 036 Ore Transfer From 061-03-1 to 010-01-1 --- --- 31.2 0.008 SV 022 None
EU 037 Ore Transfer Fr 004-01-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 None
EU 038 Ore Transfer Fr 004-02-1 to Turn Bin 060-01-1 --- --- Incl with EU036 0.008 SV 022 None
EU 039 Ore Transfer From 011-01-1 to 060-01-1 --- --- Incl with EU036 0.008 SV 022 None
EU 040 Ore Transfer From 061-01-1 to 005-01-1 --- --- 31.2 0.008 SV 023 None
EU 041 Ore Transfer From 061-08-1 to 010-02-1 --- --- 31.2 0.008 SV 024 None
EU 042 Ore Transfer From 061-07-1 to 005-03-1 --- --- Incl with EU041 0.008 SV 024 None
EU 043 Ore Transfer From 061-06-1 to 005-04-1 --- --- Incl with EU041 0.008 SV 024 None
EU 044 Ore Transfer From 011-03-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 None
EU 045 Ore Transfer From 004-03-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 None
EU 046 Ore Transfer From 004-04-1 to Turn Bin --- --- Incl with EU041 0.008 SV 024 None
EU 047 Ore Transfer From 011-02-1 to 011-03-1 --- --- 31.2 0.008 SV 025 None
EU 048 Ore Transfer From Stockpile to 011-01-1 --- --- 31.2 0.008 SV 026 None
EU 052 Ore Transfer Fr 008-01-1 to 009-01-1 or 009-02-1 --- --- 6.0 0.008 SV 030 None
EU 053 Ore Transfer From 008-02-1 to 009-02-1 --- --- Incl with EU052 0.008 SV 030 None
EU 054 Secondary Crusher --- --- 14.2 0.008 SV 031 None
EU 055 Secondary Crusher --- --- 14.2 0.008 SV 032 None
EU 056 Secondary Crusher --- --- 12.0 0.008 SV 033 None
EU 057 Secondary Crusher --- --- 14.2 0.008 SV 034 None
EU 058 Ore Transfer From 001-01-1 to 070-01-1 --- --- 5.5 0.008 SV 035 None
EU 059 Ore Transfer From 005-02-1 to 006-02-1 --- --- Incl with EU058 0.008 SV 035 None
EU 060 Ore Transfer From 005-01-1 to 006-01-1 --- --- Incl with EU058 0.008 SV 035 None
EU 061 Ore Transfer From 003-01-1 to 004-01-1 --- --- 5.5 0.008 SV 036 None
EU 062 Ore Transfer From 003-02-1 to 004-02-1 --- --- Incl with EU061 0.008 SV 036 None
EU 063 Ore Transfer From 003-03-1 to 004-01-1 --- --- Incl with EU061 0.008 SV 036 None
EU 064 Ore Transfer From 003-04-1 to 004-02-1 --- --- Incl with EU061 0.008 SV 036 None
EU 065 Ore Transfer From 006-01-1 to 080-01-1 --- --- 5.5 0.008 SV 037 None
EU 066 Ore Transfer From 006-01-1 to 080-03-1 --- --- Incl with EU065 0.008 SV 037 None
EU 067 Ore Transfer From 006-01-1 to 080-05-1 --- --- Incl with EU065 0.008 SV 037 None
EU 068 Ore Transfer From 006-01-1 to 080-07-1 --- --- Incl with EU065 0.008 SV 037 None
EU 069 Tertiary Crusher --- --- 7.2 0.008 SV 038 None
EU 070 Tertiary Crusher --- --- 7.2 0.008 SV 039 None
EU 071 Tertiary Crusher --- --- 7.2 0.008 SV 040 None
EU 072 Tertiary Crusher --- --- 7.2 0.008 SV 041 None
EU 073 Tertiary Crusher --- --- 7.2 0.008 SV 042 None
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 --- --- 7.2 0.008 SV 043 None
EU 075 Tertiary Crusher --- --- 7.2 0.008 SV 044 None
EU 076 Tertiary Crusher --- --- 7.2 0.008 SV 045 None
EU 077 Tertiary Crusher --- --- 7.2 0.008 SV 046 None
EU 078 Tertiary Crusher --- --- 7.2 0.008 SV 047 None
EU 079 Tertiary Crusher --- --- 7.2 0.008 SV 048 None
EU 080 Tertiary Crusher --- --- 7.2 0.008 SV 049 None
EU 081 Tertiary Crusher --- --- 16.6 0.008 SV 050 None
EU 082 Tertiary Crusher --- --- 16.6 0.008 SV 051 None
EU 083 Tertiary Crusher --- --- 16.6 0.008 SV 052 None
EU 084 Tertiary Crusher --- --- 16.6 0.008 SV 053 None
EU 085 Ore Transfer From 006-01-1 to 080-15-1 --- --- 16.8 0.008 SV 054 None
EU 086 Ore Transfer From 006-01-1 to 080-09-1 --- --- Incl with EU085 0.008 SV 054 None
EU 087 Ore Transfer From 006-01-1 to 080-11-1 --- --- Incl with EU085 0.008 SV 054 None
EU 088 Ore Transfer From 006-01-1 to 080-13-1 --- --- Incl with EU085 0.008 SV 054 None
EU 089 Ore Transfer From 006-01-2 to 080-15-1 --- --- Incl with EU085 0.008 SV 054 None
EU 090 Ore Transfer From 006-01-2 to 080-09-1 --- --- Incl with EU085 0.008 SV 054 None
EU 091 Ore Transfer From 006-01-2 to 080-11-1 --- --- Incl with EU085 0.008 SV 054 None
EU 092 Ore Transfer From 006-01-2 to 080-13-1 --- --- Incl with EU085 0.008 SV 054 None
EU 093 Secondary Crusher --- --- 18.7 0.008 SV 055 None
EU 094 Secondary Crusher --- --- 18.7 0.008 SV 056 None
EU 095 Secondary Crusher --- --- 18.7 0.008 SV 057 None
EU 096 Secondary Crusher --- --- 18.7 0.008 SV 058 None
EU 097 Secondary Crusher --- --- 18.7 0.008 SV 059 None
EU 098 Ore Transfer From 008-03-1 to 009-03-1 --- --- 5.5 0.008 SV 060 None
EU 099 Ore Transfer From 003-05-1 to 003-06-1 --- --- Incl with EU098 0.008 SV 060 None
EU 100 Ore Transfer From 003-06-1 to 003-02-1 --- --- Incl with EU098 0.008 SV 060 None
EU 101 Ore Transfer From 009-03-1 to 009-02-1 --- --- Incl with EU098 0.008 SV 060 None
EU 102 Ore Transfer From 001-01-2 to 070-02-1 --- --- 7.7 0.008 SV 061 None
EU 103 Secondary Crusher --- --- 14.2 0.008 SV 062 None
EU 104 Ore Transfer From 008-04-1 to 009-04-1 --- --- 6.0 0.008 SV 063 None
EU 105 Ore Transfer From 008-05-1 to 009-05-1 --- --- Incl with EU105 0.008 SV 063 None
EU 106 Secondary Crusher --- --- 14.6 0.008 SV 064 None
EU 107 Secondary Crusher --- --- 18.7 0.008 SV 065 None
EU 108 Secondary Crusher --- --- 18.7 0.008 SV 066 None
EU 109 Secondary Crusher --- --- 18.7 0.008 SV 067 None
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 --- --- 18.7 0.008 SV 068 None
EU 111 Ore Transfer From 001-03-1 to 070-03-1 --- --- 4.8 0.008 SV 069 None
EU 112 Ore Transfer From 003-07-1 to 003-09-1 --- --- 6.0 0.008 SV 070 None
EU 113 Ore Transfer From 003-08-1 to 003-10-1 --- --- Incl with EU112 0.008 SV 070 None
EU 114 Ore Transfer From 003-09-1 to 004-03-1 --- --- 6.0 0.008 SV 071 None
EU 115 Ore Transfer From 003-10-1 to 004-04-1 --- --- Incl with EU114 0.008 SV 071 None
EU 116 Ore Transfer From 006-03-1 to 080-18-1 --- --- 12.5 0.008 SV 072 None
EU 117 Ore Transfer From 006-03-1 to 080-20-1 --- --- Incl with EU116 0.008 SV 072 None
EU 118 Ore Transfer From 006-03-1 to 080-22-1 --- --- Incl with EU116 0.008 SV 072 None
EU 119 Ore Transfer From 006-03-1 to 080-24-1 --- --- Incl with EU116 0.008 SV 072 None
EU 120 Ore Transfer From 006-03-1 to 080-26-1 --- --- Incl with EU116 0.008 SV 072 None
EU 121 Ore Transfer From 006-03-1 to 080-28-1 --- --- Incl with EU116 0.008 SV 072 None
EU 122 Ore Transfer From 006-04-1 to 080-18-1 --- --- Incl with EU116 0.008 SV 072 None
EU 123 Ore Transfer From 006-04-1 to 080-20-1 --- --- Incl with EU116 0.008 SV 072 None
EU 124 Ore Transfer From 006-04-1 to 080-22-1 --- --- Incl with EU116 0.008 SV 072 None
EU 125 Ore Transfer From 006-04-1 to 080-24-1 --- --- Incl with EU116 0.008 SV 072 None
EU 126 Ore Transfer From 006-04-1 to 080-26-1 --- --- Incl with EU116 0.008 SV 072 None
EU 127 Ore Transfer From 006-04-1 to 080-28-1 --- --- Incl with EU116 0.008 SV 072 None
EU 128 Tertiary Crusher --- --- 10.6 0.008 SV 073 None
EU 129 Tertiary Crusher --- --- 10.6 0.008 SV 074 None
EU 130 Tertiary Crusher --- --- 10.6 0.008 SV 075 None
EU 131 Tertiary Crusher --- --- 10.6 0.008 SV 076 None
EU 132 Tertiary Crusher --- --- 10.6 0.008 SV 077 None
EU 133 Tertiary Crusher --- --- 10.6 0.008 SV 078 None
EU 134 Tertiary Crusher --- --- 10.6 0.008 SV 079 None
EU 135 Tertiary Crusher --- --- 10.6 0.008 SV 080 None
EU 136 Tertiary Crusher --- --- 10.6 0.008 SV 081 None
EU 137 Tertiary Crusher --- --- 10.6 0.008 SV 082 None
EU 138 Tertiary Crusher --- --- 10.6 0.008 SV 083 None
EU 140 Ore Transfer From 005-03-1 to 006-03-1 --- --- 5.5 0.008 SV 085 None
EU 141 Ore Transfer From 005-04-1 to 006-04-1 --- --- Incl with EU140 0.008 SV 085 None
EU 144 Ore Transfer From 009-01-1 to 020-01-1 --- --- 10.6 0.008 SV 087 None
EU 145 Ore Transfer From 009-02-1 to 020-02-1 --- --- Incl with EU144 0.008 SV 087 None
EU 146 Ore Transfer From 009-02-1 to 020-06-1 --- --- Incl with EU144 0.008 SV 087 None
EU 147 Ore Transfer From 020-05-1 to 020-01-1 --- --- Incl with EU144 0.008 SV 087 None
EU 155 Ore Transfer From 020-01-1 to Bin 100-06 --- --- 5.5 0.008 SV 089 None
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 020-01-1 to Bin 100-07 --- --- Incl with EU155 0.008 SV 089 None
EU 157 Ore Transfer From 020-01-1 to Bin 100-08 --- --- Incl with EU155 0.008 SV 089 None
EU 158 Ore Transfer From 020-01-1 to Bin 100-09 --- --- Incl with EU155 0.008 SV 089 None
EU 159 Ore Transfer From 020-01-1 to Bin 100-10 --- --- Incl with EU155 0.008 SV 089 None
EU 160 Ore Transfer From 021-03-1 to 022-03-1 --- --- Incl with EU155 0.008 SV 089 None
EU 161 Ore Transfer From 021-04-1 to 022-04-1 --- --- Incl with EU155 0.008 SV 089 None
EU 162 Ore Transfer From 020-01-1 to Bin 100-11 --- --- 9.1 0.008 SV 090 None
EU 163 Ore Transfer From 020-01-1 to Bin 100-12 --- --- Incl with EU162 0.008 SV 090 None
EU 164 Ore Transfer From 020-01-1 to Bin 100-13 --- --- Incl with EU162 0.008 SV 090 None
EU 165 Ore Transfer From 020-01-1 to Bin 100-14 --- --- Incl with EU162 0.008 SV 090 None
EU 166 Ore Transfer From 020-01-1 to Bin 100-15 --- --- Incl with EU162 0.008 SV 090 None
EU 167 Ore Transfer From 021-05-1 to 022-05-1 --- --- Incl with EU162 0.008 SV 090 None
EU 168 Ore Transfer From 021-06-1 to 022-06-1 --- --- Incl with EU162 0.008 SV 090 None
EU 169 Ore Transfer From 020-01-1 to Bin 100-16 --- --- 4.3 0.008 SV 091 None
EU 170 Ore Transfer From 020-01-1 to Bin 100-17 --- --- Incl with EU169 0.008 SV 091 None
EU 171 Ore Transfer From 020-01-1 to Bin 100-18 --- --- Incl with EU169 0.008 SV 091 None
EU 172 Ore Transfer From 020-01-1 to Bin 100-19 --- --- Incl with EU169 0.008 SV 091 None
EU 173 Ore Transfer From 020-01-1 to Bin 100-20 --- --- Incl with EU169 0.008 SV 091 None
EU 174 Ore Transfer From 021-07-1 to 022-07-1 --- --- Incl with EU169 0.008 SV 091 None
EU 175 Ore Transfer From 021-08-1 to 022-08-1 --- --- Incl with EU169 0.008 SV 091 None
EU 176 Ore Transfer From 020-01-1 to Bin 100-21 --- --- 10.6 0.008 SV 092 None
EU 177 Ore Transfer From 020-01-1 to Bin 100-22 --- --- Incl with EU176 0.008 SV 092 None
EU 178 Ore Transfer From 020-01-1 to Bin 100-23 --- --- Incl with EU176 0.008 SV 092 None
EU 179 Ore Transfer From 020-01-1 to Bin 100-24 --- --- Incl with EU176 0.008 SV 092 None
EU 180 Ore Transfer From 020-01-1 to Bin 100-25 --- --- Incl with EU176 0.008 SV 092 None
EU 181 Ore Transfer From 021-09-1 to 022-09-1 --- --- Incl with EU176 0.008 SV 092 None
EU 182 Ore Transfer From 021-10-1 to 022-10-1 --- --- Incl with EU176 0.008 SV 092 None
EU 183 Ore Transfer From 020-01-1 to Bin 100-26 --- --- 10.6 0.008 SV 093 None
EU 184 Ore Transfer From 020-01-1 to Bin 100-27 --- --- Incl with EU183 0.008 SV 093 None
EU 185 Ore Transfer From 020-01-1 to Bin 100-28 --- --- Incl with EU183 0.008 SV 093 None
EU 186 Ore Transfer From 020-01-1 to Bin 100-29 --- --- Incl with EU183 0.008 SV 093 None
EU 187 Ore Transfer From 020-01-1 to Bin 100-30 --- --- Incl with EU183 0.008 SV 093 None
EU 188 Ore Transfer From 021-11-1 to 022-11-1 --- --- Incl with EU183 0.008 SV 093 None
EU 189 Ore Transfer From 021-12-1 to 022-12-1 --- --- Incl with EU183 0.008 SV 093 None
EU 190 Ore Transfer From 009-04-1 to 020-04-1 --- --- 10.6 0.008 SV 094 None
EU 191 Ore Transfer From 009-05-1 to 020-03-1 --- --- Incl with EU190 0.008 SV 094 None
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 009-05-1 to 020-05-1 --- --- Incl with EU190 0.008 SV 094 None
EU 193 Ore Transfer From 020-06-1 to 020-04-1 --- --- Incl with EU190 0.008 SV 094 None
EU 194 Ore Transfer From 020-01-1 to Bin 100-31 --- --- 10.6 0.008 SV 095 None
EU 195 Ore Transfer From 020-01-1 to Bin 100-32 --- --- Incl with EU194 0.008 SV 095 None
EU 196 Ore Transfer From 020-01-1 to Bin 100-33 --- --- Incl with EU194 0.008 SV 095 None
EU 197 Ore Transfer From 020-01-1 to Bin 100-34 --- --- Incl with EU194 0.008 SV 095 None
EU 198 Ore Transfer From 020-01-1 to Bin 100-35 --- --- Incl with EU194 0.008 SV 095 None
EU 199 Ore Transfer From 021-13-1 to 022-13-1 --- --- Incl with EU194 0.008 SV 095 None
EU 200 Ore Transfer From 021-14-1 to 022-14-1 --- --- Incl with EU194 0.008 SV 095 None
EU 201 Ore Transfer From 020-01-1 to Bin 100-36 --- --- 10.6 0.008 SV 096 None
EU 202 Ore Transfer From 020-01-1 to Bin 100-37 --- --- Incl with EU201 0.008 SV 096 None
EU 203 Ore Transfer From 020-01-1 to Bin 100-38 --- --- Incl with EU201 0.008 SV 096 None
EU 204 Ore Transfer From 021-15-1 to 022-15-1 --- --- Incl with EU201 0.008 SV 096 None
EU 205 Ore Transfer From 021-16-1 to 022-16-1 --- --- Incl with EU201 0.008 SV 096 None
EU 206 Ore Transfer From 020-01-1 to Bin 100-39 --- --- Incl with EU201 0.008 SV 096 None
EU 207 Ore Transfer From 020-01-1 to Bin 100-40 --- --- Incl with EU201 0.008 SV 096 None
EU 208 Ore Transfer From 020-01-1 to Bin 100-41 --- --- 10.6 0.008 SV 097 None
EU 209 Ore Transfer From 020-01-1 to Bin 100-42 --- --- Incl with EU208 0.008 SV 097 None
EU 210 Ore Transfer From 020-01-1 to Bin 100-43 --- --- Incl with EU208 0.008 SV 097 None
EU 211 Ore Transfer From 020-01-1 to Bin 100-44 --- --- Incl with EU208 0.008 SV 097 None
EU 212 Ore Transfer From 020-01-1 to Bin 100-45 --- --- Incl with EU208 0.008 SV 097 None
EU 213 Ore Transfer From 021-17-1 to 022-17-1 --- --- Incl with EU208 0.008 SV 097 None
EU 214 Ore Transfer From 021-18-1 to 022-18-1 --- --- Incl with EU208 0.008 SV 097 None
EU 221 Traveling Grate --- --- 4.6 0.008 SV 101 None
EU 222 Traveling Grate --- --- 9.1 0.008 SV 102 None
EU 227 L3 Pellet Cooler --- --- 832.8 0.008 SV 104 None
EU 228 L3 Pellet Cooler Dump Zone --- --- 9.4 0.008 SV 105 None
EU 229 L3 Feeder 041/046 Belts --- --- 912.0 0.008 SV 106 None
EU 230 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 --- --- 4.3 0.008 SV 107 None
EU 231 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 --- --- Incl with EU230 0.008 SV 107 None
EU 232 Pellet Transfer From 042-01-1 to 043-01-1 --- --- 4.3 0.008 SV 108 None
EU 233 Pellet Transfer From 042-01-2 to 043-01-2 --- --- Incl with EU232 0.008 SV 108 None
EU 234 Pellet Trnsfr Fr 041-03-1 to 042-01-1 or 042-02-2 --- --- 4.3 0.008 SV 109 None
EU 235 Pellet Trnsfr Fr 046-03-1 to 042-01-1 or 042-02-2 --- --- Incl with EU234 0.008 SV 109 None
EU 257 Traveling Grate --- --- 2.6 0.008 SV 116 None
EU 258 Traveling Grate --- --- 722.4 0.008 SV 117 None
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 --- --- 304.1 0.008 SV 119 None
EU 264 L4 Conv. Trans. Feeder --- --- 912.0 0.008 SV 120 None
EU 265 L4 Pellet Cooler Dump Zone --- --- 33.6 0.008 SV 121 None
EU 266 Pellet Trnsfr Fr 041-04-1 to 042-01-1 or 042-02-2 --- --- 26.4 0.008 SV 122 None
EU 267 Pellet Trnsfr Fr 046-04-1 to 042-01-1 or 042-02-2 --- --- Incl with EU266 0.008 SV 122 None
EU 278 Traveling Grate --- --- 2.6 0.008 SV 125 None
EU 279 Traveling Grate --- --- 705.2 0.008 SV 126 None
EU 284 L5 Pellet Cooler --- --- 145.7 0.008 SV 128 None
EU 285 L5 Conv. Trans. Feeder --- --- 912.0 0.008 SV 129 None
EU 286 L5 Pellet Cooler Dump Zone --- --- 33.6 0.008 SV 130 None
EU 287 Pellet Trnsfr Fr 041-05-1 to 042-01-1 or 042-02-2 --- --- 43.2 0.008 SV 131 None
EU 288 Pellet Trnsfr Fr 046-05-1 to 042-01-1 or 042-02-2 --- --- Incl with EU287 0.008 SV 131 None
EU 289 Conveyor --- --- 77.8 0.008 SV 132 None
EU 290 Conveyor --- --- 77.8 0.008 SV 133 None
EU 291 Conveyor --- --- 77.8 0.008 SV 134 None
EU 292 Conveyor --- --- 77.8 0.008 SV 135 None
EU 293 Conveyor --- --- 77.8 0.008 SV 136 None
EU 294 Conveyor --- --- 77.8 0.008 SV 137 None
EU 295 Pellet Transfer From 046-06-1 to 042-07-1 --- --- 31.2 0.008 SV 138 None
EU 296 Pellet Transfer From 046-06-2 to 042-07-2 --- --- Incl with EU295 0.008 SV 138 None
EU 311 Traveling Grate --- --- 2.6 0.008 SV 142 None
EU 312 Traveling Grate --- --- 767.4 0.008 SV 143 None
EU 318 Pellet Trnsfr Fr 041-06-1 to 042-06-1 or 042-06-2 --- --- 48.0 0.008 SV 146 None
EU 319 Pellet Trnsfr Fr 046-06-1 to 042-06-1 or 042-06-2 --- --- Incl with EU318 0.008 SV 146 None
EU 330 Traveling Grate --- --- 2.6 0.008 SV 149 None
EU 331 Traveling Grate --- --- 717.0 0.008 SV 150 None
EU 337 Pellet Trnsfr Fr 041-07-1 to 042-06-1 or 042-06-2 --- --- 384.0 0.008 SV 153 None
EU 338 Pellet Trnsfr Fr 046-07-1 to 042-06-1 or 042-06-2 --- --- Incl with EU337 0.008 SV 153 None
EU 339 Pellet Transfer From 043-03-1 to 044-03-1 --- --- 77.8 0.008 SV 154 None
EU 340 Pellet Transfer From 043-03-2 to 044-03-2 --- --- 77.8 0.008 SV 155 None
EU 341 Conveyor --- --- 204.4 0.008 SV 156 None
EU 342 Conveyor --- --- 204.4 0.008 SV 157 None
EU 343 Conveyor --- --- 204.4 0.008 SV 158 None
EU 344 Conveyor --- --- 204.4 0.008 SV 159 None
EU 345 Conveyor --- --- 204.4 0.008 SV 160 None
EU 346 Conveyor --- --- 204.4 0.008 SV 161 None
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 --- --- 204.4 0.008 SV 162 None
EU 348 Conveyor --- --- 204.4 0.008 SV 163 None
EU 349 Conveyor --- --- 204.4 0.008 SV 164 None
EU 350 Conveyor --- --- 204.4 0.008 SV 165 None
EU 351 Conveyor --- --- 204.4 0.008 SV 166 None
EU 352 Conveyor --- --- 204.4 0.008 SV 167 None
EU 353 Conveyor --- --- 204.4 0.008 SV 168 None
EU 354 Conveyor --- --- 204.4 0.008 SV 169 None
EU 355 Conveyor --- --- 204.4 0.008 SV 170 None
EU 359 Pellet Transfer From 043-06-1 to 044-06-1 --- --- 204.4 0.008 SV 174 None
EU 360 Conveyor --- --- 204.4 0.008 SV 175 None
EU 361 Pellet Transfer From 043-06-2 to 044-06-2 --- --- 204.4 0.008 SV 176 None
EU 362 Conveyor --- --- 204.4 0.008 SV 177 None
EU 363 Pellet Transfer From 044-06-1 to 044-07-1 --- --- 204.4 0.008 SV 178 None
EU 364 Pellet Transfer From 044-06-2 to 044-07-2 --- --- 204.4 0.008 SV 179 None
EU 365 Conveyor --- --- 204.4 0.008 SV 179 None
EU 366 Pellet Hopper --- --- 204.4 0.008 SV 180 None
EU 397 Line 6 Cooler Vent Stack --- --- 648.0 0.008 SV 196 None
EU 398 Line 7 Cooler Vent Stack --- --- 616.1 0.008 SV 197 None
N/A N/A - Total facility fugitive sources --- --- 5,650.4 --- N/A None
3.D. Non-MACT Units and Fugitive Sources (PM only)
EU 148Limestone Transfer
(formerly Ore Transfer From 020-01-1 to Bin 100-01) --- --- 9.6 --- SV 088 None
EU 149Limestone Transfer
(formerly Ore Transfer From 020-01-1 to Bin 100-02) --- --- Incl with EU148 --- SV 088 None
EU 150Limestone Transfer
(formerly Ore Transfer From 020-01-1 to Bin 100-03) --- --- Incl with EU148 --- SV 088 None
EU 151Limestone Transfer
(formerly Ore Transfer From 021-01-1 to 022-01-1) --- --- Incl with EU148 --- SV 088 None
EU 152Limestone Transfer
(formerly Ore Transfer From 020-01-1 to Bin 100-04) --- --- Incl with EU148 --- SV 088 None
EU 153Limestone Transfer
(formerly Ore Transfer From 021-02-1 to 022-02-1) --- --- Incl with EU148 --- SV 088 None
EU 154Limestone Transfer
(formerly Ore Transfer From 020-01-1 to Bin 100-05) --- --- Incl with EU148 --- SV 088 None
EU 217 Pekay Mixer --- --- 2.4 --- SV 100 None
3.C. Sources of fugitive PM that are subject to MACT standards
Table 3-1 Summary Table of BART-Eligible Units Subject to a Streamlined BART Analysis
Emission
Unit # Emission Unit Description
NOx Max. 24-hr
Actual
Emissions (lb/day)
SO2 Max. 24-
hr Actual
Emissions
(lb/day)
PM10 Max. 24-
hr Actual
Emissions
(lb/day)
MACT
PM Emission
Limit*
(g/dscf)
Stack
Number Actions Required
EU 218 Pekay Mixer --- --- Incl with EU217 --- SV 100 None
EU 219 Pekay Mixer --- --- Incl with EU217 --- SV 100 None
EU 220 Pekay Mixer --- --- Incl with EU217 --- SV 100 None
EU 236 Bentonite Bin --- --- 3.1 --- SV 110 None
EU 237 Bentonite Bin --- --- Incl with EU236 --- SV 110 None
EU 238 Bentonite Bin --- --- Incl with EU236 --- SV 110 None
EU 239 Bentonite Day Bin --- --- 0.3 --- SV 111 None
EU 240 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 None
EU 241 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 None
EU 242 Bentonite Day Bin --- --- Incl with EU239 --- SV 111 None
EU 243 Bentonite Unloading Hopper --- --- 0.1 --- SV 112 None
EU 244 Bentonite Storage Bin --- --- 3.1 --- SV 113 None
EU 245 Bentonite Storage Bin --- --- Incl with EU244 --- SV 113 None
EU 246 Bentonite Storage Bin --- --- Incl with EU244 --- SV 113 None
EU 247 Storage Bin --- --- 0.3 --- SV 114 None
EU 248 Storage Bin --- --- Incl with EU247 --- SV 114 None
EU 249 Storage Bin --- --- Incl with EU247 --- SV 114 None
EU 250 Storage Bin --- --- Incl with EU247 --- SV 114 None
EU 251 Storage Bin --- --- Incl with EU247 --- SV 114 None
EU 252 Pekay Mixer --- --- 2.9 --- SV 115 None
EU 253 Pekay Mixer --- --- Incl with EU252 --- SV 115 None
EU 254 Pekay Mixer --- --- Incl with EU252 --- SV 115 None
EU 255 Pekay Mixer --- --- Incl with EU252 --- SV 115 None
EU 256 Pekay Mixer --- --- Incl with EU252 --- SV 115 None
EU 268 Storage Bin --- --- 0.3 --- SV 123 None
EU 269 Storage Bin --- --- Incl with EU268 --- SV 123 None
EU 270 Storage Bin --- --- Incl with EU268 --- SV 123 None
EU 271 Storage Bin --- --- Incl with EU268 --- SV 123 None
EU 272 Storage Bin --- --- Incl with EU268 --- SV 123 None
EU 273 Pekay Mixer --- --- 2.9 --- SV 124 None
EU 274 Pekay Mixer --- --- Incl with EU273 --- SV 124 None
EU 275 Pekay Mixer --- --- Incl with EU273 --- SV 124 None
EU 276 Pekay Mixer --- --- Incl with EU273 --- SV 124 None
EU 277 Pekay Mixer --- --- Incl with EU273 --- SV 124 None
EU 297 Bentonite Storage Bin --- --- 3.1 --- SV 139 None
EU 298 Bentonite Storage Bin --- --- Incl with EU297 --- SV 139 None
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 EU297 --- SV 139 None
EU 300 Bentonite Unloading Hopper --- --- Incl with EU297 --- SV 139 None
EU 301 Storage Bin --- --- 0.4 --- SV 140 None
EU 302 Storage Bin --- --- Incl with EU301 --- SV 140 None
EU 303 Storage Bin --- --- Incl with EU301 --- SV 140 None
EU 304 Storage Bin --- --- Incl with EU301 --- SV 140 None
EU 305 Storage Bin --- --- Incl with EU301 --- SV 140 None
EU 306 Pekay Mixer --- --- 1.6 --- SV 141 None
EU 307 Pekay Mixer --- --- Incl with EU306 --- SV 141 None
EU 308 Pekay Mixer --- --- Incl with EU306 --- SV 141 None
EU 309 Pekay Mixer --- --- Incl with EU306 --- SV 141 None
EU 310 Pekay Mixer --- --- Incl with EU306 --- SV 141 None
EU 320 Storage Bin --- --- 0.4 --- SV 147 None
EU 321 Storage Bin --- --- Incl with EU320 --- SV 147 None
EU 322 Storage Bin --- --- Incl with EU320 --- SV 147 None
EU 323 Storage Bin --- --- Incl with EU320 --- SV 147 None
EU 324 Storage Bin --- --- Incl with EU320 --- SV 147 None
EU 325 Pekay Mixer --- --- 1.6 --- SV 148 None
EU 326 Pekay Mixer --- --- Incl with EU325 --- SV 148 None
EU 327 Pekay Mixer --- --- Incl with EU325 --- SV 148 None
EU 328 Pekay Mixer --- --- Incl with EU325 --- SV 148 None
EU 329 Pekay Mixer --- --- Incl with EU325 --- SV 148 None
EU 367 Coal Unload Hopper --- --- 0.2 --- SV 181 None
EU 368 Coal Hopper Conveyor --- --- Incl with EU367 --- SV 181 None
EU 369 Coal Conv. Feed --- --- Incl with EU367 --- SV 181 None
EU 370 Coal Silo Feed --- --- Incl with EU367 --- SV 181 None
EU 371 Coal Silo Discharge --- --- Incl with EU367 --- SV 181 None
EU 372 Coal Silo Transfer --- --- Incl with EU367 --- SV 181 None
EU 373 Coal Silo --- --- Incl with EU367 --- SV 181 None
EU 374 Coal Conv. Discharge --- --- 0.2 --- SV 182 None
EU 375 Coal Screen --- --- Incl with EU374 --- SV 182 None
EU 376 Coal Reversing Belt --- --- Incl with EU374 --- SV 182 None
EU 377 Day Bin Belt Feed --- --- Incl with EU374 --- SV 182 None
EU 378 Day Bin Belt Discharge --- --- Incl with EU374 --- SV 182 None
EU 379 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10
EU 380 Coal Pulverizer --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10
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 EU374 --- SV 182 De Minimis Modeling for PM10
EU 382 Coal Day Bin --- --- Incl with EU374 --- SV 182 De Minimis Modeling for PM10
3.E. Other Combustion Units
EU 001 Utility Plant Heating Boiler #1 193.5 0.4 5.3 --- SV 001
BART Analysis for NOx
De Minimis Modeling for PM10 and SO2
EU 002 Utility Plant Heating Boiler #2 719.8 1.5 19.5 --- SV 002
BART Analysis for NOx
De Minimis Modeling for PM10 and SO2
EU 003 Utility Plant Heating Boiler #3 105.6 0.2 2.9 --- SV 003
BART Analysis for NOx
De Minimis Modeling for PM10 and SO2
EU 004 Utility Plant Heating Boiler #4 230.8 0.5 6.3 --- SV 004
BART Analysis for NOx
De Minimis Modeling for PM10 and SO2
EU 005 Utility Plant Heating Boiler #5 226.5 0.5 6.1 --- SV 005
BART Analysis for NOx
De Minimis Modeling for PM10 and SO2
EU 006 Utility Plant Diesel Generator 3.1 0.2 0.2 --- SV 006 None
EU 008 Utility Plant Diesel Generator 8.4 0.6 0.6 --- SV 008 None
EU 009 Utility Plant Diesel Fire Pump 10.9 0.7 0.7 --- SV 009 None
EU 010 Mobile Eqp Shop Heating Boiler #1 6.8 0.0 0.2 --- SV 010 De Minimis Modeling for SO2 + NOx
EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 Incl with EU010 --- SV 011 De Minimis Modeling for SO2 + NOx
EU 012 Mobile Eqp Shop Diesel Generator 2.3 0.2 0.2 --- SV 012 None
EU 028 Coarse Crusher Zinc Furnace 3.3 0.0 0.3 --- SV 019 De Minimis Modeling for SO2, NOx + PM10
EU 032 Coarse Crusher Zinc Furnace 0.5 1.4 0.0 --- SV 020 De Minimis Modeling for SO2, NOx + PM10
EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 Incl with EU032 --- SV 020 De Minimis Modeling for SO2, NOx + PM10
EU 051 Crusher Area Diesel Generator 2.0 0.1 0.1 --- SV 029 None
EU 142 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Modeling for SO2, NOx + PM10
EU 143 Fine Crusher Zinc Furnace 5.6 16.7 0.3 --- SV 086 De Minimis Modeling for SO2, NOx + PM10
EU 215 Concentrator Area Diesel Generator 45.0 3.0 3.1 --- SV 098 None
EU 383 Diesel Generator 15.4 1.0 1.1 --- SV 183 None
EU 384 Diesel Generator 19.2 1.3 1.3 --- SV 184 None
EU 385 Diesel Generator 6.1 0.4 0.4 --- SV 185 None
EU 386 Diesel Generator 7.5 0.5 0.5 --- SV 186 None
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 171.1 11.3 11.8 --- 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.
Table 3-2: De Minimis Modeling Input Data and the Basis for 24-hour Emissions Data
EU # EU Description
SO2 Maximum
24-hr Emission
Rate (lbs/day)
NOx Maximum
24-hr Emission
Rate (lbs/day)
PM2.5
Maximum 24-
hr Emission
Rate (lbs/day)
PM10 Maximum
24-hr Emission
Rate (lbs/day) SV #
Stack Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground (ft)
Base
Elevation
of
Ground
(ft)
Stack length,
width, or
Diameter (ft)
Flow
Rate at
exit
(acfm)
Exit
Temp
(°F)
Basis for SO2 24-
hour Actual
Emissions
Basis for NOx 24-
hour Actual
Emissions
Basis for
PM2.5 24-
hour
Actual
Emissions
Basis for PM10 24-
hour Actual
Emissions
EU 379 Coal Pulverizer 0.00 0.00 0.00 0.15 SV 182 NA NA 163.5 1676 2.83 29000.0 70 n/a n/a n/aAP-42 Emission
Factor
EU 380 Coal Pulverizer 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382
EU 381 Coal Day Bin 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382
EU 382 Coal Day Bin 0.00 0.00 0.00 Incl with EU 379 SV 182 NA NA 163.5 1676 2.83 29000.0 70 Incl with EU 379 Incl with EU 380 n/a Incl with EU 382
EU 001 Utility Plant Heating Boiler #1 0.41 193.52 0.00 5.25 SV 001 527605.4429 5268166.228 67.25 1682 4.50 17000.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 002 Utility Plant Heating Boiler #2 1.54 719.83 0.00 19.54 SV 002 527612.1358 5268167.191 67.25 1682 4.50 17000.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 003 Utility Plant Heating Boiler #3 0.23 105.64 0.00 2.87 SV 003 527619.1379 5268168.2 67.25 1682 4.50 20800.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 004 Utility Plant Heating Boiler #4 0.49 230.83 0.00 6.27 SV 004 527626.9988 5268169.38 68.59 1682 4.50 25500.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 005 Utility Plant Heating Boiler #5 0.49 226.49 0.00 6.15 SV 005 527633.9031 5268170.379 68.59 1682 4.50 25500.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 010 Mobile Eqp Shop Heating Boiler #1 0.01 6.79 0.00 0.18 SV 010 527646.157 5266984.445 58.84 1619 2.50 4100.0 380AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 011 Mobile Eqp Shop Heating Boiler #2 Incl with EU010 Incl with EU010 0.00 Incl with EU010 SV 011 527650.711 5266985.142 58.84 1619 2.50 4100.0 380 Incl with EU010 Incl with EU010 n/a Incl with EU010
EU 028 Coarse Crusher Zinc Furnace 0.00 3.29 0.00 0.31 SV 019 527252.4492 5267524.117 32 1732 1.67 36700.0 700AP-42 Emission
Factor
AP-42 Emission
Factorn/a
AP-42 Emission
Factor
EU 032 Coarse Crusher Zinc Furnace 1.44 0.48 0.00 0.02 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 700
19 gallons used in
Jan of 2005 * AP-42
Emission Factor
19 gallons used in
Jan of 2005 * AP-42
Emission Factor
n/a
19 gallons used in
Jan of 2005 * AP-42
Emission Factor
EU 033 Coarse Crusher Zinc Furnace Incl with EU032 Incl with EU032 0.00 Incl with EU032 SV 020 527164.3521 5267449.81 32 1732 1.67 36700.0 700 Incl with EU032 Incl with EU032 n/a Incl with EU032
EU 142 Fine Crusher Zinc Furnace 16.72 5.59 0.00 0.25 SV 086 527183.7471 5267919.903 29 1731 1.67 36700.0 700
Assume one full day
of operation: 24 hrs *
operating rate * AP-
42 Emission Factor
Assume one full day
of operation: 24 hrs
* operating rate *
AP-42 Emission
Factor
n/a
Assume one full day
of operation: 24 hrs
* operating rate *
AP-42 Emission
Facto
EU 143 Fine Crusher Zinc Furnace 16.72 5.59 0.00 0.25 SV 086 527173.7879 5267919.13 29 1731 1.67 36700.0 700
Assume one full day
of operation: 24 hrs *
operating rate * AP-
42 Emission Factor
Assume one full day
of operation: 24 hrs
* operating rate *
AP-42 Emission
Factor
n/a
Assume one full day
of operation: 24 hrs
* operating rate *
AP-42 Emission
Facto
EU 387 Air Compressor 11.28 171.12 0.00 11.76 SV 187 NA NA 40 1676 1.00 12000 80 Based on PTE Based on PTE n/a Based on PTE
Table 3-3 De Minimis Visibility Modeling Results
2002 2003 2004 2002 – 2004 Combined
Class I
Area with
Greatest
Impact Model Scenario
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
BWCA De Minimis 0.040 0 0.034 0 0.029 0 0.031 0
Table 4-1 Baseline Conditions Modeling Input Data and the Basis for 24-hour Emissions Data
EU # EU Description
SO2 Maximum
24-hr Emission
Rate (lbs/day)
NOx Maximum
24-hr Emission
Rate (lbs/day)
PM2.5
Maximum 24-hr
Emission Rate
(lbs/day)
PM10 Maximum
24-hr Emission
Rate (lbs/day) SV #
Stack
Easting
(utm)
Stack
Northing
(utm)
Height of
Opening
from
Ground (ft)
Base
Elevation
of
Ground
(ft)
Stack length,
width, or
Diameter (ft)
Flow Rate
at exit
(acfm)
Exit
Temp
(°F)
Basis for SO2 24-
hour Actual
Emissions
Basis for NOx 24-
hour Actual
Emissions
Basis for
PM2.5 24-
hour Actual
Emissions
Basis for PM10 24-
hour Actual
Emissions
Baseline Conditions - Utility Plant Heating Boilers
EU 001 Utility Plant Heating Boiler #1 0.41 194 n/a 5.3 SV 001 527605.4429 5268166.228 67.25 1682 4.5 17,000 380AP-42 Emission
Factor
AP-42 Emission
FactorN/A
AP-42 Emission
Factor
EU 002 Utility Plant Heating Boiler #2 1.54 720 n/a 19.5 SV 002 527612.1358 5268167.191 67.25 1682 4.5 17,000 380AP-42 Emission
Factor
AP-42 Emission
FactorN/A
AP-42 Emission
Factor
EU 003 Utility Plant Heating Boiler #3 0.23 106 n/a 2.9 SV 003 527619.1379 5268168.2 67.25 1682 4.5 20,800 380AP-42 Emission
Factor
AP-42 Emission
FactorN/A
AP-42 Emission
Factor
EU 004 Utility Plant Heating Boiler #4 0.49 231 n/a 6.3 SV 004 527626.9988 5268169.38 68.59 1682 4.5 25,500 380AP-42 Emission
Factor
AP-42 Emission
FactorN/A
AP-42 Emission
Factor
EU 005 Utility Plant Heating Boiler #5 0.49 226 n/a 6.1 SV 005 527633.9031 5268170.379 68.59 1682 4.5 25,500 380AP-42 Emission
Factor
AP-42 Emission
FactorN/A
AP-42 Emission
Factor
Baseline Conditions - Indurating Furnaces - Natural Gas Burning in Kiln
EU 223 Line 3 3072 19133 n/a 6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130Stack Test
May 2005
Stack Test
June 1997N/A
Stack Test
May 2005
EU 259 Line 4 3192 29520 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack Test
July 2006
Stack Test
April 2004N/A
Stack Test
July 2005
EU 280 Line 5 3192 29520 n/a 2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as Line 4 Same as line 4 N/AStack Test
May 2005
EU 313 Line 6 2520 26232 n/a 1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as Line 7 Same as line 7 N/AStack Test
April 2005
EU 332 Line 7 2520 26232 n/a 1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109Stack Test
June 2002
Stack Test
June 2002 N/A
Stack Test
April 2005
Baseline Conditions - Indurating Furnaces - Solid Fuel Burning in Kiln
EU 223 Line 3 3072 12168 n/a 6552 SV 103 528069.3977 5268291.49 116 1698 10.4 322,000 130Stack Test
March 1994
Stack Test
April 2004N/A
Stack Test
May 2005
EU 259 Line 4 3192 27360 n/a 2568 SV 118 528116.5749 5268294.618 139.6 1702 14.0 650,000 115Stack Test
July 2005
Stack Test
April 2004N/A
Stack Test
July 2005
EU 280 Line 5 3192 27360 n/a 2568 SV 127 528130.9199 5268296.414 139.6 1702 14.0 650,000 115 Same as line 4 Same as line 4 N/AStack Test
May 2005
EU 313 Line 6 4032 19440 n/a 1968 SV 144 528362.9511 5268243.387 140 1700 16.0 600,000 109 Same as line 7 Same as line 7 N/AStack Test
April 2005
EU 332 Line 7 4032 19440 n/a 1968 SV 151 528377.6897 5268245.79 140 1700 16.0 600,000 109Stack Test
March 1994
Stack Test
May 2004 N/A
Stack Test
April 2005
Table 4-2 Baseline Visibility Modeling Results Table 4-2 Baseline Visibility Modeling Results
2002 2003 2004 2002 – 2004 Combined
Modeling
Scenario SO2 NOx
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
0
Baseline
Indurating Furnaces
burning Natural Gas
Baseline
Indurating Furnaces
burning Natural Gas
BWCA 5.508 177 7.201 168 5.962 160 6.209 505
1
Baseline
Indurating Furnaces
burning
Solid Fuels
Baseline
Indurating Furnaces
burning
Solid Fuels
BWCA 4.78 173 6.377 162 5.26 155 5.52 490
Scenario Control Technology
Table 5-3 SO2 Control Cost Summary
Control
Technology
Installed Capital Cost
(MM$)
Operating Cost
(MM$/yr)
Annualized
Pollution
Control Cost
($/ton)
Line 3 $27,948,027 $5,322,323 $20,201
Line 4 $39,347,773 $8,448,332 $23,597
Line 5 $39,347,773 $8,448,332 $23,597
Line 6 $36,370,821 $7,939,628 $18,216
Line 7 $37,793,453 $8,123,761 $18,638
Line 3 $19,626,314 $2,816,433 $14,253
Line 4 $26,664,036 $4,123,939 $15,358
Line 5 $26,664,036 $4,123,939 $15,358
Line 6 $25,704,464 $3,953,025 $12,093
Line 7 $25,704,464 $3,953,025 $12,093
Secondary Wet Scrubber
Wet Walled Electrostatic Precipitator (WWESP)
Table 5-4 Indurating Furnace Post-BART SO2 Control - Predicted 24-hour Maximum Emission Rates
Scenario Control Technology SO2 NOx
Control
Scenario SV #
Emission
Unit SO2 NOx% Reduction
Max 24-hour
lbs/day % Reduction
Max 24-hour
lbs/day
SV 103 Line 3 30% 2,150 --- 19,128
SV 118 Line 4 --- 3,192 --- 29,520
SV 127 Line 5 --- 3,192 --- 29,520
SV 144 Line 6 --- 2,520 10% 23,609
SV 151 Line 7 --- 2,520 --- 26,232
SV 103 Line 3 30% 2,150 --- 12,168
SV 118 Line 4 --- 3,192 --- 27,360
SV 127 Line 5 --- 3,192 --- 27,360
SV 144 Line 6 --- 4,032 10% 17,496
SV 151 Line 7 --- 4,032 --- 19,440
2 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces Burning
Nat Gas
Current Operation
w/ line 6 Burners
Indurating Furances Burning
Nat Gas
3 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces Burning
Solid Fuel
Current Operation
w/ line 6 Burners
Indurating Furnaces Burning
Solid Fuel
Table 5-5 Post-BART SO2 Modeling Scenarios - Visibility Modeling Results
Scenario # SO2 NOx
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
0 Baseline
Indurating Furnaces
burning Natural Gas
Baseline
Indurating Furnaces
burning Natural Gas
BWCA 5.508 177 7.201 168 5.962 160 6.209 505
1 Baseline
Indurating Furnaces
burning
Solid Fuels
Baseline
Indurating Furnaces
burning
Solid Fuels
BWCA 4.78 173 6.377 162 5.26 155 5.52 490
2 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Current Operation
w/ line 6 Burners
Indurating Furances
Burning Nat Gas
BWCA 5.333 176 7.005 168 5.807 157 6.043 501
3 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Current Operation
w/ line 6 Burners
Indurating Furnaces
Burning Solid Fuel
BWCA 4.642 171 6.189 159 5.106 148 5.365 478
Scenario Control Technology 2004
2002 – 2004
Combined2002 2003
Table 5-8 Indurating Furnace NOx Control Cost Summary
Control
Technology
Installed
Capital Cost
(MM$)
Operating
Cost (MM$/yr)
Annualized
Pollution
Control Cost
($/ton)
Incremental
Control Cost
($/ton)
Line 3 $69,222,423 $19,513,772 $18,135 n/a
Line 4 $58,874,795 $28,169,433 $19,433 n/a
Line 5 $58,874,795 $28,169,433 $19,347 n/a
Line 6 $56,748,729 $26,419,264 $18,595 n/a
Line 7 $56,748,729 $26,419,264 $17,129 n/a
Line 3 n/a n/a n/a n/a
Line 4 $5,091,356 $480,588 $5,844 $5,076
Line 5 $6,474,892 $611,184 $5,974 $5,209
Line 6 n/a n/a n/a n/a
Line 7 n/a n/a n/a n/a
Line 3 n/a n/a n/a n/a
Line 4 $1,474,892 $139,219 $768 -$3,673
Line 5 $1,474,892 $139,219 $765 -$3,657
Line 6 n/a n/a n/a n/a
Line 7 $1,200,000 $113,272 $588 n/a
Line 3 $3,616,464 $341,369 $5,076 n/a
Line 4 $5,000,000 $471,965 $5,209 n/a
Line 5 $5,000,000 $471,965 $5,186 n/a
Line 6 n/a n/a n/a n/a
Line 7 n/a n/a n/a n/a
Low-NOx Burners
Ported Kilns
Selective Catalytic Reduction (SCR)
Low-NOx Burners + Ported Kilns
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates
Scenario Control Technology SO2 NOx
Control
Scenario SV #
Emission
Unit SO2 NOx% Reduction
Max 24-hour
lbs/day % Reduction
Max 24-hour
lbs/day
SV 103 Line 3 --- 2,150 5% 18,172
SV 118 Line 4 --- 3,192 5% 28,044
SV 127 Line 5 --- 3,192 5% 28,044
SV 144 Line 6 --- 2,520Ports already
installed23,609
SV 151 Line 7 --- 2,520Ports already
installed26,232
SV 103 Line 3 --- 2,150
No NOx
improvement
on solid fuels
12,168
SV 118 Line 4 --- 3,192
No NOx
improvement
on solid fuels
27,360
SV 127 Line 5 --- 3,192
No NOx
improvement
on solid fuels
27,360
SV 144 Line 6 --- 4,032
No NOx
improvement
on solid fuels
17,496
SV 151 Line 7 --- 4,032
No NOx
improvement
on solid fuels
19,440
4
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Nat Gas
5
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Solid Fuel
6
Table 5-10 Indurating Furnace Post- BART NOX Control - Predicted 24-hour Maximum Emission Rates
Scenario Control Technology SO2 NOx
Control
Scenario SV #
Emission
Unit SO2 NOx% Reduction
Max 24-hour
lbs/day % Reduction
Max 24-hour
lbs/day
4SV 103 Line 3 --- 2,150
low-NOx Not
Available19,128
SV 118 Line 4 --- 3,192 10% 26,568
SV 127 Line 5 --- 3,192 10% 26,568
SV 144 Line 6 --- 2,520
low-NOx
Already
Installed
23,609
SV 151 Line 7 --- 2,520 10% 23,609
SV 103 Line 3 --- 2,150low-NOx Not
Available12,168
SV 118 Line 4 --- 3,192 10% 24,624
SV 127 Line 5 --- 3,192 10% 24,624
SV 144 Line 6 --- 4,032
low-NOx
Already
Installed
17,496
SV 151 Line 7 --- 4,032 10% 17,496
SV 103 Line 3 --- 2,150 5% 18,172
SV 118 Line 4 --- 3,192 15% 25,092
SV 127 Line 5 --- 3,192 15% 25,092
SV 144 Line 6 --- 2,520 0% 23,609
SV 151 Line 7 --- 2,520 10% 23,609
SV 103 Line 3 --- 2,150 0% 12,168
SV 118 Line 4 --- 3,192 10% 24,624
SV 127 Line 5 --- 3,192 10% 24,624
SV 144 Line 6 --- 4,032 0% 17,496
SV 151 Line 7 --- 4,032 10% 17,496
6
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Nat Gas
7
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Solid Fuel
8 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
9 Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results
Scenario # Operating Conditions Operating Conditions
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
0
Baseline
Indurating Furnaces
burning Natural Gas
Baseline
Indurating Furnaces
burning Natural Gas
BWCA 5.508 177 7.201 168 5.962 160 6.209 505
1
Baseline
Indurating Furnaces
burning
Solid Fuels
Baseline
Indurating Furnaces
burning
Solid Fuels
BWCA 4.780 173 6.377 162 5.260 155 5.520 490
2
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Current Operation
w/ line 6 Burners
Indurating Furances
Burning Nat Gas
BWCA 5.333 176 7.005 168 5.807 157 6.043 501
3
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Current Operation
w/ line 6 Burners
Indurating Furnaces
Burning Solid Fuel
BWCA 4.642 171 6.189 159 5.106 148 5.365 478
4
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Nat Gas
BWCA 5.219 174 6.871 168 5.677 156 5.931 498
5
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Solid Fuel
BWCA 4.642 171 6.189 159 5.106 148 5.365 478
2002 2003 2004
2002 – 2004
Combined
Table 5-11 Indurating Furnace Post-BART NOX Modeling Scenarios - Visibility Modeling Results
Scenario # Operating Conditions Operating Conditions
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
2002 2003 2004
2002 – 2004
Combined
6
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Nat Gas
BWCA 5.088 174 6.713 166 5.542 153 5.758 493
7
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Solid Fuel
BWCA 4.408 165 5.912 153 4.858 142 5.095 460
8
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
Burning Nat Gas
BWCA 4.970 173 6.574 162 5.417 153 5.641 488
9
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Solid Fuel
BWCA 4.408 165 5.912 153 4.858 142 5.095 460
Table 5-14 Boiler NOx Control Cost Summary
Control Technology
Installed
Capital Cost
(MM$)
Operating
Cost
(MM$/yr)
Annualized
Pollution Control
Cost ($/ton)
Low Temperature Oxidation (LoTOx)
Utility Plant Heater Boiler #1 $1,681,680 $304,052 $23,668
Utility Plant Heater Boiler #2 $1,681,680 $304,052 $24,489
Utility Plant Heater Boiler #4 $1,914,641 $343,518 $25,720
Utility Plant Heater Boiler #5 $1,914,641 $343,518 $27,713
Selective Catalytic Reduction (SCR)
Utility Plant Heater Boiler #1 $4,488,567 $592,165 $50,632
Utility Plant Heater Boiler #2 $4,488,567 $592,165 $52,345
Utility Plant Heater Boiler #4 $5,234,392 $688,384 $56,028
Utility Plant Heater Boiler #5 $5,234,392 $688,384 $60,211
Low NOX Burner / Flue Gas Recirculation
Utility Plant Heater Boiler #1 $1,384,220 $166,560 $15,558
Utility Plant Heater Boiler #2 $1,384,220 $166,560 $16,098
Utility Plant Heater Boiler #4 $1,745,018 $209,678 $18,839
Utility Plant Heater Boiler #5 $1,745,018 $209,678 $20,299
Regenerative Selective Catalytic Reduction (R-SCR)
Utility Plant Heater Boiler #1 $1,690,961 $238,636 $22,879
Utility Plant Heater Boiler #2 $1,690,961 $238,636 $23,638
Utility Plant Heater Boiler #4 $2,156,692 $316,281 $28,633
Utility Plant Heater Boiler #5 $2,156,692 $316,281 $30,710
Low NOX Burner / Overfire Air (OFA)
Utility Plant Heater Boiler #1 $1,131,149 $136,590 $14,282
Utility Plant Heater Boiler #2 $1,131,149 $136,590 $14,778
Utility Plant Heater Boiler #4 $1,425,985 $171,954 $17,294
Utility Plant Heater Boiler #5 $1,425,985 $171,954 $18,634
Low NOX Burner
Utility Plant Heater Boiler #1 $344,269 $47,480 $6,653
Utility Plant Heater Boiler #2 $344,269 $47,480 $6,883
Utility Plant Heater Boiler #4 $434,003 $59,540 $8,024
Utility Plant Heater Boiler #5 $434,003 $59,540 $8,646
Selective Non-Catalytic Reduction (SNCR)
Utility Plant Heater Boiler #1 $1,084,406 $300,018 $42,037
Utility Plant Heater Boiler #2 $1,084,406 $300,018 $43,495
Utility Plant Heater Boiler #4 $1,277,232 $354,613 $47,792
Utility Plant Heater Boiler #5 $1,277,232 $354,613 $51,494
Table 5-15 Boiler Post-BART NOX Control - Predicted 24-hour Maximum Emission Rates
Scenario Control Technology NOx
Control
Scenario SV #
Emission
Unit NOx% Reduction Max 24-hour lbs/day
SV 001 EU 001 --- 194
SV 002 EU 002 --- 720
SV 004 EU 004 --- 231
SV 005 EU 005 --- 226
SV 001 EU 001 50% 97
SV 002 EU 002 50% 360
SV 004 EU 004 50% 115
SV 005 EU 005 50% 113
0
(baseline)
Baseline
Indurating Furnaces burning Natural
Gas
1
Utility Plant Heating Boilers
Low-NOx Burners
Table 5-16 Boiler Post-BART NOX Modeling Scenarios - Visibility Modeling Results
Scenario # SO2 NOx
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
0
Baseline
Indurating Furnaces
burning Natural Gas
Baseline
Indurating Furnaces
burning Natural Gas
BWCA 5.508 177 7.201 168 5.962 160 6.209 505
10
Baseline
Indurating Furnaces
burning Natural Gas
Utility Plant Heating
Boilers
Low-NOx Burners
BWCA 5.486 177 7.178 168 5.957 158 6.201 503
2002 – 2004
CombinedScenario Control Technology 2002 2003 2004
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results
Scenario # Operating Conditions Operating Conditions
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
0
Baseline
Indurating Furnaces
burning Natural Gas
Baseline
Indurating Furnaces
burning Natural Gas
BWCA 5.508 177 7.201 168 5.962 160 6.209 505
1
Baseline
Indurating Furnaces
burning
Solid Fuels
Baseline
Indurating Furnaces
burning
Solid Fuels
BWCA 4.78 173 6.377 162 5.26 155 5.52 490
2
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Current Operation
w/ line 6 Burners
Indurating Furances
Burning Nat Gas
BWCA 5.333 176 7.005 168 5.807 157 6.043 501
3
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Current Operation
w/ line 6 Burners
Indurating Furnaces
Burning Solid Fuel
BWCA 4.642 171 6.189 159 5.106 148 5.365 478
4
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Nat Gas
BWCA 5.219 174 6.871 168 5.677 156 5.931 498
5
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
Indurating Furances
Burning Solid Fuel
BWCA 4.642 171 6.189 159 5.106 148 5.365 478
2002 2003 2004
2002 – 2004
Combined
Table 6-1 Post-BART Modeling Scenarios - Visibility Modeling Results
Scenario # Operating Conditions Operating Conditions
Class I Area
with Greatest
Impact
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
Modeled 98th
Percentile
Value
(deciview)
No. of days
exceeding 0.5
deciview
2002 2003 2004
2002 – 2004
Combined
6
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Nat Gas
BWCA 5.088 174 6.713 166 5.542 153 5.758 493
7
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Solid Fuel
BWCA 4.408 165 5.912 153 4.858 142 5.095 460
8
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Nat Gas
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
Burning Nat Gas
BWCA 4.97 173 6.574 162 5.417 153 5.641 488
9
Current Operations
w/ Line 3 Scrubber
Indurating Furnaces
Burning Solid Fuel
Ported Kilns
(lines 3, 4, 5)
+
Low NOx Burners
(lines 4, 5, 7)
Indurating Furances
Burning Solid Fuel
BWCA 4.408 165 5.912 153 4.858 142 5.095 460
10
Baseline
Indurating Furnaces
burning Natural Gas
Utility Plant Heating
Boilers
Low-NOx Burners
BWCA 5.486 177 7.178 168 5.957 158 6.201 503
US Steel - Minntac 9/6/2006
BART Report - Attachment A: Emission Control Cost Analysis
Table A.1: Furnaces Cost Summary
NOx Control Cost Summary
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Annualized
Operating Cost $/yr
Pollution Control
Cost $/ton
Incremental
Control Cost
$/ton
Selective Catalytic Reduction with Reheat (SCR)
Line 3 80% 269.0 1076.0 $69,222,423 $19,513,772 $18,135 n/a
Line 4 80% 362.4 1449.6 $58,874,795 $28,169,433 $19,433 n/a
Line 5 80% 364.0 1456.0 $58,874,795 $28,169,433 $19,347 n/a
Line 6 80% 355.2 1420.8 $56,748,729 $26,419,264 $18,595 n/a
Line 7 80% 385.6 1542.4 $56,748,729 $26,419,264 $17,129 n/a
Low NOX Burners + Ported Kilns
Line 3 n/a n/a n/a n/a n/a n/a n/a
Line 4 15% 2908.6 248.5 $5,091,356 $480,588 $5,844 $5,076
Line 5 15% 3359.4 272.6 $6,474,892 $611,184 $5,974 $5,209
Line 6 n/a n/a n/a n/a n/a n/a n/a
Line 7 n/a n/a n/a n/a n/a n/a n/a
Low NOX Burners
Line 3 n/a n/a n/a n/a n/a n/a n/a
Line 4 10% 1630.8 181.2 $1,474,892 $139,219 $768 -$3,673
Line 5 10% 1638.0 182.0 $1,474,892 $139,219 $765 -$3,657
Line 6 n/a n/a n/a n/a n/a n/a n/a
Line 7 10% 1735.2 192.8 $1,200,000 $113,272 $588 n/a
Ported Kilns
Line 3 5% 1277.8 67.3 $3,616,464 $341,369 $5,076 n/a
Line 4 5% 1721.4 90.6 $5,000,000 $471,965 $5,209 n/a
Line 5 5% 1729.0 91.0 $5,000,000 $471,965 $5,186 n/a
Line 6 n/a n/a n/a n/a n/a n/a n/a
Line 7 n/a n/a n/a n/a n/a n/a n/a
SO2 Control Cost Summary
Control TechnologyControl
Eff %
Controlled
Emissions T/y
Emission
Reduction T/yr
Installed Capital
Cost $
Annualized
Operating Cost $/yr
Pollution Control
Cost $/ton
Incremental
Control Cost
$/ton
Line 3 80% 65.9 263.5 $27,948,027 $5,322,323 $20,201 n/a
Line 4 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a
Line 5 80% 89.5 358.0 $39,347,773 $8,448,332 $23,597 n/a
Line 6 80% 109.0 435.9 $36,370,821 $7,939,628 $18,216 n/a
Line 7 80% 109.0 435.9 $37,793,453 $8,123,761 $18,638 n/a
Line 3 60% 131.7 197.6 $19,626,314 $2,816,433 $14,253 n/a
Line 4 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a
Line 5 60% 179.0 268.5 $26,664,036 $4,123,939 $15,358 n/a
Line 6 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a
Line 7 60% 217.9 326.9 $25,704,464 $3,953,025 $12,093 n/a
Secondary Wet Scrubber
(after existing scrubber)
Wet Walled Electrostatic Precipitator (WWESP)
(after existing scrubber)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Cost Summary 9/7/2006 Page 1 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost 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 e-mail
Maintenance Labor 61 $/hr Per Chrissy Bartovich e-mail
Electricity 0.051 $/kwh 2006
Expected annual average industrial price of
electricity in the West North Central Division
for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage.htm
Natural Gas 9.2575 $/mscf 2005
Energy Information Administration. Average
US Industrial Natural Gas Prices. July '05 to
June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htm
Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail
Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail
Compressed Air 0.32 $/mscf 0.25 1998
EPA Air Pollution Control Cost Manual 6th
Ed 2002, Section 6 Chapter 1
Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%
inflation
Wastewater Disposal Neutralization 1.69 $/mgal 1.50 2002
EPA Air Pollution Control Cost Manual 6th
Ed 2002, Section 2 Chapter 2.5.5.5
Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 Ch
3 lists $1.30 - $2.15/1,000 gal
Chemicals & Supplies
Lime 91.40 $/ton 91.40 2006 Estimate from Cutler-Magney Company
Oxygen 40.00 $/ton 2006 BOC estimate.
Ammonia (29% aqua.) 0.12 $/lb 0.101 2000
EPA Air Pollution Control Cost Manual 6th
Ed 2002, Section 4 Chapter 2, page 2-50
Annual costs for a retrofit SCR system example problem. '00 costs
adjusted for 3% inflation.
Caustic 305.96 $/ton 280 2003 Hawkins Chemical 50% solution (50 Deg Be); includes delivery. '03 cost adjusted for inflation
SCR Catalyst 141.00 $/ft3
Cormetech, Inc.
Other
Sales Tax 6.5% %
Interest Rate 7.00% %
EPA Air Pollution Control Cost Manual
Introduction, Chapter 2, section 2.4.2. Social (discount) rate used as a default.
Operating Information
Annual Op. Hrs 7946 Hours Engineering Estimate
Utilization Rate 93%
Equipment Life 20 yrs Engineering Estimate
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Utility Chem$ Data 9/7/2006 Page 2 of 75
Standardized Flow Rate
SV 103 268,515 scfm @ 32º F Calculated.
SV 118 556,174 scfm @ 32º F Calculated.
SV 127 556,174 scfm @ 32º F Calculated.
SV 144 518,805 scfm @ 32º F Calculated.
SV 151 518,805 scfm @ 32º F Calculated.
Temperature
SV 103 130 Deg F BART spreadsheet.
SV 118 115 Deg F BART spreadsheet.
SV 127 115 Deg F BART spreadsheet.
SV 144 109 Deg F BART spreadsheet.
SV 151 109 Deg F BART spreadsheet.
Moisture Content
SV 103 10.5% Assumed value.
SV 118 10.5% Assumed value.
SV 127 10.5% Assumed value.
SV 144 10.5% Assumed value.
SV 151 10.5% Assumed value.
Actual Flow Rate
SV 103 322,000 acfm BART spreadsheet.
SV 118 650,000 acfm BART spreadsheet.
SV 127 650,000 acfm BART spreadsheet.
SV 144 600,000 acfm Same as line 7
SV 151 600,000 acfm BART spreadsheet.
Standardized Flow Rate
SV 103 288,163 scfm @ 68º F Calculated.
SV 118 596,870 scfm @ 68º F Calculated.
SV 127 596,870 scfm @ 68º F Calculated.
SV 144 556,766 scfm @ 68º F Calculated.
SV 151 556,766 scfm @ 68º F Calculated.
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Utility Chem$ Data 9/7/2006 Page 3 of 75
Dry Std Flow Rate
SV 103 257,906 dscfm @ 68º F Calculated.
SV 118 534,198 dscfm @ 68º F Calculated.
SV 127 534,198 dscfm @ 68º F Calculated.
SV 144 498,306 dscfm @ 68º F Calculated.
SV 151 498,306 dscfm @ 68º F Calculated.
24-hour
Max Emis Projected future actual lb/hr ton/year
Pollutant Lb/Hr emissions (tpy) ppmv ppmv Max 24 hour emissions source Projected future actual emissions source
Nitrous Oxides (NOx)
SV 103 876.9 1,345.0 474 166.1 Based on max stack test plus 10% Based on 2005 AEI plus 10%.
SV 118 1353.0 1,812.0 353 108.0 Based on max stack test plus 10% Based on 2005 AEI plus 10%.
SV 127 1353.0 1,820.0 353 108.5 Based on max stack test plus 10% Based on 2005 AEI plus 10%.
SV 144 1202.3 1,776.0 336 113.5 Based on max stack test plus 10% Based on 2005 AEI plus 10%.
SV 151 1202.3 1,928.0 336 123.2 Based on max stack test plus 10% Based on 2005 AEI plus 10%.
Sulfur Dioxides (SO2)
SV 103 98.6 329.3 38 29.2
Based on max stack test plus 10%, minus
30% to account for new scrubber.
Based on AEI avg 2004/2005 plus 10%., minus 30% to account for new
scrubber.
SV 118 146.3 447.5 27 19.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.
SV 127 146.3 447.5 27 19.2 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.
SV 144 184.8 544.8 37 25.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.
SV 151 184.8 544.8 37 25.0 Based on max stack test plus 10%. Based on AEI avg 2004/2005 plus 10%.
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Utility Chem$ Data 9/7/2006 Page 4 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 3 waste gas
Emission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering
Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 130 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F
Dry Std Flow Rate 257,906 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment 28,387,757
Purchased Equipment Total SCR Only 30,232,961
SCR + Reheat 30,950,318
Total Capital Investment (TCI) = DC + IC SCR + Reheat 69,222,423
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 11,235,240
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 8,288,440
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 19,513,772
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 876.9 1,345.0 80% 269.0 1,076.0 18,135
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 80% reduction
12 Site specific electricity costs
13 Catalyst replacement every 3 years.
14 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 SCR Line3 SCR 5 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 28,387,757
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 1,845,204
Freight 5% of control device cost (A) NA
Purchased Equipment Total 30,232,961
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 9% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 9% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,931,529
Total Plant Cost (D) A + B + C 37,808,389
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 756,168
Inventory Capital Reagent Vol * $/gal 102,618
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 38,667,175
Retrofit Factor (14) 60% of TCI 23,200,305
Sitework and foundations 1,400,000
Structural steel 4,800,000
Total Capital Investment Retrofit Installed 68,067,479
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 580,008
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization 245,543
SCR Catalyst 64.71 Catalyst Replacement 193,359
Ammonia (29% aqua.) 0.12 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization 2,694,872
Total Annual Direct Operating Costs 3,853,135
Indirect Operating Costs
Overhead 60% of total labor and material costs 94,284
Administration (2% total capital costs) 2% of total capital costs (TCI) 773,343
Property tax (1% total capital costs) 1% of total capital costs (TCI) 386,672
Insurance (1% total capital costs) 1% of total capital costs (TCI) 386,672
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,425,089
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,066,059
Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,919,195
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 SCR Line3 SCR 6 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst Estimate amount of catalyst required
Equipment Life 24,000 hours Vol. #1 2708 ft3
Cormetech, Inc.
FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc.
Rep part cost per unit $141 Flow #2 288,163 scfm
Vol #2 4408.7 ft3
Amount Required 4,409 ft3
Catalyst Cost 621,630
Y catalyst life factor 3 Years
Annualized Cost 193,359
Equivalent Duty 1,547 Plant Cap kW A 158,727
Est power platn eff 35% Unc Nox lb/mmBtu B 0.62 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 158,727 Capital Cost $/kW D $150.00 $23,809,086.67 Total SCR Equipment
Uncontrolled Nox t/y 3,840.9 Fixed O&M E $157,139.97
Annual Operating Hrs 7,946 Variable O&M F $394,208.98
Uncontrolled Nox lb/mmBtu 0.625 Ann Cap Factor G 0.82
Heat Input mmBtu/hr H 1,547
Electrical Use
Equivalent Duty 1,547 MMBtu/hr kW
NOx Cont Eff 80% Power 651.5
NOx in 0.62 lb/MMBtu
n catalyst layers 4 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 651.5
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
877 lb/hr Neat 404.0 gal/hr
29% solution Volume 14 day inventory 135,729 gal $102,618 Inventory Cost
3024 lb/hr
Design Basis Max Emis Control Eff (%)
lb/MMBtu 80%
Nitrous Oxides (NOx) 0.625
Actual 77,372 dscf/MMBtu
Method 19 Factor 10,000 dscf/MMBtu
Adjusted Duty 1,547 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 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 0.051 $/kwh 651.5 kW-hr 4,814,574 245,543 $/kwh, 652 kW-hr, 7946 hr/yr, 93% utilization
SCR Catalyst 141 $/ft3 193,359 Catalyst Replacement
Ammonia (29% aqua.) 0.12 $/lb 3024 lb/hr 22,345,675 2,694,872 $/lb, 3,024 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 SCR Line3 SCR 7 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Line 3 waste gas
Emission Unit Number EU 223 Stack/Vent Number SV 103 Chemical Engineering
Design Capacity 200 mmbtu/hr Standardized Flow Rate 268,515 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 130 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F
Dry Std Flow Rate 257,906 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 590,417
Purchased Equipment Total (B) 22% of control device cost (A) 717,356
Installation - Standard Costs 30% of purchased equip cost (B) 215,207
Installation - Site Specific Costs NA
Installation Total 215,207
Total Direct Capital Cost, DC 932,563
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380
Total Capital Investment (TCI) = DC + IC 1,154,944
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 7,382,105
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472
Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 Reheat Line3 Reheat 8 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 590,417
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 59,042
MN Sales Taxes 6.5% of control device cost (A) 38,377
Freight 5% of control device cost (A) 29,521
Purchased Equipment Total (B) 22% 717,356
Installation
Foundations & supports 8% of purchased equip cost (B) 57,389
Handling & erection 14% of purchased equip cost (B) 100,430
Electrical 4% of purchased equip cost (B) 28,694
Piping 2% of purchased equip cost (B) 14,347
Insulation 1% of purchased equip cost (B) 7,174
Painting 1% of purchased equip cost (B) 7,174
Installation Subtotal Standard Expenses 30% 215,207
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 35,868Contractor fees 10% of purchased equip cost (B) 71,736
Start-up 2% of purchased equip cost (B) 14,347
Performance test 1% of purchased equip cost (B) 7,174
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 21,521
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 222,380
Total Capital Investment (TCI) = DC + IC 1,154,944
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,154,944
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization 449,620
Natural Gas 9.26 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization 6,837,058
Total Annual Direct Operating Costs 7,382,105
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 23,099
Property tax (1% total capital costs) 1% of total capital costs (TCI) 11,549
Insurance (1% total capital costs) 1% of total capital costs (TCI) 11,549
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 109,019
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 212,472
Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,594,577
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 Reheat Line3 Reheat 9 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 322,000 19 0.6 1,193.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 322,000 23 0.6 1,444.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 1193.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1193.0 kW-hr 8,816,081 449,620 $/kwh, 1,193 kW-hr, 7946 hr/yr, 93% utilization
Natural Gas 9.26 $/mscf 1,666 scfm 738,543 6,837,058 $/mscf, 1,666 scfm, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 Reheat Line3 Reheat 10 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.a: NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 130 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 564 Deg F - Temperature of waste gas out of heat recovery
Tfo 316 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 288,163 scfm - Flow of waste gas
Qaf 1,666 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 289,828 scfm Flue Gas Cost in 1989 $'s $495,188
Current Cost Using CHE Plant Cost Index $590,417
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 Reheat Line3 Reheat 11 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118
Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment 23,050,831
Purchased Equipment Total SCR Only 24,549,135
SCR + Reheat 25,409,745
Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,812.0 80% 362.4 1,449.6 19,433
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 80% reduction
12 Site specific electricity costs
13 Catalyst replacement every 3 years.
14 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 SCR Line4 SCR 12 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 1,498,304
Freight 5% of control device cost (A) NA
Purchased Equipment Total 24,549,135
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,078,955
Total Plant Cost (D) A + B + C 31,271,989
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 625,440
Inventory Capital Reagent Vol * $/gal 158,329
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758
Retrofit Factor (14) 60% of TCI 19,233,455
Sitework and foundations 1,400,000
Structural steel 4,800,000
Total Capital Investment Retrofit Installed 57,489,212
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 480,836
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079
SCR Catalyst 64.71 Catalyst Replacement 400,504
Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919
Total Annual Direct Operating Costs 5,709,691
Indirect Operating Costs
Overhead 60% of total labor and material costs 91,281
Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115
Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558
Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087
Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 SCR Line4 SCR 13 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst Estimate amount of catalyst required
Equipment Life 24,000 hours Vol. #1 2708 ft3
Cormetech, Inc.
FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc.
Rep part cost per unit $141 Flow #2 596,870 scfm
Vol #2 9131.8 ft3
Amount Required 9,132 ft3
Catalyst Cost 1,287,579
Y catalyst life factor 3 Years
Annualized Cost 400,504
Equivalent Duty 3,484 Plant Cap kW A 357,359
Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment
Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49
Annual Operating Hrs 8000 Variable O&M F $624,082.60
Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82
Heat Input mmBtu/hr H 6,000
Electrical Use
Equivalent Duty 3,484 MMBtu/hr kW
NOx Cont Eff 80% Power 1,409.2
NOx in 0.43 lb/MMBtu
n catalyst layers 4 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1409.2
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
1353 lb/hr Neat 623.3 gal/hr
29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost
4666 lb/hr
Design Basis Max Emis Control Eff (%)
lb/MMBtu 80%
Nitrous Oxides (NOx) 0.428
Actual 106,840 dscf/MMBtu
Method 19 Factor 9,200 dscf/MMBtu
Adjusted Duty 3,484 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization
SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement
Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 SCR Line4 SCR 14 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118 Chemical Engineering
Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 115 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 708,321
Purchased Equipment Total (B) 22% of control device cost (A) 860,610
Installation - Standard Costs 30% of purchased equip cost (B) 258,183
Installation - Site Specific Costs NA
Installation Total 258,183
Total Direct Capital Cost, DC 1,118,793
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468
Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 Reheat Line4 Reheat 15 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 708,321
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 70,832
MN Sales Taxes 6.5% of control device cost (A) 46,041
Freight 5% of control device cost (A) 35,416
Purchased Equipment Total (B) 22% 860,610
Installation
Foundations & supports 8% of purchased equip cost (B) 68,849
Handling & erection 14% of purchased equip cost (B) 120,485
Electrical 4% of purchased equip cost (B) 34,424
Piping 2% of purchased equip cost (B) 17,212
Insulation 1% of purchased equip cost (B) 8,606
Painting 1% of purchased equip cost (B) 8,606
Installation Subtotal Standard Expenses 30% 258,183
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 43,031Contractor fees 10% of purchased equip cost (B) 86,061
Start-up 2% of purchased equip cost (B) 17,212
Performance test 1% of purchased equip cost (B) 8,606
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 25,818
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618
Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142
Total Annual Direct Operating Costs 15,416,187
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712
Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856
Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468
Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 Reheat Line4 Reheat 16 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 2408.3
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization
Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 Reheat Line4 Reheat 17 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.b - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 115 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 560 Deg F - Temperature of waste gas out of heat recovery
Tfo 306 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 596,870 scfm - Flow of waste gas
Qaf 3,511 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076
Current Cost Using CHE Plant Cost Index $708,321
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 Reheat Line4 Reheat 18 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127
Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment 23,050,831
Purchased Equipment Total SCR Only 24,549,135
SCR + Reheat 25,409,745
Total Capital Investment (TCI) = DC + IC SCR + Reheat 58,874,795
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 21,125,878
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 7,066,876
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 28,169,433
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,820.0 80% 364.0 1,456.0 19,347
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 80% reduction
12 Site specific electricity costs
13 Catalyst replacement every 3 years.
14 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 SCR Line5 SCR 19 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 23,050,831
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 1,498,304
Freight 5% of control device cost (A) NA
Purchased Equipment Total 24,549,135
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 4,078,955
Total Plant Cost (D) A + B + C 31,271,989
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 625,440
Inventory Capital Reagent Vol * $/gal 158,329
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 32,055,758
Retrofit Factor (14) 60% of TCI 19,233,455
Sitework and foundations 1,400,000
Structural steel 4,800,000
Total Capital Investment Retrofit Installed 57,489,212
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 480,836
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization 531,079
SCR Catalyst 64.71 Catalyst Replacement 400,504
Ammonia (29% aqua.) 0.12 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization 4,157,919
Total Annual Direct Operating Costs 5,709,691
Indirect Operating Costs
Overhead 60% of total labor and material costs 91,281
Administration (2% total capital costs) 2% of total capital costs (TCI) 641,115
Property tax (1% total capital costs) 1% of total capital costs (TCI) 320,558
Insurance (1% total capital costs) 1% of total capital costs (TCI) 320,558
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,426,575
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,800,087
Total Annual Cost (Annualized Capital Cost + Operating Cost) 12,509,778
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 SCR Line5 SCR 20 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst Estimate amount of catalyst required
Equipment Life 24,000 hours Vol. #1 2708 ft3
Cormetech, Inc.
FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc.
Rep part cost per unit $141 Flow #2 596,870 scfm
Vol #2 9131.8 ft3
Amount Required 9,132 ft3
Catalyst Cost 1,287,579
Y catalyst life factor 3 Years
Annualized Cost 400,504
Equivalent Duty 3,484 Plant Cap kW A 357,359
Est power platn eff 35% Unc Nox lb/mmBtu B 0.43 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 357,359 Capital Cost $/kW D $64.50 $23,050,831.27 Total SCR Equipment
Uncontrolled Nox t/y 1,353.0 Fixed O&M E $152,135.49
Annual Operating Hrs 8000 Variable O&M F $624,082.60
Uncontrolled Nox lb/mmBtu 0.428 Ann Cap Factor G 0.82
Heat Input mmBtu/hr H 6,000
SCR Capital Cost
Electrical Use
Duty 3,484 MMBtu/hr kW
NOx Cont Eff 80% Power 1,409.2
NOx in 0.43 lb/MMBtu
n catalyst layers 4 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1409.2
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
1353 lb/hr Neat 623.3 gal/hr
29% solution Volume 14 day inventory 209,416 gal $158,329 Inventory Cost
4666 lb/hr
Design Basis Max Emis Control Eff (%)
lb/MMBtu 80%
Nitrous Oxides (NOx) 0.428
Actual 106,840 dscf/MMBtu
Method 19 Factor 9,200 dscf/MMBtu
Adjusted Duty 3,484 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 480,836 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1409.2 kW-hr 10,413,319 531,079 $/kwh, 1,409 kW-hr, 7946 hr/yr, 93% utilization
SCR Catalyst 141 $/ft3 400,504 Catalyst Replacement
Ammonia (29% aqua.) 0.12 $/lb 4666 lb/hr 34,477,146 4,157,919 $/lb, 4,666 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 SCR Line5 SCR 21 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127 Chemical Engineering
Design Capacity 300 mmbtu/hr Standardized Flow Rate 556,174 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 115 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 708,321
Purchased Equipment Total (B) 22% of control device cost (A) 860,610
Installation - Standard Costs 30% of purchased equip cost (B) 258,183
Installation - Site Specific Costs NA
Installation Total 258,183
Total Direct Capital Cost, DC 1,118,793
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 15,416,187
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468
Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 Reheat Line5 Reheat 22 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 708,321
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 70,832
MN Sales Taxes 6.5% of control device cost (A) 46,041
Freight 5% of control device cost (A) 35,416
Purchased Equipment Total (B) 22% 860,610
Installation
Foundations & supports 8% of purchased equip cost (B) 68,849
Handling & erection 14% of purchased equip cost (B) 120,485
Electrical 4% of purchased equip cost (B) 34,424
Piping 2% of purchased equip cost (B) 17,212
Insulation 1% of purchased equip cost (B) 8,606
Painting 1% of purchased equip cost (B) 8,606
Installation Subtotal Standard Expenses 30% 258,183
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 43,031Contractor fees 10% of purchased equip cost (B) 86,061
Start-up 2% of purchased equip cost (B) 17,212
Performance test 1% of purchased equip cost (B) 8,606
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 25,818
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 266,789
Total Capital Investment (TCI) = DC + IC 1,385,582
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,385,582
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization 907,618
Natural Gas 9.26 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization 14,413,142
Total Annual Direct Operating Costs 15,416,187
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 27,712
Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,856
Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,856
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,789
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 243,468
Total Annual Cost (Annualized Capital Cost + Operating Cost) 15,659,655
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 Reheat Line5 Reheat 23 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 650,000 19 0.6 2,408.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 650,000 23 0.6 2,915.3 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 2408.3
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2408.3 kW-hr 17,796,438 907,618 $/kwh, 2,408 kW-hr, 7946 hr/yr, 93% utilization
Natural Gas 9.26 $/mscf 3,511 scfm 1,556,915 14,413,142 $/mscf, 3,511 scfm, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 Reheat Line5 Reheat 24 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.c - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 115 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 560 Deg F - Temperature of waste gas out of heat recovery
Tfo 306 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 596,870 scfm - Flow of waste gas
Qaf 3,511 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 600,381 scfm Flue Gas Cost in 1989 $'s $594,076
Current Cost Using CHE Plant Cost Index $708,321
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 Reheat Line5 Reheat 25 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 6 waste gas
Emission Unit Number EU 313 Stack/Vent Number SV 144
Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment 22,013,215
Purchased Equipment Total SCR Only 23,444,074
SCR + Reheat 24,289,858
Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,776.0 80% 355.2 1,420.8 18,595
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 80% reduction
12 Site specific electricity costs
13 Catalyst replacement every 3 years.
14 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 SCR Line6 SCR 26 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 1,430,859
Freight 5% of control device cost (A) NA
Purchased Equipment Total 23,444,074
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 3,913,196
Total Plant Cost (D) A + B + C 30,001,168
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 600,023
Inventory Capital Reagent Vol * $/gal 140,694
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886
Retrofit Factor (14) 60% of TCI 18,445,131
Sitework and foundations 1,400,000
Structural steel 4,800,000
Total Capital Investment Retrofit Installed 55,387,017
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 461,128
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304
SCR Catalyst 64.71 Catalyst Replacement 373,594
Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801
Total Annual Direct Operating Costs 5,162,181
Indirect Operating Costs
Overhead 60% of total labor and material costs 87,172
Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838
Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419
Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990
Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 SCR Line6 SCR 27 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst Estimate amount of catalyst required
Equipment Life 24,000 hours Vol. #1 2708 ft3
Cormetech, Inc.
FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc.
Rep part cost per unit $141 Flow #2 556,766 scfm
Vol #2 8518.2 ft3
Amount Required 8,518 ft3
Catalyst Cost 1,201,067
Y catalyst life factor 3 Years
Annualized Cost 373,594
Equivalent Duty 3,250 Plant Cap kW A 333,349
Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment
Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22
Annual Operating Hrs 8000 Variable O&M F $586,106.42
Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82
Heat Input mmBtu/hr H 6,000
SCR Capital Cost
Electrical Use
Duty 3,250 MMBtu/hr kW
NOx Cont Eff 80% Power 1,308.9
NOx in 0.41 lb/MMBtu
n catalyst layers 4 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1308.9
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
1202 lb/hr Neat 553.8 gal/hr
29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost
4146 lb/hr
Design Basis Max Emis Control Eff (%)
lb/MMBtu 80%
Nitrous Oxides (NOx) 0.408
Actual 99,661 dscf/MMBtu
Method 19 Factor 9,200 dscf/MMBtu
Adjusted Duty 3,250 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization
SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement
Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 SCR Line6 SCR 28 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Line 6 waste gas
Emission Unit Number EU 313 Stack/Vent Number SV 144 Chemical Engineering
Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 109 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 696,118
Purchased Equipment Total (B) 22% of control device cost (A) 845,784
Installation - Standard Costs 30% of purchased equip cost (B) 253,735
Installation - Site Specific Costs NA
Installation Total 253,735
Total Direct Capital Cost, DC 1,099,519
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260
Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 Reheat Line6 Reheat 29 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 696,118
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 69,612
MN Sales Taxes 6.5% of control device cost (A) 45,248
Freight 5% of control device cost (A) 34,806
Purchased Equipment Total (B) 22% 845,784
Installation
Foundations & supports 8% of purchased equip cost (B) 67,663
Handling & erection 14% of purchased equip cost (B) 118,410
Electrical 4% of purchased equip cost (B) 33,831
Piping 2% of purchased equip cost (B) 16,916
Insulation 1% of purchased equip cost (B) 8,458
Painting 1% of purchased equip cost (B) 8,458
Installation Subtotal Standard Expenses 30% 253,735
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 42,289Contractor fees 10% of purchased equip cost (B) 84,578
Start-up 2% of purchased equip cost (B) 16,916
Performance test 1% of purchased equip cost (B) 8,458
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 25,374
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802
Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605
Total Annual Direct Operating Costs 14,471,833
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234
Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617
Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260
Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 Reheat Line6 Reheat 30 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 2223.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization
Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 Reheat Line6 Reheat 31 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.d - NOx Control - Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 109 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 558 Deg F - Temperature of waste gas out of heat recovery
Tfo 301 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 556,766 scfm - Flow of waste gas
Qaf 3,298 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841
Current Cost Using CHE Plant Cost Index $696,118
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 Reheat Line6 Reheat 32 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 7 waste gas
Emission Unit Number EU 332 Stack/Vent Number SV 151
Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs EPRI Correlation
Purchased Equipment 22,013,215
Purchased Equipment Total SCR Only 23,444,074
SCR + Reheat 24,289,858
Total Capital Investment (TCI) = DC + IC SCR + Reheat 56,748,729
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 19,634,014
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 6,807,183
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 26,419,264
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,928.0 80% 385.6 1,542.4 17,129
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 For Calculation purposes, duty reflects increased flow rate, not actual duty.
3 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
4 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
5 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
6 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
7 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
8 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
9 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
10 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
11 Control Efficiency = 80% reduction
12 Site specific electricity costs
13 Catalyst replacement every 3 years.
14 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 SCR Line7 SCR 33 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 22,013,215
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) 1,430,859
Freight 5% of control device cost (A) NA
Purchased Equipment Total 23,444,074
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 11% Replacement Power, two weeks 2,643,899
Total Indirect Installation Costs (B) 11% of purchased equip cost (A) 2,643,899
Project Contingeny (C) 15% of (A + B) 3,913,196
Total Plant Cost (D) A + B + C 30,001,168
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 600,023
Inventory Capital Reagent Vol * $/gal 140,694
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 30,741,886
Retrofit Factor (14) 60% of TCI 18,445,131
Sitework and foundations 1,400,000
Structural steel 4,800,000
Total Capital Investment Retrofit Installed 55,387,017
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 461,128
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization 493,304
SCR Catalyst 64.71 Catalyst Replacement 373,594
Ammonia (29% aqua.) 0.12 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization 3,694,801
Total Annual Direct Operating Costs 5,162,181
Indirect Operating Costs
Overhead 60% of total labor and material costs 87,172
Administration (2% total capital costs) 2% of total capital costs (TCI) 614,838
Property tax (1% total capital costs) 1% of total capital costs (TCI) 307,419
Insurance (1% total capital costs) 1% of total capital costs (TCI) 307,419
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 5,228,143
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 6,544,990
Total Annual Cost (Annualized Capital Cost + Operating Cost) 11,707,171
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 SCR Line7 SCR 34 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst Estimate amount of catalyst required
Equipment Life 24,000 hours Vol. #1 2708 ft3
Cormetech, Inc.
FCW 0.3111 Flow #1 177,000 scfm Cormetech, Inc.
Rep part cost per unit $141 Flow #2 556,766 scfm
Vol #2 8518.2 ft3
Amount Required 8,518 ft3
Catalyst Cost 1,201,067
Y catalyst life factor 3 Years
Annualized Cost 373,594
Equivalent Duty 3,250 Plant Cap kW A 333,349
Est power platn eff 35% Unc Nox lb/mmBtu B 0.41 D=75*(300,000)*((B/1.5)^0.05*(C/100)^0.04)A)^0.35
Watt per Btu/hr 0.29307 Nox Red. Eff. C 80% E=D*A*0.0066
Equivalent power plant kW 333,349 Capital Cost $/kW D $66.04 $22,013,215.04 Total SCR Equipment
Uncontrolled Nox t/y 1,202.3 Fixed O&M E $145,287.22
Annual Operating Hrs 8000 Variable O&M F $586,106.42
Uncontrolled Nox lb/mmBtu 0.408 Ann Cap Factor G 0.82
Heat Input mmBtu/hr H 6,000
SCR Capital Cost
Electrical Use
Duty 3,250 MMBtu/hr kW
NOx Cont Eff 80% Power 1,308.9
NOx in 0.41 lb/MMBtu
n catalyst layers 4 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 1308.9
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
1202 lb/hr Neat 553.8 gal/hr
29% solution Volume 14 day inventory 186,091 gal $140,694 Inventory Cost
4146 lb/hr
Design Basis Max Emis Control Eff (%)
lb/MMBtu 80%
Nitrous Oxides (NOx) 0.408
Actual 99,661 dscf/MMBtu
Method 19 Factor 9,200 dscf/MMBtu
Adjusted Duty 3,250 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 461,128 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1308.9 kW-hr 9,672,634 493,304 $/kwh, 1,309 kW-hr, 7946 hr/yr, 93% utilization
SCR Catalyst 141 $/ft3 373,594 Catalyst Replacement
Ammonia (29% aqua.) 0.12 $/lb 4146 lb/hr 30,637,009 3,694,801 $/lb, 4,146 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 SCR Line7 SCR 35 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
Operating Unit: Line 7 waste gas
Emission Unit Number EU 332 Stack/Vent Number SV 151 Chemical Engineering
Design Capacity 300 mmbtu/hr Standardized Flow Rate 518,805 scfm @ 32º F Chemical Plant Cost Index
Expected Utilization Rate 93% Temperature 109 Deg F 1998/1999 390
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 696,118
Purchased Equipment Total (B) 22% of control device cost (A) 845,784
Installation - Standard Costs 30% of purchased equip cost (B) 253,735
Installation - Site Specific Costs NA
Installation Total 253,735
Total Direct Capital Cost, DC 1,099,519
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 14,471,833
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260
Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 Reheat Line7 Reheat 36 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 696,118
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 69,612
MN Sales Taxes 6.5% of control device cost (A) 45,248
Freight 5% of control device cost (A) 34,806
Purchased Equipment Total (B) 22% 845,784
Installation
Foundations & supports 8% of purchased equip cost (B) 67,663
Handling & erection 14% of purchased equip cost (B) 118,410
Electrical 4% of purchased equip cost (B) 33,831
Piping 2% of purchased equip cost (B) 16,916
Insulation 1% of purchased equip cost (B) 8,458
Painting 1% of purchased equip cost (B) 8,458
Installation Subtotal Standard Expenses 30% 253,735
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 42,289Contractor fees 10% of purchased equip cost (B) 84,578
Start-up 2% of purchased equip cost (B) 16,916
Performance test 1% of purchased equip cost (B) 8,458
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 25,374
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 262,193
Total Capital Investment (TCI) = DC + IC 1,361,712
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,361,712
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization 837,802
Natural Gas 9.26 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization 13,538,605
Total Annual Direct Operating Costs 14,471,833
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 27,234
Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,617
Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,617
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 128,536
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 240,260
Total Annual Cost (Annualized Capital Cost + Operating Cost) 14,712,093
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 Reheat Line7 Reheat 37 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 3 years
CRF 0.3811
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 600,000 19 0.6 2,223.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 600,000 23 0.6 2,691.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 2223.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2223.0 kW-hr 16,427,481 837,802 $/kwh, 2,223 kW-hr, 7946 hr/yr, 93% utilization
Natural Gas 9.26 $/mscf 3,298 scfm 1,462,447 13,538,605 $/mscf, 3,298 scfm, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 Reheat Line7 Reheat 38 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.3.e - NOx Control - Selective Catalytic Reduction with Reheat
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 109 Deg F - Temperature of waste gas into heat recovery
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 558 Deg F - Temperature of waste gas out of heat recovery
Tfo 301 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 556,766 scfm - Flow of waste gas
Qaf 3,298 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 560,065 scfm Flue Gas Cost in 1989 $'s $583,841
Current Cost Using CHE Plant Cost Index $696,118
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 Reheat Line7 Reheat 39 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.4.a: NOX Control - Low-NOX Burners
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Total Capital Investment (TCI) = DC + IC 1,474,892
Operating Costs(2)
Total Annual Cost (Annualized Capital Cost) 139,219
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 139,219
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Exit Conc. Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,812.0 10% 1630.8 181.2 768
Sulfur Dioxide (SO2) 146.3 447.5 0% NA NA NA
Notes & Assumptions
1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section
Cost is ratioed to Line 4 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on estimated reduction of line 6 total NOX emissions based on NOX CEMS
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.4.b: NOX Control - Low-NOX Burners
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Total Capital Investment (TCI) = DC + IC 1,474,892
Operating Costs(2)
Total Annual Cost (Annualized Capital Cost) 139,219
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 139,219
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Exit Conc. Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,820.0 10% 1638.0 182.0 765
Sulfur Dioxide (SO2) 146.3 447.5 0% NA NA NA
Notes & Assumptions
1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section
Cost is ratioed to Line 5 burner size using 6/10 rule based on Line 6 burner size of 117 mmbtu/hr and Line 6 cost of $1.2 million
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on estimated reduction of line 6 total NOX emissions based on NOX CEMS
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.4.c: NOX Control - Low-NOX Burners
Operating Unit: Line 7 waste gas
Emission Unit Number EU 332 Stack/Vent Number SV 151
Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Total Capital Investment (TCI) = DC + IC 1,200,000
Operating Costs(2)
Total Annual Cost (Annualized Capital Cost) 113,272
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 113,272
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Exit Conc. Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,928.0 10% 1735.2 192.8 588
Sulfur Dioxide (SO2) 184.8 544.8 0% NA NA NA
Notes & Assumptions
1 Total installed capital cost based on recent Low-NOX burner installation on Line 6 pre-heat section
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on estimated reduction of line 6 total NOX emissions based on NOX CEMS
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.5.a: NOX Control - Ported Kilns
Operating Unit: Line 3 waste gas
Emission Unit Number EU 223 Stack/Vent Number SV 103
Standardized Flow Rate 268,515 scfm @ 32º F
Expected Utilization Rate 93% Temperature 130 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F
Dry Std Flow Rate 257,906 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Minntac Line 4/5 Budget Estimate = 5,000,000$
Total Capital Investment (TCI) = DC + IC 3,616,464
Minntac Line 4/5 volumetric flow = 650,000 acfm
Operating Costs(2)
Minntac Line 3 volumetric flow = 378,824 acfm
Total Annual Cost (Annualized Capital Cost) 341,369
Use "6/10 Rule" to calculate Line 3 Cost = 3,616,464$
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 341,369
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 876.9 1,345.0 5% 1277.8 67.3 5,076
Notes & Assumptions
1 Capital costs based on Minntac Line 4/5 budget estimate and scaled to Line 3 stack flow rate.
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on report, "NOX Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.5.b: NOX Control - Ported Kilns
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000$
Operating Costs(2)
Total Annual Cost (Annualized Capital Cost) 471,965
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 471,965
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,812.0 5% 1721.4 90.6 5,209
Notes & Assumptions
1 Capital costs based on Minntac Line 4/5 budget estimate.
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on report, "NOX Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.5.c: NOX Control - Ported Kilns
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
Size 165 mmbtu/hr
CONTROL EQUIPMENT COSTS
Capital Costs(1)
Total Capital Investment (TCI) = DC + IC 5,000,000 Minntac Line 4/5 Budget Estimate = 5,000,000$
Operating Costs(2)
Total Annual Cost (Annualized Capital Cost) 471,965
Capital Recovery Factor
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Capital Recovery Cost 471,965
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Control Eff(3)
Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,820.0 5% 1729.0 91.0 5,186
Notes & Assumptions
1 Capital costs based on Minntac Line 4/5 budget estimate.
2 Total annualized cost is equal to the annualized capital cost.
3 Control efficiency based on report, "NOX Emissions Analysis Pre and Post Installation of Air Injection Ports on Line 7 at USS/Minntac."
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Line 3 waste gas
Emission Unit Number EU 223 Stack/Vent Number SV 103
Standardized Flow Rate 268,515 scfm @ 32º F
Expected Utilization Rate 93% Temperature 130 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F
Dry Std Flow Rate 257,906 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 4,994,311
Purchased Equipment Total (B) 22% of control device cost (A) 6,068,088
Installation - Standard Costs 67% of purchased equip cost (B) 4,065,619
Installation - Site Specific Costs 6,200,000
Installation Total 4,065,619
Total Direct Capital Cost, DC 10,133,707
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810
Total Capital Investment (TCI) = DC + IC 27,948,027
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 2,023,179
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144
Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0 - NASulfur Dioxide (SO2) 98.6 329.3 80% 65.9 263.5 20,201
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm
3 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 WWESP 9/7/2006 Page 46 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 4,994,311
Instrumentation 10% of control device cost (A) 499,431
MN Sales Taxes 6.5% of control device cost (A) 324,630
Freight 5% of control device cost (A) 249,716
Purchased Equipment Total (B) 22% 6,068,088
Installation
Foundations & supports 4% of purchased equip cost (B) 242,724
Handling & erection 50% of purchased equip cost (B) 3,034,044
Electrical 8% of purchased equip cost (B) 485,447
Piping 1% of purchased equip cost (B) 60,681
Insulation 2% of purchased equip cost (B) 121,362
Painting 2% of purchased equip cost (B) 121,362
Installation Subtotal Standard Expenses 67% 4,065,619
Total Direct Capital Cost, DC 10,133,707
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 1,213,618
Construction & field expenses 20% of purchased equip cost (B) 1,213,618
Contractor fees 10% of purchased equip cost (B) 606,809
Start-up 1% of purchased equip cost (B) 60,681
Performance test 1% of purchased equip cost (B) 60,681Model Studies 2% of purchased equip cost (B) 121,362
Contingencies 3% of purchased equip cost (B) 182,043
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 3,458,810
Total Capital Investment (TCI) = DC + IC 13,592,517
Retrofit multiplier3
60% of TCI 8,155,510
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 27,948,027
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 6,283
Maintenance Materials 1.00 % of Maintenance Labor 49,943
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization 286,765
Water 0.08 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 57,108
WW Treat Neutralization 1.69 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization 1,205,171
Caustic 305.96 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization 278,556Total Annual Direct Operating Costs 2,023,179
Indirect Operating Costs
Overhead 60% of total labor and material costs 117,347
Administration (2% total capital costs) 2% of total capital costs (TCI) 271,850
Property tax (1% total capital costs) 1% of total capital costs (TCI) 135,925
Insurance (1% total capital costs) 1% of total capital costs (TCI) 135,925
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,638,096
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,299,144
Total Annual Cost (Annualized Capital Cost + Operating Cost) 5,322,323
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 WWESP 9/7/2006 Page 47 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.a: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 322,000 10 582.8 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 30.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 76,157 147.7 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 760.9
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 1610.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 246.40 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 15.0 hr/wk 660 6,283 $/Hr, 15.0 hr/wk, 7946 hr/yr
Maint Mtls 1 % of Purchase Cost NA 49,943 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 760.9 kW-hr 5,622,840 286,765 $/kwh, 761 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/mgal 1,610.0 gpm 713,853 57,108 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/mgal 1,610.0 gpm 713,853 1,205,171 $/mgal, 1,610 gpm, 7946 hr/yr, 93% utilization
Caustic 305.96 $/ton 246.4 lb/hr 910 278,556 $/ton, 246 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line3 WWESP 9/7/2006 Page 48 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 7,612,198
Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821
Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710
Installation - Site Specific Costs 6,200,000
Installation Total 6,196,710
Total Direct Capital Cost, DC 15,445,530
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 39,347,773
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NASulfur Dioxide (SO2) 146.3 447.5 80% 89.5 358.0 23,597
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm
3 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 WWESP 9/7/2006 Page 49 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,612,198
Instrumentation 10% of control device cost (A) 761,220
MN Sales Taxes 6.5% of control device cost (A) 494,793
Freight 5% of control device cost (A) 380,610
Purchased Equipment Total (B) 22% 9,248,821
Installation
Foundations & supports 4% of purchased equip cost (B) 369,953
Handling & erection 50% of purchased equip cost (B) 4,624,410
Electrical 8% of purchased equip cost (B) 739,906
Piping 1% of purchased equip cost (B) 92,488
Insulation 2% of purchased equip cost (B) 184,976
Painting 2% of purchased equip cost (B) 184,976
Installation Subtotal Standard Expenses 67% 6,196,710
Total Direct Capital Cost, DC 15,445,530
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 1,849,764
Construction & field expenses 20% of purchased equip cost (B) 1,849,764
Contractor fees 10% of purchased equip cost (B) 924,882
Start-up 1% of purchased equip cost (B) 92,488
Performance test 1% of purchased equip cost (B) 92,488Model Studies 2% of purchased equip cost (B) 184,976
Contingencies 3% of purchased equip cost (B) 277,465
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 20,717,358
Retrofit multiplier3
60% of TCI 12,430,415
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 39,347,773
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683
Maintenance Materials 1.00 % of Maintenance Labor 76,122
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873
Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281
WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799
Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481Total Annual Direct Operating Costs 3,768,592
Indirect Operating Costs
Overhead 60% of total labor and material costs 136,895
Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347
Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174
Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 WWESP 9/7/2006 Page 50 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.b: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 1,536.0
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr
Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 1536.0 kW-hr 11,350,454 578,873 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/mgal 3,250.0 gpm 1,441,007 115,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization
Caustic 305.96 $/ton 365.8 lb/hr 1,351 413,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line4 WWESP 9/7/2006 Page 51 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 7,612,198
Purchased Equipment Total (B) 22% of control device cost (A) 9,248,821
Installation - Standard Costs 67% of purchased equip cost (B) 6,196,710
Installation - Site Specific Costs 6,200,000
Installation Total 6,196,710
Total Direct Capital Cost, DC 15,445,530
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 39,347,773
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,768,592
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0 - NASulfur Dioxide (SO2) 146.3 447.5 80% 89.5 358.0 23,597
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm
3 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 WWESP 9/7/2006 Page 52 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,612,198
Instrumentation 10% of control device cost (A) 761,220
MN Sales Taxes 6.5% of control device cost (A) 494,793
Freight 5% of control device cost (A) 380,610
Purchased Equipment Total (B) 22% 9,248,821
Installation
Foundations & supports 4% of purchased equip cost (B) 369,953
Handling & erection 50% of purchased equip cost (B) 4,624,410
Electrical 8% of purchased equip cost (B) 739,906
Piping 1% of purchased equip cost (B) 92,488
Insulation 2% of purchased equip cost (B) 184,976
Painting 2% of purchased equip cost (B) 184,976
Installation Subtotal Standard Expenses 67% 6,196,710
Total Direct Capital Cost, DC 15,445,530
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 1,849,764
Construction & field expenses 20% of purchased equip cost (B) 1,849,764
Contractor fees 10% of purchased equip cost (B) 924,882
Start-up 1% of purchased equip cost (B) 92,488
Performance test 1% of purchased equip cost (B) 92,488Model Studies 2% of purchased equip cost (B) 184,976
Contingencies 3% of purchased equip cost (B) 277,465
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,271,828
Total Capital Investment (TCI) = DC + IC 20,717,358
Retrofit multiplier3
60% of TCI 12,430,415
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 39,347,773
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 12,683
Maintenance Materials 1.00 % of Maintenance Labor 76,122
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization 578,873
Water 0.08 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 115,281
WW Treat Neutralization 1.69 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization 2,432,799
Caustic 305.96 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization 413,481Total Annual Direct Operating Costs 3,768,592
Indirect Operating Costs
Overhead 60% of total labor and material costs 136,895
Administration (2% total capital costs) 2% of total capital costs (TCI) 414,347
Property tax (1% total capital costs) 1% of total capital costs (TCI) 207,174
Insurance (1% total capital costs) 1% of total capital costs (TCI) 207,174
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,714,151
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,679,741
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,448,332
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 WWESP 9/7/2006 Page 53 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.c: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 650,000 10 1,176.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 61.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 153,733 298.2 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 1,536.0
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 3250.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 365.75 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 15.0 hr/wk 660 12,683 $/Hr, 15.0 hr/wk, 7946 hr/yr
Maint Mtls 1 % of Purchase Cost NA 76,122 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 1536.0 kW-hr 11,350,454 578,873 $/kwh, 1,536 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/mgal 3,250.0 gpm 1,441,007 115,281 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/mgal 3,250.0 gpm 1,441,007 2,432,799 $/mgal, 3,250 gpm, 7946 hr/yr, 93% utilization
Caustic 305.96 $/ton 365.8 lb/hr 1,351 413,481 $/ton, 366 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line5 WWESP 9/7/2006 Page 54 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Line 6 waste gas
Emission Unit Number EU 313 Stack/Vent Number SV 144
Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 6,928,558
Purchased Equipment Total (B) 22% of control device cost (A) 8,418,198
Installation - Standard Costs 67% of purchased equip cost (B) 5,640,193
Installation - Site Specific Costs 6,200,000
Installation Total 5,640,193
Total Direct Capital Cost, DC 14,058,391
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373
Total Capital Investment (TCI) = DC + IC 36,370,821
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,620,521
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107
Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0 - NASulfur Dioxide (SO2) 184.8 544.8 80% 109.0 435.9 18,216
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm
3 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 WWESP 9/7/2006 Page 55 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 6,928,558
Instrumentation 10% of control device cost (A) 692,856
MN Sales Taxes 6.5% of control device cost (A) 450,356
Freight 5% of control device cost (A) 346,428
Purchased Equipment Total (B) 22% 8,418,198
Installation
Foundations & supports 4% of purchased equip cost (B) 336,728
Handling & erection 50% of purchased equip cost (B) 4,209,099
Electrical 8% of purchased equip cost (B) 673,456
Piping 1% of purchased equip cost (B) 84,182
Insulation 2% of purchased equip cost (B) 168,364
Painting 2% of purchased equip cost (B) 168,364
Installation Subtotal Standard Expenses 67% 5,640,193
Total Direct Capital Cost, DC 14,058,391
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 1,683,640
Construction & field expenses 20% of purchased equip cost (B) 1,683,640
Contractor fees 10% of purchased equip cost (B) 841,820
Start-up 1% of purchased equip cost (B) 84,182
Performance test 1% of purchased equip cost (B) 84,182Model Studies 2% of purchased equip cost (B) 168,364
Contingencies 3% of purchased equip cost (B) 252,546
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 4,798,373
Total Capital Investment (TCI) = DC + IC 18,856,763
Retrofit multiplier3
60% of TCI 11,314,058
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 36,370,821
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 10,842
Maintenance Materials 1.00 % of Maintenance Labor 69,286
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization 526,675
Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413
WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661
Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292Total Annual Direct Operating Costs 3,620,521
Indirect Operating Costs
Overhead 60% of total labor and material costs 131,688
Administration (2% total capital costs) 2% of total capital costs (TCI) 377,135
Property tax (1% total capital costs) 1% of total capital costs (TCI) 188,568
Insurance (1% total capital costs) 1% of total capital costs (TCI) 188,568
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,433,148
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,319,107
Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,939,628
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 WWESP 9/7/2006 Page 56 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.d: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 131,418 255.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 1,397.5
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 15.0 hr/wk 660 10,842 $/Hr, 15.0 hr/wk, 7946 hr/yr
Maint Mtls 1 % of Purchase Cost NA 69,286 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 1397.5 kW-hr 10,326,966 526,675 $/kwh, 1,397 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization
Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line6 WWESP 9/7/2006 Page 57 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator
Operating Unit: Line 7 waste gas
Emission Unit Number EU 332 Stack/Vent Number SV 151
Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 7,255,257
Purchased Equipment Total (B) 22% of control device cost (A) 8,815,138
Installation - Standard Costs 67% of purchased equip cost (B) 5,906,142
Installation - Site Specific Costs 6,200,000
Installation Total 5,906,142
Total Direct Capital Cost, DC 14,721,280
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628
Total Capital Investment (TCI) = DC + IC 37,793,453
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 3,632,323
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0 - NASulfur Dioxide (SO2) 184.8 544.8 80% 109.0 435.9 18,638
Notes & Assumptions
1 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 3.
2 Original estimate from Durr. Used 0.6 power law factor to adjust price to stack flow rate acfm from bid basis of 291,000 acfm
3 CUECost Workbook Version 1.0, USEPA Document Page 2
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 WWESP 9/7/2006 Page 58 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)1
Purchased Equipment Costs (A)2 - ESP + auxiliary equipment 7,255,257
Instrumentation 10% of control device cost (A) 725,526
MN Sales Taxes 6.5% of control device cost (A) 471,592
Freight 5% of control device cost (A) 362,763
Purchased Equipment Total (B) 22% 8,815,138
Installation
Foundations & supports 4% of purchased equip cost (B) 352,606
Handling & erection 50% of purchased equip cost (B) 4,407,569
Electrical 8% of purchased equip cost (B) 705,211
Piping 1% of purchased equip cost (B) 88,151
Insulation 2% of purchased equip cost (B) 176,303
Painting 2% of purchased equip cost (B) 176,303
Installation Subtotal Standard Expenses 67% 5,906,142
Total Direct Capital Cost, DC 14,721,280
Indirect Capital Costs
Engineering, supervision 20% of purchased equip cost (B) 1,763,028
Construction & field expenses 20% of purchased equip cost (B) 1,763,028
Contractor fees 10% of purchased equip cost (B) 881,514
Start-up 1% of purchased equip cost (B) 88,151
Performance test 1% of purchased equip cost (B) 88,151Model Studies 2% of purchased equip cost (B) 176,303
Contingencies 3% of purchased equip cost (B) 264,454
Total Indirect Capital Costs, IC 57% of purchased equip cost (B) 5,024,628
Total Capital Investment (TCI) = DC + IC 19,745,908
Retrofit multiplier3
60% of TCI 11,847,545
Sitework and foundations Site Specific 1,400,000
Structural steel Site Specific 4,800,000
Site Specific - Other Site Specific NA
Total Site Specific Costs 6,200,000
Total Capital Investment (TCI) Retrofit Installed 37,793,453
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr 121,177
Supervisor 15% 15% of Operator Costs 18,176
Maintenance
Maintenance Labor 61.00 $/Hr, 15.0 hr/wk, 7946 hr/yr 11,707
Maintenance Materials 1.00 % of Maintenance Labor 72,553
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization 534,344
Water 0.08 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 106,413
WW Treat Neutralization 1.69 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization 2,245,661
Caustic 305.96 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization 522,292Total Annual Direct Operating Costs 3,632,323
Indirect Operating Costs
Overhead 60% of total labor and material costs 134,168
Administration (2% total capital costs) 2% of total capital costs (TCI) 394,918
Property tax (1% total capital costs) 1% of total capital costs (TCI) 197,459
Insurance (1% total capital costs) 1% of total capital costs (TCI) 197,459
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,567,435
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 4,491,439
Total Annual Cost (Annualized Capital Cost + Operating Cost) 8,123,761
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 WWESP 9/7/2006 Page 59 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.6.e: SO2 Control - Wet Walled Electrostatic Precipitator
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit
Amount Required 0
Total Rep Parts Cost 0
Installation Labor 0
Total Installed Cost 0
Annualized Cost 0
Electrical Use
Flow acfm D P in H2O kW
Fan Power 600,000 10 1,086.0 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.46
Fluid Head (ft) Pump Eff.
Pump Power 60 60% 56.5 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.47
Plate Area
ESP Power 141,907 275.3 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3 Eq 3.48
Total 1,417.8
Reagent Use & Other Operating Costs
gpm
Water 5.00 gal/min-kacfm 3000.00 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.6
lb/hr
Reagent Use 2.50 lb NaOH/lb SO2 462.00 lb/hr caustic
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61 $/Hr 2.0 hr/8 hr shift 1,987 121,177 $/Hr, 2.0 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 18,176 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 15.0 hr/wk 660 11,707 $/Hr, 15.0 hr/wk, 7946 hr/yr
Maint Mtls 1 % of Purchase Cost NA 72,553 EPA Cont Cost Manual 6th ed - Sec 6 Ch 3.4.1.1
Utilities, Supplies, Replacements & Waste ManagementElectricity 0.051 $/kwh 1417.8 kW-hr 10,477,342 534,344 $/kwh, 1,418 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/mgal 3,000.0 gpm 1,330,160 106,413 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/mgal 3,000.0 gpm 1,330,160 2,245,661 $/mgal, 3,000 gpm, 7946 hr/yr, 93% utilization
Caustic 305.96 $/ton 462.0 lb/hr 1,707 522,292 $/ton, 462 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See summary page for notes and assumptions
Y:\23\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Control Costs
Line7 WWESP 9/7/2006 Page 60 of 75
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.a: SO2 Control - Wet Scrubber
Operating Unit: Line 3 waste gas
Emission Unit Number EU 223 Stack/Vent Number SV 103
Standardized Flow Rate 268,515 scfm @ 32º F
Expected Utilization Rate 93% Temperature 130 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 322,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 288,163 scfm @ 68º F
Dry Std Flow Rate 257,906 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 3,453,270
Purchased Equipment Total (B) 22% of control device cost (A) 4,195,723
Installation - Standard Costs 85% of purchased equip cost (B) 3,566,365
Installation - Site Specific Costs 6,200,000
Installation Total 3,566,365
Total Direct Capital Cost, DC 7,762,088
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 629,358
Total Capital Investment (TCI) = DC + IC 19,626,314
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 570,934
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 876.9 1,345.0 0% 1345.0 - NA
Sulfur Dioxide (SO2) 98.6 329.3 60% 131.7 197.6 14,253
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2
Line3 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.a: SO2 Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 3,453,270
Instrumentation 10% of control device cost (A) 345,327
MN Sales Taxes 6.5% of control device cost (A) 224,463
Freight 5% of control device cost (A) 172,663
Purchased Equipment Total (B) 22% 4,195,723
Installation
Foundations & supports 12% of purchased equip cost (B) 503,487
Handling & erection 40% of purchased equip cost (B) 1,678,289
Electrical 1% of purchased equip cost (B) 41,957
Piping 30% of purchased equip cost (B) 1,258,717
Insulation 1% of purchased equip cost (B) 41,957
Painting 1% of purchased equip cost (B) 41,957
Installation Subtotal Standard Expenses 85% 3,566,365
Total Direct Capital Cost, DC 7,762,088
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 209,786
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 209,786Start-up 1% of purchased equip cost (B) 41,957Performance 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 multiplier5
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 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization 249,567
Water 0.08 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization 10,717
WW Treat Neutralization 1.69 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization 183,186
Lime 91.40 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization 32,037Total Annual Direct Operating Costs 570,934
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 167,829
Property tax (1% total capital costs) 1% of total capital costs (TCI) 83,914
Insurance (1% total capital costs) 1% of total capital costs (TCI) 83,914
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,852,585
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,245,499
Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,816,433
See Summary page for notes and assumptions
Line3 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.a: SO2 Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 322,000 8.55 0.7 - 460.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 12,236 gpm 1 60 0.7 - 197.2 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 302 gpm 1 60 0.7 - 4.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 662.2
Reagent Use & Other Operating Costs
Caustic Use 98.56 lb/hr SO2 2.50 lb NaOH/lb SO2 246.40 lb/hr Caustic
Lime Use 98.56 lb/hr SO2 0.96 lb Lime/lb SO2 94.86 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
12,236 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 302 gpm
Evaporation Loss4 = 57.42 gpm
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 662.2 kW-hr 4,893,479 249,567 $/kwh, 662 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/kgal 302.1 gpm 133,963 10,717 $/kgal, 302 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/kgal 244.7 gpm 108,506 183,186 $/kgal, 245 gpm, 7946 hr/yr, 93% utilization
Lime 91.4 $/ton 94.9 lb/hr 351 32,037 $/ton, 95 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Line3 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.b: SO2 Control - Wet Scrubber
Operating Unit: Line 4 waste gas
Emission Unit Number EU 259 Stack/Vent Number SV 118
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 5,263,384
Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011
Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759
Installation - Site Specific Costs 6,200,000
Installation Total 5,435,759
Total Direct Capital Cost, DC 11,830,771
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252
Total Capital Investment (TCI) = DC + IC 26,664,036
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,812.0 0% 1812.0 - NA
Sulfur Dioxide (SO2) 146.3 447.5 60% 179.0 268.5 15,358
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2
Line4 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.b: SO2 Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384
Instrumentation 10% of control device cost (A) 526,338
MN Sales Taxes 7% of control device cost (A) 342,120
Freight 5% of control device cost (A) 263,169
Purchased Equipment Total (B) 22% 6,395,011
Installation
Foundations & supports 12% of purchased equip cost (B) 767,401
Handling & erection 40% of purchased equip cost (B) 2,558,004
Electrical 1% of purchased equip cost (B) 63,950
Piping 30% of purchased equip cost (B) 1,918,503
Insulation 1% of purchased equip cost (B) 63,950
Painting 1% of purchased equip cost (B) 63,950
Installation Subtotal Standard Expenses 85% 5,435,759
Total Direct Capital Cost, DC 11,830,771
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 319,751
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 319,751Start-up 1% of purchased equip cost (B) 63,950Performance 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 multiplier5
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 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785
Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634
WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785
Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555Total Annual Direct Operating Costs 1,038,186
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800
Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900
Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939
See Summary page for notes and assumptions
Line4 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.b: SO2 Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 650,000 8.55 0.7 - 928.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 24,700 gpm 1 60 0.7 - 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 610 gpm 1 60 0.7 - 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 1336.7
Reagent Use & Other Operating Costs
Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic
Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
24,700 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 610 gpm
Evaporation Loss4 = 115.90 gpm
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization
Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Line4 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.c: SO2 Control - Wet Scrubber
Operating Unit: Line 5 waste gas
Emission Unit Number EU 280 Stack/Vent Number SV 127
Standardized Flow Rate 556,174 scfm @ 32º F
Expected Utilization Rate 93% Temperature 115 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 650,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 596,870 scfm @ 68º F
Dry Std Flow Rate 534,198 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 5,263,384
Purchased Equipment Total (B) 22% of control device cost (A) 6,395,011
Installation - Standard Costs 85% of purchased equip cost (B) 5,435,759
Installation - Site Specific Costs 6,200,000
Installation Total 5,435,759
Total Direct Capital Cost, DC 11,830,771
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 959,252
Total Capital Investment (TCI) = DC + IC 26,664,036
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,038,186
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,353.0 1,820.0 0% 1820.0 - NA
Sulfur Dioxide (SO2) 146.3 447.5 60% 179.0 268.5 15,358
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2
Line5 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.c: SO2 Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,263,384
Instrumentation 10% of control device cost (A) 526,338
MN Sales Taxes 7% of control device cost (A) 342,120
Freight 5% of control device cost (A) 263,169
Purchased Equipment Total (B) 22% 6,395,011
Installation
Foundations & supports 12% of purchased equip cost (B) 767,401
Handling & erection 40% of purchased equip cost (B) 2,558,004
Electrical 1% of purchased equip cost (B) 63,950
Piping 30% of purchased equip cost (B) 1,918,503
Insulation 1% of purchased equip cost (B) 63,950
Painting 1% of purchased equip cost (B) 63,950
Installation Subtotal Standard Expenses 85% 5,435,759
Total Direct Capital Cost, DC 11,830,771
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 319,751
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 319,751Start-up 1% of purchased equip cost (B) 63,950Performance 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 multiplier5
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 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization 503,785
Water 0.08 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization 21,634
WW Treat Neutralization 1.69 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization 369,785
Lime 91.40 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization 47,555Total Annual Direct Operating Costs 1,038,186
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 255,800
Property tax (1% total capital costs) 1% of total capital costs (TCI) 127,900
Insurance (1% total capital costs) 1% of total capital costs (TCI) 127,900
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,516,896
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,085,753
Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,123,939
See Summary page for notes and assumptions
Line5 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.c: SO2 Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 650,000 8.55 0.7 - 928.9 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 24,700 gpm 1 60 0.7 - 398.0 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 610 gpm 1 60 0.7 - 9.8 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 1336.7
Reagent Use & Other Operating Costs
Caustic Use 146.30 lb/hr SO2 2.50 lb NaOH/lb SO2 365.75 lb/hr Caustic
Lime Use 146.30 lb/hr SO2 0.96 lb Lime/lb SO2 140.81 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
24,700 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 610 gpm
Evaporation Loss4 = 115.90 gpm
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1336.7 kW-hr 9,878,141 503,785 $/kwh, 1,337 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/kgal 609.9 gpm 270,423 21,634 $/kgal, 610 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/kgal 494.0 gpm 219,033 369,785 $/kgal, 494 gpm, 7946 hr/yr, 93% utilization
Lime 91.4 $/ton 140.8 lb/hr 520 47,555 $/ton, 141 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Line5 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.d: SO2 Control - Wet Scrubber
Operating Unit: Line 6 waste gas
Emission Unit Number EU 313 Stack/Vent Number SV 144
Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 5,016,580
Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145
Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873
Installation - Site Specific Costs 6,200,000
Installation Total 5,180,873
Total Direct Capital Cost, DC 11,276,018
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272
Total Capital Investment (TCI) = DC + IC 25,704,464
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,776.0 0% 1776.0 - NA
Sulfur Dioxide (SO2) 184.8 544.8 60% 217.9 326.9 12,093
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2
Line6 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.d: SO2 Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580
Instrumentation 10% of control device cost (A) 501,658
MN Sales Taxes 7% of control device cost (A) 326,078
Freight 5% of control device cost (A) 250,829
Purchased Equipment Total (B) 22% 6,095,145
Installation
Foundations & supports 12% of purchased equip cost (B) 731,417
Handling & erection 40% of purchased equip cost (B) 2,438,058
Electrical 1% of purchased equip cost (B) 60,951
Piping 30% of purchased equip cost (B) 1,828,543
Insulation 1% of purchased equip cost (B) 60,951
Painting 1% of purchased equip cost (B) 60,951
Installation Subtotal Standard Expenses 85% 5,180,873
Total Direct Capital Cost, DC 11,276,018
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 304,757
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 304,757Start-up 1% of purchased equip cost (B) 60,951Performance 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 multiplier5
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 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032
Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970
WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340
Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069Total Annual Direct Operating Costs 981,838
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806
Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903
Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025
See Summary page for notes and assumptions
Line6 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.d: SO2 Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 600,000 8.55 0.7 - 857.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 22,800 gpm 1 60 0.7 - 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 563 gpm 1 60 0.7 - 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 1233.9
Reagent Use & Other Operating Costs
Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic
Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
22,800 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 563 gpm
Evaporation Loss4 = 106.99 gpm
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization
Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Line6 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.e: SO2 Control - Wet Scrubber
Operating Unit: Line 7 waste gas
Emission Unit Number EU 332 Stack/Vent Number SV 151
Standardized Flow Rate 518,805 scfm @ 32º F
Expected Utilization Rate 93% Temperature 109 Deg F
Expected Annual Hours of Operation 7,946 Hours Moisture Content 10.5%
Annual Interest Rate 7.0% Actual Flow Rate 600,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 556,766 scfm @ 68º F
Dry Std Flow Rate 498,306 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs (1)
Purchased Equipment (A) 5,016,580
Purchased Equipment Total (B) 22% of control device cost (A) 6,095,145
Installation - Standard Costs 85% of purchased equip cost (B) 5,180,873
Installation - Site Specific Costs 6,200,000
Installation Total 5,180,873
Total Direct Capital Cost, DC 11,276,018
Total Indirect Capital Costs, IC 15% of purchased equip cost (B) 914,272
Total Capital Investment (TCI) = DC + IC 25,704,464
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 981,838
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025
Actual
Emission Control Cost Calculation Emis
Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost
Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 1,202.3 1,928.0 0% 1928.0 - NA
Sulfur Dioxide (SO2) 184.8 544.8 60% 217.9 326.9 12,093
Notes & Assumptions
1 Original estimate from STS Consultants. Use 0.6 Power law factor to adjust price to stack flow rate from bid basis of 500,000 acfm.
2 Liquid/Gas ratio = 38 L/G = Gal/1,000 acf
3 Water Makeup Rate/Wastewater Discharge = 2.0% of circulating water rate
4 Evaporation rate calculated from steam table in Basic Principles and Calculations in Chemical Engineering Third Edition.
5 CUECost Workbook Version 1.0, USEPA Document Page 2
Line7 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.e: SO2 Control - Wet Scrubber
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 5,016,580
Instrumentation 10% of control device cost (A) 501,658
MN Sales Taxes 7% of control device cost (A) 326,078
Freight 5% of control device cost (A) 250,829
Purchased Equipment Total (B) 22% 6,095,145
Installation
Foundations & supports 12% of purchased equip cost (B) 731,417
Handling & erection 40% of purchased equip cost (B) 2,438,058
Electrical 1% of purchased equip cost (B) 60,951
Piping 30% of purchased equip cost (B) 1,828,543
Insulation 1% of purchased equip cost (B) 60,951
Painting 1% of purchased equip cost (B) 60,951
Installation Subtotal Standard Expenses 85% 5,180,873
Total Direct Capital Cost, DC 11,276,018
Indirect Capital Costs
Engineering, supervision 5% of purchased equip cost (B) 304,757
Construction & field expenses 0% of purchased equip cost (B) 0
Contractor fees 5% of purchased equip cost (B) 304,757Start-up 1% of purchased equip cost (B) 60,951Performance 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 multiplier5
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 37.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Supervisor 15% 15% of Operator Costs 4,544
Maintenance
Maintenance Labor 40.00 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr 30,294
Maintenance Materials 100% of maintenance labor costs 30,294
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization 465,032
Water 0.08 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization 19,970
WW Treat Neutralization 1.69 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization 341,340
Lime 91.40 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization 60,069Total Annual Direct Operating Costs 981,838
Indirect Operating Costs
Overhead 60% of total labor and material costs 57,256
Administration (2% total capital costs) 2% of total capital costs (TCI) 243,806
Property tax (1% total capital costs) 1% of total capital costs (TCI) 121,903
Insurance (1% total capital costs) 1% of total capital costs (TCI) 121,903
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 2,426,320
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,971,187
Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,953,025
See Summary page for notes and assumptions
Line7 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.7.e: SO2 Control - Wet Scrubber
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst:
Equipment Life 20 years
CRF 0.0000
Rep part cost per unit 0 $/ft3
Amount Required 0 ft3
Packing Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0.00 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Scrubber 600,000 8.55 0.7 - 857.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.48
Flow Liquid SPGR ∆ P ft H2O Efficiency Hp kWCirc Pump 22,800 gpm 1 60 0.7 - 367.4 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
H2O WW Disch 563 gpm 1 60 0.7 - 9.1 EPA Cost Cont Manual 6th ed Section 5.2 Chapter 1 Eq 1.49
Other
Total 1233.9
Reagent Use & Other Operating Costs
Caustic Use 184.80 lb/hr SO2 2.50 lb NaOH/lb SO2 462.00 lb/hr Caustic
Lime Use 184.80 lb/hr SO2 0.96 lb Lime/lb SO2 177.87 lb/hr lime, lime addition at 1.1 times the stoichiometric ratio
Liquid/Gas ratio 38.0 * L/G = Gal/1,000 acf
Circulating Water Rate2
22,800 gpm
Water Makeup Rate/WW Disch3 = 2.0% of circulating water rate + evap. loss = 563 gpm
Evaporation Loss4 = 106.99 gpm
Operating Cost Calculations Annual hours of operation: 7,946
Utilization Rate: 93%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Supervisor 15% of Op. NA 4,544 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 497 30,294 $/Hr, 0.5 hr/8 hr shift, 7946 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 30,294 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1233.9 kW-hr 9,118,284 465,032 $/kwh, 1,234 kW-hr, 7946 hr/yr, 93% utilization
Water 0.08 $/kgal 563.0 gpm 249,621 19,970 $/kgal, 563 gpm, 7946 hr/yr, 93% utilization
WW Treat Neutralization 1.69 $/kgal 456.0 gpm 202,184 341,340 $/kgal, 456 gpm, 7946 hr/yr, 93% utilization
Lime 91.4 $/ton 177.9 lb/hr 657 60,069 $/ton, 178 lb/hr, 7946 hr/yr, 93% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
Line7 Wet Scrubber
US Steel - Minntac
BART Report - Attachment A: Emission Control Cost Analysis
Table A.8: Utility Plant Heater Boilers Cost Summary
NOx Control Cost Summary
Control TechnologyControl Eff
%
Controlled
Emissions
T/y
Emission
Reduction
T/yr
Installed
Capital Cost $
Annualized
Operating
Cost $/yr
Pollution
Control
Cost $/ton
Low Temperature Oxidation (LoTOx)
Utility Plant Heater Boiler #1 90% 1.43 12.85 $1,681,680 $304,052 $23,668
Utility Plant Heater Boiler #2 90% 1.38 12.42 $1,681,680 $304,052 $24,489
Utility Plant Heater Boiler #4 90% 1.48 13.36 $1,914,641 $343,518 $25,720
Utility Plant Heater Boiler #5 90% 1.38 12.40 $1,914,641 $343,518 $27,713
Selective Catalytic Reduction (SCR)
Utility Plant Heater Boiler #1 80% 2.92 11.70 $4,488,567 $592,165 $50,632
Utility Plant Heater Boiler #2 80% 2.83 11.31 $4,488,567 $592,165 $52,345
Utility Plant Heater Boiler #4 80% 3.07 12.29 $5,234,392 $688,384 $56,028
Utility Plant Heater Boiler #5 80% 2.86 11.43 $5,234,392 $688,384 $60,211
Low NOX Burner / Flue Gas Recirculation
Utility Plant Heater Boiler #1 75% 3.57 10.71 $1,384,220 $166,560 $15,558
Utility Plant Heater Boiler #2 75% 3.45 10.35 $1,384,220 $166,560 $16,098
Utility Plant Heater Boiler #4 75% 3.71 11.13 $1,745,018 $209,678 $18,839
Utility Plant Heater Boiler #5 75% 3.44 10.33 $1,745,018 $209,678 $20,299
Regenerative Selective Catalytic Reduction (R-SCR)
Utility Plant Heater Boiler #1 70% 4.47 10.43 $1,690,961 $238,636 $22,879
Utility Plant Heater Boiler #2 70% 4.33 10.10 $1,690,961 $238,636 $23,638
Utility Plant Heater Boiler #4 70% 4.73 11.05 $2,156,692 $316,281 $28,633
Utility Plant Heater Boiler #5 70% 4.41 10.30 $2,156,692 $316,281 $30,710
Low NOX Burner / Overfire Air (OFA)
Utility Plant Heater Boiler #1 67% 4.71 9.56 $1,131,149 $136,590 $14,282
Utility Plant Heater Boiler #2 67% 4.55 9.24 $1,131,149 $136,590 $14,778
Utility Plant Heater Boiler #4 67% 4.90 9.94 $1,425,985 $171,954 $17,294
Utility Plant Heater Boiler #5 67% 4.55 9.23 $1,425,985 $171,954 $18,634
Low NOX Burner
Utility Plant Heater Boiler #1 50% 7.14 7.14 $344,269 $47,480 $6,653
Utility Plant Heater Boiler #2 50% 6.90 6.90 $344,269 $47,480 $6,883
Utility Plant Heater Boiler #4 50% 7.42 7.42 $434,003 $59,540 $8,024
Utility Plant Heater Boiler #5 50% 6.89 6.89 $434,003 $59,540 $8,646
Selective Non-Catalytic Reduction (SNCR)
Utility Plant Heater Boiler #1 50% 7.14 7.14 $1,084,406 $300,018 $42,037
Utility Plant Heater Boiler #2 50% 6.90 6.90 $1,084,406 $300,018 $43,495
Utility Plant Heater Boiler #4 50% 7.42 7.42 $1,277,232 $354,613 $47,792
Utility Plant Heater Boiler #5 50% 6.89 6.89 $1,277,232 $354,613 $51,494
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
Cost Summary Cost Summary 1 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.9: Summary of Utility, Chemical and Supply Costs
Operating Unit: Utility Plant Heater Boiler #1 Study Year 2006
Emission Unit Number EU 001
Stack/Vent Number SV 001
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002
Stack/Vent Number SV 002
Operating Unit: Utility Plant Heater Boiler #3
Emission Unit Number EU 003
Stack/Vent Number SV 003
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004
Stack/Vent Number SV 004
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005
Stack/Vent Number SV 005
Reference
Item Unit Cost Units Cost Year Data Source Notes
Operating Labor 61.00 $/hr Per Chrissy Bartovich e-mail
Maintenance Labor 61.00 $/hr Per Chrissy Bartovich e-mail
Electricity 0.051 $/kwh 2006
Expected annual average industrial price of
electricity in the West North Central Division
for 2007 - DOE http://tonto.eia.doe.gov/steo_query/app/elecpage.htm
Natural Gas 9.2575 $/mscf 2005
Energy Information Administration. Average
US Industrial Natural Gas Prices. July '05 to
June '06. http://tonto.eia.doe.gov/dnav/ng/hist/n3035us3m.htm
Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail
Cooling Water 0.08 $/mgal 2006 Per Chrissy Bartovich e-mail
Ch 1 Carbon Adsrobers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and
3% inflation
Compressed Air 0.32 $/kscf 0.25 1998
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6 Chapter 1
Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3%
inflation
Wastewater Disposal Bio-Treat 4.28 $/kgal 3.80 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 5.2 Chapter 1
Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost
adjusted for 3% inflation
Hazardous Waste Disposal 281.38 $/ton 250.00 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 2 Chapter 2.5.5.5
Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3%
inflation
Waste Transport 0.56 $/ton-mi 0.50 2002
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation
Chemicals & Supplies
Urea 405 $/ton 2005 Hawkins Chemical 50% solution of urea in water, includes delivery
Oxygen 40.00 $/ton BOC
Ammonia (29% aqua.) 0.12 $/lb 0.101 2000
EPA Air Pollution Control Cost Manual 6th Ed
2002, Section 5 Chapter 2, page 2-50
Annual costs for a retrofit SCR system example problem. '00 costs
adjusted for 3% inflation.
Catayst & Replacement Parts
SCR Catalyst 141.00 $/ft3
Cormetech, Inc.
Other
Sales Tax 6.5 %
Interest Rate 7.0% %
Please note, for units of measure, k = 1,000 units, MM = 1,000,000 units e.g. kgal = 1,000 gal
Operating Information
Annual Op. Hrs
Utility Plant Heater Boiler #1 3,156 Hours
Average actual operating hours based on 2004
and 2005 emission inventories
Utility Plant Heater Boiler #2 3,156 Hours
Utility Plant Heater Boiler #3 3,156 Hours
Utility Plant Heater Boiler #4 3,156 Hours
Utility Plant Heater Boiler #5 3,156 Hours
Utilization Rate
Utility Plant Heater Boiler #1 28%
Average actual utilization rate based on 2004
and 2005 emission inventories
Utility Plant Heater Boiler #2 28%
Utility Plant Heater Boiler #3 28%
Utility Plant Heater Boiler #4 28%
Utility Plant Heater Boiler #5 28%
Equipment Life 20 yrs Engineering Estimate
Desgin Capacity
Utility Plant Heater Boiler #1 104 MMBtu/hr
Utility Plant Heater Boiler #2 104 MMBtu/hr
Utility Plant Heater Boiler #3 125 MMBtu/hr
Utility Plant Heater Boiler #4 153 MMBtu/hr
Utility Plant Heater Boiler #5 153 MMBtu/hr
Standardized Flow Rate
Utility Plant Heater Boiler #1 11,005 scfm @ 32º F
Utility Plant Heater Boiler #2 11,005 scfm @ 32º F
Utility Plant Heater Boiler #3 13,465 scfm @ 32º F
Utility Plant Heater Boiler #4 16,508 scfm @ 32º F
Utility Plant Heater Boiler #5 16,508 scfm @ 32º F
Temperature
Utility Plant Heater Boiler #1 380 Deg F
Utility Plant Heater Boiler #2 380 Deg F
Utility Plant Heater Boiler #3 380 Deg F
Utility Plant Heater Boiler #4 380 Deg F
Utility Plant Heater Boiler #5 380 Deg F
Moisture Content
Utility Plant Heater Boiler #1 13.3%
Utility Plant Heater Boiler #2 13.3%
Utility Plant Heater Boiler #3 13.3%
Utility Plant Heater Boiler #4 13.3%
Utility Plant Heater Boiler #5 13.3%
Actual Flow Rate
Utility Plant Heater Boiler #1 17,000 acfm
Utility Plant Heater Boiler #2 17,000 acfm
Utility Plant Heater Boiler #3 20,800 acfm
Utility Plant Heater Boiler #4 25,500 acfm
Utility Plant Heater Boiler #5 25,500 acfm
Standardized Flow Rate
Utility Plant Heater Boiler #1 11,811 scfm @ 68º F
Utility Plant Heater Boiler #2 11,811 scfm @ 68º F
Utility Plant Heater Boiler #3 14,451 scfm @ 68º F
Utility Plant Heater Boiler #4 17,716 scfm @ 68º F
Utility Plant Heater Boiler #5 17,716 scfm @ 68º F
Dry Std Flow Rate
Utility Plant Heater Boiler #1 10,240 dscfm @ 68º F
Utility Plant Heater Boiler #2 10,240 dscfm @ 68º F
Utility Plant Heater Boiler #3 12,529 dscfm @ 68º F
Utility Plant Heater Boiler #4 15,360 dscfm @ 68º F
Utility Plant Heater Boiler #5 15,360 dscfm @ 68º F
Design Basis Baseline Emis. Baseline Emis. Max Emis. (Model) Max Emis.
Pollutant T/yr lb/MMBtu lb/hr lb/mmbtu
Nitrous Oxides (NOx)
Utility Plant Heater Boiler #1 14.3 0.03 29.2 0.28
Utility Plant Heater Boiler #2 13.8 0.03 29.2 0.28
Utility Plant Heater Boiler #3 1.7 0.00 34.9 0.28
Utility Plant Heater Boiler #4 14.8 0.02 42.9 0.28
Utility Plant Heater Boiler #5 13.8 0.02 42.9 0.28
Max emissions based on limited potential
emissions as reported in the BART
spreadsheet. Baseline emissions are based
on 2005 emission inventory.
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
Utility Chem$ Data Utility Chem$ Data 2 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 768,944
Purchased Equipment Total (B) 22% of control device cost (A) 934,267
Installation - Standard Costs 45% of purchased equip cost (B) 420,420
Total Direct Capital Cost, DC 1,354,687
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993
Total Capital Investment (TCI) = DC + IC 1,681,680
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747
Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.3 90% 1.4 12.8 23,668
Notes & Assumptions
1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter.
Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
2 Handling and erection of ozone generators included in estimate from PCI Wedeco
3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project.
4 Oxygen plant site prep costs divided between all 5 lines
5 In order for LoTOx to work, a scrubber needs to be installed to capture NOX that has been converted to HNO3 and N2O5. This analysis
does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs;
however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LoTOx #1 LoTOx 3 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)(1)
Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 768,944
Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894
MN Sales Taxes 6.5% of control device cost (A) 49,981
Freight 5% of control device cost (A) 38,447
Purchased Equipment Total (B) 22% 934,267
Installation
Foundations & supports 12% of purchased equip cost (B) 112,112
Handling & erection(2)
0% of purchased equip cost (B) 0
Electrical 1% of purchased equip cost (B) 9,343
Piping 30% of purchased equip cost (B) 280,280
Insulation 1% of purchased equip cost (B) 9,343
Painting 1% of purchased equip cost (B) 9,343
Installation Subtotal Standard Expenses 45% 420,420
Total Direct Capital Cost, DC 1,354,687
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 93,427
Construction & field expenses 10% of purchased equip cost (B) 93,427
Contractor fees 10% of purchased equip cost (B) 93,427
Start-up 1% of purchased equip cost (B) 9,343
Performance test 1% of purchased equip cost (B) 9,343
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 28,028
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993
Total Capital Investment (TCI) = DC + IC 1,681,680
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534
Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502
Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367
Total Annual Direct Operating Costs 55,305
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634
Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817
Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747
Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LoTOx #1 LoTOx 4 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.a: NOx Control - LoTOx - (Low Temperature Oxidation)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
Flow acfm ∆∆∆∆ P in H2O Efficiency Hp kW
Blower, Scrubber 17,000 No extra load on blower
Flow Liquid SPGR ∆∆∆∆ P ft H2O Efficiency Hp kW
Circ Pump 126 gpm No extra load on circulation pump
H2O WW Disch 2 gpm No extra load on discharge pump
kW-hr
LoTOx Electric Use 4 kW/lb O3 189 per estimate from PCI Wedeco
Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2
Total 189
Reagent Use & Other Operating Costs
Ozone Needed 1.62 lb O3/lb NOx 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC
Oxygen Needed 10% wt O2 to O3 conversion 473.4 lb/hr O2 5,311 scfh O2
Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco
Circulating Water Rate 126.3 gpm
Water Makeup Rate 5.8 gpm
WW Discharge (blowdown) 2.2 gpm
Nitrate loading (as NaNO3) in scrubber water 49 lb/hr NaNO3
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 189.4 kW-hr 167,342 8,534 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization
Cooling Water 0.08 $/mgal 118.4 gpm 6,275 502 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization
Oxygen 40.00 $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LoTOx #1 LoTOx 5 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 768,944
Purchased Equipment Total (B) 22% of control device cost (A) 934,267
Installation - Standard Costs 45% of purchased equip cost (B) 420,420
Total Direct Capital Cost, DC 1,354,687
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993
Total Capital Investment (TCI) = DC + IC 1,681,680
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 55,305
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747
Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 13.8 90% 1.4 12.4 24,489
Notes & Assumptions
1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter.
Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
2 Handling and erection of ozone generators included in estimate from PCI Wedeco
3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project.
4 Oxygen plant site prep costs divided between all 5 lines
5 In order for LoTOx to work, a scrubber needs to be installed to capture NOX that has been converted to HNO3 and N2O5. This analysis
does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs;
however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LoTOx #2 LoTOx 6 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)(1)
Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 768,944
Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 76,894
MN Sales Taxes 6.5% of control device cost (A) 49,981
Freight 5% of control device cost (A) 38,447
Purchased Equipment Total (B) 22% 934,267
Installation
Foundations & supports 12% of purchased equip cost (B) 112,112
Handling & erection(2)
0% of purchased equip cost (B) 0
Electrical 1% of purchased equip cost (B) 9,343
Piping 30% of purchased equip cost (B) 280,280
Insulation 1% of purchased equip cost (B) 9,343
Painting 1% of purchased equip cost (B) 9,343
Installation Subtotal Standard Expenses 45% 420,420
Installation Total
Total Direct Capital Cost, DC 1,354,687
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 93,427
Construction & field expenses 10% of purchased equip cost (B) 93,427
Contractor fees 10% of purchased equip cost (B) 93,427
Start-up 1% of purchased equip cost (B) 9,343
Performance test 1% of purchased equip cost (B) 9,343
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 28,028
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 326,993
Total Capital Investment (TCI) = DC + IC 1,681,680
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,681,680
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization 8,534
Cooling Water 0.08 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization 502
Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 8,367
Total Annual Direct Operating Costs 55,305
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 33,634
Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,817
Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,817
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 158,739
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 248,747
Total Annual Cost (Annualized Capital Cost + Operating Cost) 304,052
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LoTOx #2 LoTOx 7 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.b: NOx Control - LoTOx - (Low Temperature Oxidation)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
Flow acfm ∆∆∆∆ P in H2O Efficiency Hp kW
Blower, Scrubber 17,000 No extra load on blower
Flow Liquid SPGR ∆∆∆∆ P ft H2O Efficiency Hp kW
Circ Pump 126 gpm No extra load on circulation pump
H2O WW Disch 2 gpm No extra load on discharge pump
kW-hr
LoTOx Electric Use 4 kW/lb O3 189 per estimate from PCI Wedeco
Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2
Total 189
Reagent Use & Other Operating Costs
Ozone Needed 1.62 lb O3/lb NOx 47.3 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC
Oxygen Needed 10% wt O2 to O3 conversion 473.4 lb/hr O2 5,311 scfh O2
Ozone generators Cooling Water 150 gal/lb O3 118 gpm per estimate from PCI Wedeco
Circulating Water Rate 126.3 gpm
Water Makeup Rate 5.8 gpm
WW Discharge (blowdown) 2.2 gpm
Nitrate loading (as NaNO3) in scrubber water 49 lb/hr NaNO3
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 189.4 kW-hr 167,342 8,534 $/kwh, 189 kW-hr, 3156 hr/yr, 28% utilization
Cooling Water 0.08 $/mgal 118.4 gpm 6,275 502 $/mgal, 118 gpm, 3156 hr/yr, 28% utilization
Oxygen 40.00 $/ton 0.2 ton/hr 209 8,367 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LoTOx #2 LoTOx 8 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 875,464
Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689
Installation - Standard Costs 45% of purchased equip cost (B) 478,660
Total Direct Capital Cost, DC 1,542,349
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291
Total Capital Investment (TCI) = DC + IC 1,914,641
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055
Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.8 90% 1.5 13.4 25,720
Notes & Assumptions
1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter.
Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
2 Handling and erection of ozone generators included in estimate from PCI Wedeco
3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project.
4 Oxygen plant site prep costs divided between all 5 lines
5 In order for LoTOx to work, a scrubber needs to be installed to capture NOX that has been converted to HNO3 and N2O5. This analysis
does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs;
however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LoTOx #4 LoTOx 9 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)(1)
Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464
Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546
MN Sales Taxes 6.5% of control device cost (A) 56,905
Freight 5% of control device cost (A) 43,773
Purchased Equipment Total (B) 22% 1,063,689
Installation
Foundations & supports 12% of purchased equip cost (B) 127,643
Handling & erection(2)
0% of purchased equip cost (B) 0
Electrical 1% of purchased equip cost (B) 10,637
Piping 30% of purchased equip cost (B) 319,107
Insulation 1% of purchased equip cost (B) 10,637
Painting 1% of purchased equip cost (B) 10,637
Installation Subtotal Standard Expenses 45% 478,660
Total Direct Capital Cost, DC 1,542,349
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 106,369
Construction & field expenses 10% of purchased equip cost (B) 106,369
Contractor fees 10% of purchased equip cost (B) 106,369
Start-up 1% of purchased equip cost (B) 10,637
Performance test 1% of purchased equip cost (B) 10,637
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 31,911
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291
Total Capital Investment (TCI) = DC + IC 1,914,641
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535
Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737
Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289
Total Annual Direct Operating Costs 63,463
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293
Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146
Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055
Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LoTOx #4 LoTOx 10 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.c: NOx Control - LoTOx - (Low Temperature Oxidation)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
Flow acfm ∆∆∆∆ P in H2O Efficiency Hp kW
Blower, Scrubber 25,500 No extra load on blower
Flow Liquid SPGR ∆∆∆∆ P ft H2O Efficiency Hp kW
Circ Pump 189 gpm No extra load on circulation pump
H2O WW Disch 3 gpm No extra load on discharge pump
kW-hr
LoTOx Electric Use 4 kW/lb O3 278 per estimate from PCI Wedeco
Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2
Total 278
Reagent Use & Other Operating Costs
Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC
Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2
Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco
Circulating Water Rate 189.4 gpm
Water Makeup Rate 8.7 gpm
WW Discharge (blowdown) 3.2 gpm
Nitrate loading (as NaNO3) in scrubber water 71 lb/hr NaNO3
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization
Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization
Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LoTOx #4 LoTOx 11 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 875,464
Purchased Equipment Total (B) 22% of control device cost (A) 1,063,689
Installation - Standard Costs 45% of purchased equip cost (B) 478,660
Total Direct Capital Cost, DC 1,542,349
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291
Total Capital Investment (TCI) = DC + IC 1,914,641
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 63,463
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055
Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 13.8 90% 1.4 12.4 27,713
Notes & Assumptions
1 Capital cost estimated based on quote from PCI Wedeco and scaled linearly using boiler exhaust flow rate as design parameter.
Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 (absorbers)
2 Handling and erection of ozone generators included in estimate from PCI Wedeco
3 Site prep cost estimates per Rob Wilmunen of Minntac. Based on site prep costs of a recent project.
4 Oxygen plant site prep costs divided between all 5 lines
5 In order for LoTOx to work, a scrubber needs to be installed to capture NOX that has been converted to HNO3 and N2O5. This analysis
does not include costs for a scrubber or treatment of scrubber blowdown water. A scrubber would significantly increase the costs;
however, this analysis clearly shows that LoTOx would not be economically feasible, despite the exclusion of the extra costs.
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LoTOx #5 LoTOx 12 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A)(1)
Purchased Equipment Costs (A) - Ozone generator (estimate from PCI Wedeco) 875,464
Instrumentation for LoTOx Injection 10% of ozone generator cost (A) 87,546
MN Sales Taxes 6.5% of control device cost (A) 56,905
Freight 5% of control device cost (A) 43,773
Purchased Equipment Total (B) 22% 1,063,689
Installation
Foundations & supports 12% of purchased equip cost (B) 127,643
Handling & erection(2)
0% of purchased equip cost (B) 0
Electrical 1% of purchased equip cost (B) 10,637
Piping 30% of purchased equip cost (B) 319,107
Insulation 1% of purchased equip cost (B) 10,637
Painting 1% of purchased equip cost (B) 10,637
Installation Subtotal Standard Expenses 45% 478,660
Total Direct Capital Cost, DC 1,542,349
Indirect Capital Costs
Engineering, supervision 10% of purchased equip cost (B) 106,369
Construction & field expenses 10% of purchased equip cost (B) 106,369
Contractor fees 10% of purchased equip cost (B) 106,369
Start-up 1% of purchased equip cost (B) 10,637
Performance test 1% of purchased equip cost (B) 10,637
Model Studies NA of purchased equip cost (B) NA
Contingencies 3% of purchased equip cost (B) 31,911
Total Indirect Capital Costs, IC 35% of purchased equip cost (B) 372,291
Total Capital Investment (TCI) = DC + IC 1,914,641
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,914,641
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization 12,535
Cooling Water 0.08 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization 737
Oxygen 40.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 12,289
Total Annual Direct Operating Costs 63,463
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 38,293
Property tax (1% total capital costs) 1% of total capital costs (TCI) 19,146
Insurance (1% total capital costs) 1% of total capital costs (TCI) 19,146
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 180,729
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 280,055
Total Annual Cost (Annualized Capital Cost + Operating Cost) 343,518
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LoTOx #5 LoTOx 13 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A-10.d: NOx Control - LoTOx - (Low Temperature Oxidation)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
Flow acfm ∆∆∆∆ P in H2O Efficiency Hp kW
Blower, Scrubber 25,500 No extra load on blower
Flow Liquid SPGR ∆∆∆∆ P ft H2O Efficiency Hp kW
Circ Pump 189 gpm No extra load on circulation pump
H2O WW Disch 3 gpm No extra load on discharge pump
kW-hr
LoTOx Electric Use 4 kW/lb O3 278 per estimate from PCI Wedeco
Total Oxygen Plant Electric Use 12,900 kW - cost accounted for in $/ton of O2
Total 278
Reagent Use & Other Operating Costs
Ozone Needed 1.62 lb O3/lb NOx 69.5 lb/hr O3 lb O3/lb NOx requirements from Naresh Suchak of BOC
Oxygen Needed 10% wt O2 to O3 conversion 695.3 lb/hr O2 7,801 scfh O2
Ozone generators Cooling Water 150 gal/lb O3 174 gpm per estimate from PCI Wedeco
Circulating Water Rate 189.4 gpm
Water Makeup Rate 8.7 gpm
WW Discharge (blowdown) 3.2 gpm
Nitrate loading (as NaNO3) in scrubber water 71 lb/hr NaNO3
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 278.1 kW-hr 245,784 12,535 $/kwh, 278 kW-hr, 3156 hr/yr, 28% utilization
Cooling Water 0.08 $/mgal 173.8 gpm 9,217 737 $/mgal, 174 gpm, 3156 hr/yr, 28% utilization
Oxygen 40.00 $/ton 0.3 ton/hr 307 12,289 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LoTOx #5 LoTOx 14 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs 2000 2,173,722
Purchased Equipment (A) 2005 2,585,117
Purchased Equipment Total (B) SCR + Reheat 2,907,528
Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.6 80% 2.92 11.7 50,632
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 SCR #1 SCR 15 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117
Instrumentation 0% of control device cost (A) NA
ND Sales Taxes 0.0% of control device cost (A) NA
Freight 0% of control device cost (A) NA
Purchased Equipment Total (A) 0% 2,585,117
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 31% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012
Project Contingeny (C) 15% of (A + B) 507,169
Total Plant Cost (D) A + B + C 3,888,299
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 77,766
Inventory Capital Reagent Vol * $/gal 3,420
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 59,542
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565
Cat. Replacement 346.28 Catalyst Replacement 2,705
Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739
Total Annual Direct Operating Costs 76,551
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691
Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 SCR #1 SCR 16 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 24,000 hours
FCW 0.0975
Rep part cost per unit 141 $/ft3
# of Layers 10
Replacement Factor 8Layers replaced per year = 3.3
Amount Required 197 ft3
Catalyst Cost 27,753
Y catalyst life factor 8 Years
Annualized Cost 2,705
SCR Capital Cost per EPRI Method 2,173,722
Duty 104 MMBtu/hr Catalyst Area 50 ft2
308 f (h SCR)
Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst)
Temperature 380 Deg F h SCR 81 ft f (h SCR)
Catalyst Volume 1,509 ft3
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/MMBtun catalyst layers 11 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 79.1
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
29 lb/hr Neat 13.5 gal/hr
29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost
101 lb/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization
Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement
Ammonia (29% aqua.) 0.12059928 $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 265,359
Purchased Equipment Total (B) 22% of control device cost (A) 322,412
Installation - Standard Costs 30% of purchased equip cost (B) 96,724
Installation - Site Specific Costs NA
Installation Total 96,724
Total Direct Capital Cost, DC 419,135
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502
Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 265,359
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 26,536
ND Sales Taxes 6.5% of control device cost (A) 17,248
Freight 5% of control device cost (A) 13,268
Purchased Equipment Total (B) 22% 322,412
Installation
Foundations & supports 8% of purchased equip cost (B) 25,793
Handling & erection 14% of purchased equip cost (B) 45,138
Electrical 4% of purchased equip cost (B) 12,896
Piping 2% of purchased equip cost (B) 6,448
Insulation 1% of purchased equip cost (B) 3,224
Painting 1% of purchased equip cost (B) 3,224
Installation Subtotal Standard Expenses 30% 96,724
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 16,121Contractor fees 10% of purchased equip cost (B) 32,241
Start-up 2% of purchased equip cost (B) 6,448
Performance test 1% of purchased equip cost (B) 3,224
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 9,672
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839
Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681
Total Annual Direct Operating Costs 48,421
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382
Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191
Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502
Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 17,000 19 0.6 63.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 17,000 23 0.6 76.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 63.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.a: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 380 Deg F - Temperature of waste gas into heat recovery
Tfi 450 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 429 Deg F - Temperature of waste gas out of heat recovery
Tfo 401 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 11,811 scfm - Flow of waste gas
Qaf 16 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560
Current Cost Using CHE Plant Cost Index $265,359
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
NOx Due to Duct Burner
939 scf/hr Flow of natural gas required
1.0 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.345 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs 2000 2,173,722
Purchased Equipment (A) 2005 2,585,117
Purchased Equipment Total (B) SCR + Reheat 2,907,528
Total Capital Investment (TCI) = DC + IC SCR + Reheat 4,488,567
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 124,972
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 467,193
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 592,165
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.1 80% 2.83 11.3 52,345
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 2,585,117
Instrumentation 0% of control device cost (A) NA
ND Sales Taxes 0.0% of control device cost (A) NA
Freight 0% of control device cost (A) NA
Purchased Equipment Total (A) 0% 2,585,117
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 31% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 31% of purchased equip cost (A) 796,012
Project Contingeny (C) 15% of (A + B) 507,169
Total Plant Cost (D) A + B + C 3,888,299
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 77,766
Inventory Capital Reagent Vol * $/gal 3,420
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 3,969,484
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 59,542
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization 3,565
Cat. Replacement 346.28 Catalyst Replacement 2,705
Ammonia (29% aqua.) 0.12 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization 10,739
Total Annual Direct Operating Costs 76,551
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 374,691
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 374,691
Total Annual Cost (Annualized Capital Cost + Operating Cost) 451,242
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 SCR #2 SCR 23 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 24,000 hours
FCW 0.0975
Rep part cost per unit 141 $/ft3
# of Layers 10
Replacement Factor 8Layers replaced per year = 3.3
Amount Required 197 ft3
Catalyst Cost 27,753
Y catalyst life factor 8 Years
Annualized Cost 2,705
SCR Capital Cost per EPRI Method 2,173,722
Duty 104 MMBtu/hr Catalyst Area 50 ft2
308 f (h SCR)
Q flue gas 48,166 acfm Rx Area 58 1,273 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 7.6 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 11 layers 362,172 f (vol catalyst)
Temperature 380 Deg F h SCR 81 ft f (h SCR)
Catalyst Volume 1,509 ft3
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/MMBtun catalyst layers 11 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 79.1
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
29 lb/hr Neat 13.5 gal/hr
29% solution Volume 14 day inventory 4,523 gal $3,420 Inventory Cost
101 lb/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 59,542 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 79.1 kW-hr 69,892 3,565 $/kwh, 79 kW-hr, 3156 hr/yr, 28% utilization
Cat. Replacement 346 $/ft3 2,705 Catalyst Replacement
Ammonia (29% aqua.) 0.12059928 $/lb 101 lb/hr 89,050 10,739 $/lb, 101 lb/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 265,359
Purchased Equipment Total (B) 22% of control device cost (A) 322,412
Installation - Standard Costs 30% of purchased equip cost (B) 96,724
Installation - Site Specific Costs NA
Installation Total 96,724
Total Direct Capital Cost, DC 419,135
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 48,421
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502
Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 265,359
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 26,536
ND Sales Taxes 6.5% of control device cost (A) 17,248
Freight 5% of control device cost (A) 13,268
Purchased Equipment Total (B) 22% 322,412
Installation
Foundations & supports 8% of purchased equip cost (B) 25,793
Handling & erection 14% of purchased equip cost (B) 45,138
Electrical 4% of purchased equip cost (B) 12,896
Piping 2% of purchased equip cost (B) 6,448
Insulation 1% of purchased equip cost (B) 3,224
Painting 1% of purchased equip cost (B) 3,224
Installation Subtotal Standard Expenses 30% 96,724
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 16,121Contractor fees 10% of purchased equip cost (B) 32,241
Start-up 2% of purchased equip cost (B) 6,448
Performance test 1% of purchased equip cost (B) 3,224
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 9,672
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 99,948
Total Capital Investment (TCI) = DC + IC 519,083
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 519,083
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization 2,839
Natural Gas 9.26 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization 7,681
Total Annual Direct Operating Costs 48,421
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 10,382
Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,191
Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,191
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 48,998
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 92,502
Total Annual Cost (Annualized Capital Cost + Operating Cost) 140,923
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 17,000 19 0.6 63.0 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 17,000 23 0.6 76.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 63.0
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 63.0 kW-hr 55,659 2,839 $/kwh, 63 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 16 scfm 830 7,681 $/mscf, 16 scfm, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.b: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 380 Deg F - Temperature of waste gas into heat recovery
Tfi 450 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 429 Deg F - Temperature of waste gas out of heat recovery
Tfo 401 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 11,811 scfm - Flow of waste gas
Qaf 16 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 11,826 scfm Flue Gas Cost in 1989 $'s $222,560
Current Cost Using CHE Plant Cost Index $265,359
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
NOx Due to Duct Burner
939 scf/hr Flow of natural gas required
1.0 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.345 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs 2000 2,667,517
Purchased Equipment (A) 2005 3,172,367
Purchased Equipment Total (B) SCR + Reheat 3,529,175
Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 15.4 80% 3.1 12.3 56,028
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367
Instrumentation 0% of control device cost (A) NA
ND Sales Taxes 0.0% of control device cost (A) NA
Freight 0% of control device cost (A) NA
Purchased Equipment Total (A) 0% 3,172,367
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 25% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012
Project Contingeny (C) 15% of (A + B) 595,257
Total Plant Cost (D) A + B + C 4,563,637
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 91,273
Inventory Capital Reagent Vol * $/gal 5,023
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 69,899
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244
Cat. Replacement 346.28 Catalyst Replacement 3,979
Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773
Total Annual Direct Operating Costs 94,895
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865
Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 24,000 hours
FCW 0.0975
Rep part cost per unit 141 $/ft3
# of Layers 10
Replacement Factor 8Layers replaced per year = 3.3
Amount Required 290 ft3
Catalyst Cost 40,823
Y catalyst life factor 8 Years
Annualized Cost 3,979
SCR Capital Cost per EPRI Method 2,667,517
Duty 153 MMBtu/hr Catalyst Area 74 ft2
308 f (h SCR)
Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst)
Temperature 380 Deg F h SCR 81 ft f (h SCR)
Catalyst Volume 2,220 ft3
New/Retrofit R N or R
Electrical Use
Duty 153 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 116.4
NOx in 0.28 lb/MMBtun catalyst layers 11 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 116.4
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
43 lb/hr Neat 19.8 gal/hr
29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost
148 lb/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization
Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement
Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 293,668
Purchased Equipment Total (B) 22% of control device cost (A) 356,807
Installation - Standard Costs 30% of purchased equip cost (B) 107,042
Installation - Site Specific Costs NA
Installation Total 107,042
Total Direct Capital Cost, DC 463,849
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944
Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 293,668
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC
Instrumentation 10% of control device cost (A) 29,367
ND Sales Taxes 6.5% of control device cost (A) 19,088
Freight 5% of control device cost (A) 14,683
Purchased Equipment Total (B) 22% 356,807
Installation
Foundations & supports 8% of purchased equip cost (B) 28,545
Handling & erection 14% of purchased equip cost (B) 49,953
Electrical 4% of purchased equip cost (B) 14,272
Piping 2% of purchased equip cost (B) 7,136
Insulation 1% of purchased equip cost (B) 3,568
Painting 1% of purchased equip cost (B) 3,568
Installation Subtotal Standard Expenses 30% 107,042
Site Preparation, as required Site Specific NA
Buildings, as required Site Specific NA
Site Specific - Other Site Specific NA
Total Site Specific Costs NAInstallation 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) 17,840Contractor fees 10% of purchased equip cost (B) 35,681
Start-up 2% of purchased equip cost (B) 7,136
Performance test 1% of purchased equip cost (B) 3,568
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 10,704
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258
Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521
Total Annual Direct Operating Costs 53,680
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489
Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745
Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944
Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 94.5
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.c: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 380 Deg F - Temperature of waste gas into heat recovery
Tfi 450 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 429 Deg F - Temperature of waste gas out of heat recovery
Tfo 401 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 17,716 scfm - Flow of waste gas
Qaf 23 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303
Current Cost Using CHE Plant Cost Index $293,668
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
NOx Due to Duct Burner
1,408 scf/hr Flow of natural gas required
1.5 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.518 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 391
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs Year
Direct Capital Costs 2000 2,667,517
Purchased Equipment (A) 2005 3,172,367
Purchased Equipment Total (B) SCR + Reheat 3,529,175
Total Capital Investment (TCI) = DC + IC SCR + Reheat 5,234,392
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. SCR + Reheat 148,575
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost SCR + Reheat 539,809
Total Annual Cost (Annualized Capital Cost + Operating Cost) SCR + Reheat 688,384
Emission Control Cost Calculation
Max Emis Annual Control EffControlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.3 80% 2.9 11.4 60,211
Notes & Assumptions
1 Estimated Equipment Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.36 -2.43
4 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35
5 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24
6 SCR Reactor Size per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.25 - 2.31
7 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53
8 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48
9 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 3,172,367
Instrumentation 0% of control device cost (A) NA
ND Sales Taxes 0.0% of control device cost (A) NA
Freight 0% of control device cost (A) NA
Purchased Equipment Total (A) 0% 3,172,367
Indirect Installation
General Facilities 0% of purchased equip cost (A) 0
Engineering & Home Office 0% of purchased equip cost (A) 0
Process Contingency 0% of purchased equip cost (A) 0
Site Specific-Other 25% Replacement Power, two weeks 796,012
Total Indirect Installation Costs (B) 25% of purchased equip cost (A) 796,012
Project Contingeny (C) 15% of (A + B) 595,257
Total Plant Cost (D) A + B + C 4,563,637
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 91,273
Inventory Capital Reagent Vol * $/gal 5,023
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 4,659,932
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 69,899
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization 5,244
Cat. Replacement 346.28 Catalyst Replacement 3,979
Ammonia (29% aqua.) 0.12 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization 15,773
Total Annual Direct Operating Costs 94,895
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 439,865
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 439,865
Total Annual Cost (Annualized Capital Cost + Operating Cost) 534,760
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: NOx Control - Selective Catalytic Reduction (SCR) with Reheat
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 24,000 hours
FCW 0.0975
Rep part cost per unit 141 $/ft3
# of Layers 10
Replacement Factor 8Layers replaced per year = 3.3
Amount Required 290 ft3
Catalyst Cost 40,823
Y catalyst life factor 8 Years
Annualized Cost 3,979
SCR Capital Cost per EPRI Method 2,667,517
Duty 153 MMBtu/hr Catalyst Area 74 ft2
308 f (h SCR)
Q flue gas 70,860 acfm Rx Area 85 850 f (h NH3)
NOx Cont Eff 80% (as faction) Rx Height 9.2 ft 0 f (h New) new= -728, Retrofit = 0
NOx in 0.28 lb/MMBtu n layer 10 layers Y Bypass? Y or N
Ammonia Slip 2 ppm h layer 11.0 ft 127 f (h Bypass)
Fuel Sulfur 0.67 wt % (as %) n total 11 layers 532,728 f (vol catalyst)
Temperature 380 Deg F h SCR 81 ft f (h SCR)
Catalyst Volume 2,220 ft3
New/Retrofit R N or R
Electrical Use
Duty 153 MMBtu/hr kW
NOx Cont Eff 80% (as faction) Power 116.4
NOx in 0.28 lb/MMBtun catalyst layers 11 layers
Press drop catalyst 1 in H2O per layer
Press drop duct 3 in H2O
Total 116.4
Reagent Use & Other Operating Costs
Ammonia Use 56.0 lb/ft3 Density
43 lb/hr Neat 19.8 gal/hr
29% solution Volume 14 day inventory 6,643 gal $5,023 Inventory Cost
148 lb/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 69,899 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 116.4 kW-hr 102,817 5,244 $/kwh, 116 kW-hr, 3156 hr/yr, 28% utilization
Cat. Replacement 346 $/ft3 3,979 Catalyst Replacement
Ammonia (29% aqua.) 0.12059928 $/lb 148 lb/hr 130,792 15,773 $/lb, 148 lb/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 293,668
Purchased Equipment Total (B) 22% of control device cost (A) 356,807
Installation - Standard Costs 30% of purchased equip cost (B) 107,042
Installation - Site Specific Costs NA
Installation Total 107,042
Total Direct Capital Cost, DC 463,849
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 53,680
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944
Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625
Notes & Assumptions
1 Equipment cost estimate EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2.5.1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
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
US Steel - Minntac
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 NAInstallation 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) 17,840Contractor fees 10% of purchased equip cost (B) 35,681
Start-up 2% of purchased equip cost (B) 7,136
Performance test 1% of purchased equip cost (B) 3,568
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 10,704
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 110,610
Total Capital Investment (TCI) = DC + IC 574,460
Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 574,460
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Supervisor 15% 15% of Operator Costs 1,805
Maintenance
Maintenance Labor 61.00 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr 12,032
Maintenance Materials 100% of maintenance labor costs 12,032
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization 4,258
Natural Gas 9.26 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization 11,521
Total Annual Direct Operating Costs 53,680
Indirect Operating Costs
Overhead 60% of total labor and material costs 22,741
Administration (2% total capital costs) 2% of total capital costs (TCI) 11,489
Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,745
Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,745
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 54,225
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,944
Total Annual Cost (Annualized Capital Cost + Operating Cost) 153,625
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catalyst: Catalyst
Equipment Life 2 years
CRF 0.5531
Rep part cost per unit 0 $/ft3
Amount Required 39 ft3
Catalyst Cost 0 Cost adjusted for freight & sales tax
Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Replacement Parts & Equipment:
Equipment Life 3
CRF 0.3811
Rep part cost per unit 0 $ each
Amount Required 0 Number
Total Rep Parts Cost 0 Cost adjusted for freight & sales taxInstallation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.
Total Installed Cost 0 Zero out if no replacement parts needed
Annualized Cost 0
Electrical Use
Flow acfm ∆ P in H2O Efficiency Hp kW
Blower, Thermal 25,500 19 0.6 94.5 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Blower, Catalytic 25,500 23 0.6 114.4 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
Oxidizer Type thermal (catalytic or thermal) 94.5
Reagent Use & Other Operating Costs Oxidizers - NA
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 1,805 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.5 hr/8 hr shift 197 12,032 $/Hr, 0.5 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 12,032 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 94.5 kW-hr 83,488 4,258 $/kwh, 94 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 23 scfm 1,244 11,521 $/mscf, 23 scfm, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.11.d: Cost of Flue Gas Re-Heating (Thermal Oxidizer)
Flue Gas Re-Heat Equipment Cost Estimate Basis Thermal Oxidizer with 70% Heat Recovery
Auxiliary Fuel Use Equation 3.19
Twi 380 Deg F - Temperature of waste gas into heat recovery
Tfi 450 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 70% Factional Heat Recovery % Heat recovery section efficiency
Two 429 Deg F - Temperature of waste gas out of heat recovery
Tfo 401 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.2684 Btu/lb - Deg F Heat Capacity of waste gas (air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 17,716 scfm - Flow of waste gas
Qaf 23 scfm - Flow of auxiliary fuel
Year 2005 Inflation Rate 3.0%Cost Calculations 17,739 scfm Flue Gas Cost in 1989 $'s $246,303
Current Cost Using CHE Plant Cost Index $293,668
Heat Rec % A B
0 10,294 0.2355 Exponents per equation 3.24
0.3 13,149 0.2609 Exponents per equation 3.25
0.5 17,056 0.2502 Exponents per equation 3.26
0.7 21,342 0.2500 Exponents per equation 3.27
Indurator Flue Gas Heat Capacity - Basis Typical Composition
100 scfm 359 scf/lbmole
Gas Composition lb/hr f wt % Cp Gas Cp Flue
28 mw CO 0 v % 0
44 mw CO2 15 v % 184 22.0% 0.24 0.0528
18 mw H2O 10 v % 50 6.0% 0.46 0.0276
28 mw N2 60 v % 468 56.0% 0.27 0.1512
32 mw O2 15 v % 134 16.0% 0.23 0.0368
Cp Flue Gas 100 v % 836 100.0% 0.2684
NOx Due to Duct Burner
1,408 scf/hr Flow of natural gas required
1.5 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.518 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 442,265
Purchased Equipment Total (B) 22% of control device cost (A) 537,352
Installation - Standard Costs 30% of purchased equip cost (B) 161,206
Installation - Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 698,558
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 1,384,220
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721
Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.3 75% 3.6 10.7 15,558
Notes & Assumptions
1 Purchased equipment cost based on estimate from Coen Burner.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 442,265
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 44,227
MN Sales Taxes 6.5% of control device cost (A) 28,747
Freight 5% of control device cost (A) 22,113
Purchased Equipment Total (B) 22% 537,352
Installation
Foundations & supports 8% of purchased equip cost (B) 42,988
Handling & erection 14% of purchased equip cost (B) 75,229
Electrical 4% of purchased equip cost (B) 21,494
Piping 2% of purchased equip cost (B) 10,747
Insulation 1% of purchased equip cost (B) 5,374
Painting 1% of purchased equip cost (B) 5,374
Installation Subtotal Standard Expenses 30% 161,206
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/a
Total Site Specific Costs n/aInstallation Total n/a
Total Direct Capital Cost, DC 698,558
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 53,735
Construction & field expenses 5% of purchased equip cost (B) 26,868Contractor fees 10% of purchased equip cost (B) 53,735
Start-up 2% of purchased equip cost (B) 10,747
Performance test 1% of purchased equip cost (B) 5,374
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 16,121
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 865,137
Retrofit Factor(3)
60% of TCI 519,082
TCI Retrofit Installed 1,384,220
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81
Total Annual Direct Operating Costs 840
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303
Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651
Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721
Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 5% of flue gas is recirculated)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 442,265
Purchased Equipment Total (B) 22% of control device cost (A) 537,352
Installation - Standard Costs 30% of purchased equip cost (B) 161,206
Installation - Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 698,558
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 1,384,220
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 840
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721
Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 13.8 75% 3.4 10.3 16,098
Notes & Assumptions
1 Purchased equipment cost based on estimate from Coen Burner.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 442,265
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 44,227
MN Sales Taxes 6.5% of control device cost (A) 28,747
Freight 5% of control device cost (A) 22,113
Purchased Equipment Total (B) 22% 537,352
Installation
Foundations & supports 8% of purchased equip cost (B) 42,988
Handling & erection 14% of purchased equip cost (B) 75,229
Electrical 4% of purchased equip cost (B) 21,494
Piping 2% of purchased equip cost (B) 10,747
Insulation 1% of purchased equip cost (B) 5,374
Painting 1% of purchased equip cost (B) 5,374
Installation Subtotal Standard Expenses 30% 161,206
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/a
Total Site Specific Costs n/aInstallation Total n/a
Total Direct Capital Cost, DC 698,558
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 53,735
Construction & field expenses 5% of purchased equip cost (B) 26,868Contractor fees 10% of purchased equip cost (B) 53,735
Start-up 2% of purchased equip cost (B) 10,747
Performance test 1% of purchased equip cost (B) 5,374
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 16,121
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 166,579
Total Capital Investment (TCI) = DC + IC 865,137
Retrofit Factor(3)
60% of TCI 519,082
TCI Retrofit Installed 1,384,220
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2 kW-hr, hr/yr, 0% utilization 81
Total Annual Direct Operating Costs 840
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 17,303
Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,651
Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,651
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 130,661
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 165,721
Total Annual Cost (Annualized Capital Cost + Operating Cost) 166,560
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 850 10 0.55 1.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 5% of flue gas is recirculated)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 1.8 kW-hr 1,598 81 $/kwh, 2 kW-hr, hr/yr, 0% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 557,542
Purchased Equipment Total (B) 22% of control device cost (A) 677,414
Installation - Standard Costs 30% of purchased equip cost (B) 203,224
Installation - Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 880,638
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,745,018
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798
Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.8 75% 3.7 11.1 18,839
Notes & Assumptions
1 Purchased equipment cost based on estimate from Coen Burner.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 557,542
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 55,754
MN Sales Taxes 6.5% of control device cost (A) 36,240
Freight 5% of control device cost (A) 27,877
Purchased Equipment Total (B) 22% 677,414
Installation
Foundations & supports 8% of purchased equip cost (B) 54,193
Handling & erection 14% of purchased equip cost (B) 94,838
Electrical 4% of purchased equip cost (B) 27,097
Piping 2% of purchased equip cost (B) 13,548
Insulation 1% of purchased equip cost (B) 6,774
Painting 1% of purchased equip cost (B) 6,774
Installation Subtotal Standard Expenses 30% 203,224
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/a
Total Site Specific Costs n/aInstallation Total n/a
Total Direct Capital Cost, DC 880,638
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 67,741
Construction & field expenses 5% of purchased equip cost (B) 33,871Contractor fees 10% of purchased equip cost (B) 67,741
Start-up 2% of purchased equip cost (B) 13,548
Performance test 1% of purchased equip cost (B) 6,774
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 20,322
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,090,636
Retrofit Factor(3)
60% of TCI 654,382
TCI Retrofit Installed 1,745,018
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122
Total Annual Direct Operating Costs 880
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813
Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906
Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798
Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 5% of flue gas is recirculated)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 557,542
Purchased Equipment Total (B) 22% of control device cost (A) 677,414
Installation - Standard Costs 30% of purchased equip cost (B) 203,224
Installation - Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 880,638
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,745,018
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 880
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798
Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 13.8 75% 3.4 10.3 20,299
Notes & Assumptions
1 Purchased equipment cost based on estimate from Coen Burner.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 557,542
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 55,754
MN Sales Taxes 6.5% of control device cost (A) 36,240
Freight 5% of control device cost (A) 27,877
Purchased Equipment Total (B) 22% 677,414
Installation
Foundations & supports 8% of purchased equip cost (B) 54,193
Handling & erection 14% of purchased equip cost (B) 94,838
Electrical 4% of purchased equip cost (B) 27,097
Piping 2% of purchased equip cost (B) 13,548
Insulation 1% of purchased equip cost (B) 6,774
Painting 1% of purchased equip cost (B) 6,774
Installation Subtotal Standard Expenses 30% 203,224
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/a
Total Site Specific Costs n/aInstallation Total n/a
Total Direct Capital Cost, DC 880,638
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 67,741
Construction & field expenses 5% of purchased equip cost (B) 33,871Contractor fees 10% of purchased equip cost (B) 67,741
Start-up 2% of purchased equip cost (B) 13,548
Performance test 1% of purchased equip cost (B) 6,774
Model Studies of purchased equip cost (B) 0
Contingencies 3% of purchased equip cost (B) 20,322
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 209,998
Total Capital Investment (TCI) = DC + IC 1,090,636
Retrofit Factor(3)
60% of TCI 654,382
TCI Retrofit Installed 1,745,018
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, hr/yr, 0% utilization 122
Total Annual Direct Operating Costs 880
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 21,813
Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,906
Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,906
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 164,717
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 208,798
Total Annual Cost (Annualized Capital Cost + Operating Cost) 209,678
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.12.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 1,275 10 0.55 2.7 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 5% of flue gas is recirculated)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.7 kW-hr 2,397 122 $/kwh, 3 kW-hr, hr/yr, 0% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 1,201,308
Total Direct Capital Cost, DC 1,201,308
Total Capital Investment (TCI) = DC + IC 1,690,961
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615
Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.9 70% 4.5 10.4 22,879
Notes & Assumptions
1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective.
Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and
natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from
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 R-SCR Page 55 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction
CAPITAL COSTS2
Direct Capital Costs
Purchased Equipment1 (A)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 1,201,308
Indirect Installation
General Facilities 5% of purchased equip cost (A) 60,065
Engineerin & Home Office 10% of purchased equip cost (A) 120,131
Process Contingency 5% of purchased equip cost (A) 60,065
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262
Project Contingeny (C) 15% of (A + B) 216,235
Total Plant Cost (D) A + B + C 1,657,804
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 33,156
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961
OPERATING COSTS2
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 25,364
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321
Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933
Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25
Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173
SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204
Total Annual Direct Operating Costs 79,021
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615
Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636
See Summary page for notes and assumptions
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 R-SCR Page 56 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 3 Years
CRF 0.3811
Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total cost 87,139
Annualized Cost 33,204
Electrical Use
Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total 51.5
Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5
Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators
Auxiliary Fuel Use Equation 3.19
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 1703.1 scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization
Comp Air 0.32 $/kscf 4.8 scfm 80 25 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization
Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization
SCR Catalyst 0.00 $/ft3
0 ft3
0 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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 R-SCR Page 57 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.a: NOx Control - Regenerative Selective Catalytic Reduction
Duct Burner Fuel Usage Estimate
Auxiliary Fuel Use Equation 3.19 Input Numbers
Twi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 90% Factional Heat Recovery % Heat recovery section efficiency
Two 713 Deg F - Temperature of waste gas out of heat recovery
Tfo 417 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 11,811 scfm - Flow of waste gas
Qaf 28 scfm - Flow of auxiliary fuel
NOx Due to Duct Burner
1,703 scf/hr Flow of natural gas required
1.8 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.6 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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 R-SCR Page 58 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 1,201,308
Total Direct Capital Cost, DC 1,201,308
Total Capital Investment (TCI) = DC + IC 1,690,961
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 79,021
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615
Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.4 70% 4.3 10.1 23,638
Notes & Assumptions
1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective.
Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and
natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from
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 R-SCR Page 59 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction
CAPITAL COSTS2
Direct Capital Costs
Purchased Equipment1 (A)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,201,308
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 1,201,308
Indirect Installation
General Facilities 5% of purchased equip cost (A) 60,065
Engineerin & Home Office 10% of purchased equip cost (A) 120,131
Process Contingency 5% of purchased equip cost (A) 60,065
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 240,262
Project Contingeny (C) 15% of (A + B) 216,235
Total Plant Cost (D) A + B + C 1,657,804
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 33,156
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,690,961
OPERATING COSTS2
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 25,364
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization 2,321
Natural Gas 9.26 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization 13,933
Comp Air 0.32 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization 25
Ammonia (29% aqua.) 0.12 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization 4,173
SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 33,204
Total Annual Direct Operating Costs 79,021
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 159,615
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 159,615
Total Annual Cost (Annualized Capital Cost + Operating Cost) 238,636
See Summary page for notes and assumptions
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 R-SCR Page 60 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 3 Years
CRF 0.3811
Catalyst Cost $87,139 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total cost 87,139
Annualized Cost 33,204
Electrical Use
Power consumed 51 kWhr 51 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total 51.5
Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 39.2 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5
Compressed air use 5 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Heat required 1,703 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators
Auxiliary Fuel Use Equation 3.19
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 25,364 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh 51.5 kW-hr 45,502 2,321 $/kwh, 51 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 1703.1 scfh 1,505,032 13,933 $/mscf, 1,703 scfh, 3156 hr/yr, 28% utilization
Comp Air 0.32 $/kscf 4.8 scfm 80 25 $/kscf, 5 scfm, 3156 hr/yr, 28% utilization
Ammonia (29% aqua.) 0.12 $/lb 39 lb/hr 34,605 4,173 $/lb, 39 lb/hr, 3156 hr/yr, 28% utilization
SCR Catalyst 0.00 $/ft3
0 ft3
0 33,204 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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 R-SCR Page 61 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.b: NOx Control - Regenerative Selective Catalytic Reduction
Duct Burner Fuel Usage Estimate
Auxiliary Fuel Use Equation 3.19 Input Numbers
Twi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 90% Factional Heat Recovery % Heat recovery section efficiency
Two 713 Deg F - Temperature of waste gas out of heat recovery
Tfo 417 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 11,811 scfm - Flow of waste gas
Qaf 28 scfm - Flow of auxiliary fuel
NOx Due to Duct Burner
1,703 scf/hr Flow of natural gas required
1.8 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.1 lb/hr Additional NOx from duct burners
0.6 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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 R-SCR Page 62 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 1,532,177
Total Direct Capital Cost, DC 1,532,177
Total Capital Investment (TCI) = DC + IC 2,156,692
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577
Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 15.8 70% 4.7 11.0 28,633
Notes & Assumptions
1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective.
Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and
natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from
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 R-SCR Page 63 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction
CAPITAL COSTS2
Direct Capital Costs
Purchased Equipment1 (A)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 1,532,177
Indirect Installation
General Facilities 5% of purchased equip cost (A) 76,609
Engineerin & Home Office 10% of purchased equip cost (A) 153,218
Process Contingency 5% of purchased equip cost (A) 76,609
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435
Project Contingeny (C) 15% of (A + B) 275,792
Total Plant Cost (D) A + B + C 2,114,404
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 42,288
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692
OPERATING COSTS2
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 32,350
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481
Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899
Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38
Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130
SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807
Total Annual Direct Operating Costs 112,705
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577
Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281
See Summary page for notes and assumptions
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 R-SCR Page 64 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 3 Years
CRF 0.3811
Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total cost 130,708
Annualized Cost 49,807
Electrical Use
Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total 77.2
Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5
Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators
Auxiliary Fuel Use Equation 3.19
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization
Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization
Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization
SCR Catalyst 0.00 $/ft3
0 ft3
0 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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 R-SCR Page 65 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.c: NOx Control - Regenerative Selective Catalytic Reduction
Duct Burner Fuel Usage Estimate
Auxiliary Fuel Use Equation 3.19 Input Numbers
Twi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 90% Factional Heat Recovery % Heat recovery section efficiency
Two 713 Deg F - Temperature of waste gas out of heat recovery
Tfo 417 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 17,716 scfm - Flow of waste gas
Qaf 43 scfm - Flow of auxiliary fuel
NOx Due to Duct Burner
2,555 scf/hr Flow of natural gas required
2.7 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.2 lb/hr Additional NOx from duct burners
0.9 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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 R-SCR Page 66 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F
Expected Utiliztion Rate 28% Temperature 380 Deg F
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3%
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 1,532,177
Total Direct Capital Cost, DC 1,532,177
Total Capital Investment (TCI) = DC + IC 2,156,692
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 112,705
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577
Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.7 70% 4.4 10.3 30,710
Notes & Assumptions
1
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2
3 Actual costs may be higher due to retrofit considerations, but need not be estimated since costs are already shown to be not reasonably cost effective.
Capital cost and natural gas usage have been ratioed off of original estimate from Vogt Power to account for different flow rate and
natural gas usage for reheat option. Original cost estimate was $5,500,000. Used 0.6 power law factor to adjust price to stack acfm from
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 R-SCR Page 67 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction
CAPITAL COSTS2
Direct Capital Costs
Purchased Equipment1 (A)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 1,532,177
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 1,532,177
Indirect Installation
General Facilities 5% of purchased equip cost (A) 76,609
Engineerin & Home Office 10% of purchased equip cost (A) 153,218
Process Contingency 5% of purchased equip cost (A) 76,609
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 306,435
Project Contingeny (C) 15% of (A + B) 275,792
Total Plant Cost (D) A + B + C 2,114,404
Allowance for Funds During Construction (E) 0 for SCR 0
Royalty Allowance (F) 0 for SCR 0
Pre Production Costs (G) 2% of (D+E)) 42,288
Inventory Capital Reagent Vol * $/gal 0
Intial Catalyst and Chemicals 0 for SCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 2,156,692
OPERATING COSTS2
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 1.50 % of Total Capital Investment 32,350
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization 3,481
Natural Gas 9.26 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization 20,899
Comp Air 0.32 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization 38
Ammonia (29% aqua.) 0.12 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization 6,130
SCR Catalyst 0.00 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization 49,807
Total Annual Direct Operating Costs 112,705
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 203,577
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 203,577
Total Annual Cost (Annualized Capital Cost + Operating Cost) 316,281
See Summary page for notes and assumptions
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 R-SCR Page 68 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Replacement Catayst
Equipment Life 3 Years
CRF 0.3811
Catalyst Cost $130,708 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total cost 130,708
Annualized Cost 49,807
Electrical Use
Power consumed 77 kWhr 77 Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Total 77.2
Reagent Use & Other Operating Costs
Ammonia use 1.34 lb NH3/lb NOx aqueous ammonia 57.5 lb/hr EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5 Chapter 2.5
Compressed air use 7 scfm Based on estimate from Vogt Power. Scaled linearly using stack flow rate.
Heat required 2,555 scf/hr OAQPS Control Cost Manual 5th Ed Feb 1996 Chapter 3 Thermal & Catalytic Incinerators
Auxiliary Fuel Use Equation 3.19
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 1.5 % of Total Capital Investment 32,350 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh 77.2 kW-hr 68,253 3,481 $/kwh, 77 kW-hr, 3156 hr/yr, 28% utilization
Natural Gas 9.26 $/mscf 2554.7 scfh 2,257,548 20,899 $/mscf, 2,555 scfh, 3156 hr/yr, 28% utilization
Comp Air 0.32 $/kscf 7.1 scfm 120 38 $/kscf, 7 scfm, 3156 hr/yr, 28% utilization
Ammonia (29% aqua.) 0.12 $/lb 58 lb/hr 50,826 6,130 $/lb, 58 lb/hr, 3156 hr/yr, 28% utilization
SCR Catalyst 0.00 $/ft3
0 ft3
0 49,807 $/ft3, 0 ft3, 3156 hr/yr, 28% utilization
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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 R-SCR Page 69 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.13.d: NOx Control - Regenerative Selective Catalytic Reduction
Duct Burner Fuel Usage Estimate
Auxiliary Fuel Use Equation 3.19 Input Numbers
Twi 380 Deg F - Temperature of waste gas into heat recovery Calculated Numbers
Tfi 750 Deg F - Temperature of Flue gas into of heat recovery
Tref 77 Deg F - Reference temperature for fuel combustion calculations
FER 90% Factional Heat Recovery % Heat recovery section efficiency
Two 713 Deg F - Temperature of waste gas out of heat recovery
Tfo 417 Deg F - Temperature of flue gas into of heat recovery
-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane)
-hwg 0 Btu/lb Heat of combustion waste gas
Cp wg 0.271 Btu/lb - Deg F Heat Capacity of waste gas (moist air)
p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F
p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F
Qwg 17,716 scfm - Flow of waste gas
Qaf 43 scfm - Flow of auxiliary fuel
NOx Due to Duct Burner
2,555 scf/hr Flow of natural gas required
2.7 mmbtu/hr Heat required, assuming 1050 btu/scf
0.08 lb/mmbtu NOx emission factor for natural gas combustion
0.2 lb/hr Additional NOx from duct burners
0.9 tpy Additional NOx from duct burners
Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators
(EPA 453/B-96-001)
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 R-SCR Page 70 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 361,408
Purchased Equipment Total (B) 22% of control device cost (A) 439,111
Installation - Standard Costs 30% of purchased equip cost (B) 131,733
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 570,844
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124
Total Capital Investment (TCI) = DC + IC 1,131,149
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506
Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.3 67% 4.7 9.6 14,282
Notes & Assumptions
1 Price based on installation of LNB with OFA in a similar application
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 361,408
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 36,141
MN Sales Taxes 6.5% of control device cost (A) 23,492
Freight 5% of control device cost (A) 18,070
Purchased Equipment Total (B) 22% 439,111
Installation
Foundations & supports 8% of purchased equip cost (B) 35,129
Handling & erection 14% of purchased equip cost (B) 61,476
Electrical 4% of purchased equip cost (B) 17,564
Piping 2% of purchased equip cost (B) 8,782
Insulation 1% of purchased equip cost (B) 4,391
Painting 1% of purchased equip cost (B) 4,391
Installation Subtotal Standard Expenses 30% 131,733
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 570,844
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 43,911
Construction & field expenses 5% of purchased equip cost (B) 21,956Contractor 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) 4,391Model 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326
Total Annual Direct Operating Costs 1,084
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139
Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070
Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506
Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LNB OFA 1/8/2008 Page 72 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 20% of flue gas used for OFA)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LNB OFA 1/8/2008 Page 73 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 361,408
Purchased Equipment Total (B) 22% of control device cost (A) 439,111
Installation - Standard Costs 30% of purchased equip cost (B) 131,733
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 570,844
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 136,124
Total Capital Investment (TCI) = DC + IC 1,131,149
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,084
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506
Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 13.8 67% 4.6 9.2 14,778
Notes & Assumptions
1 Price based on installation of LNB with OFA in a similar application
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LNB OFA 1/8/2008 Page 74 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 361,408
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 36,141
MN Sales Taxes 6.5% of control device cost (A) 23,492
Freight 5% of control device cost (A) 18,070
Purchased Equipment Total (B) 22% 439,111
Installation
Foundations & supports 8% of purchased equip cost (B) 35,129
Handling & erection 14% of purchased equip cost (B) 61,476
Electrical 4% of purchased equip cost (B) 17,564
Piping 2% of purchased equip cost (B) 8,782
Insulation 1% of purchased equip cost (B) 4,391
Painting 1% of purchased equip cost (B) 4,391
Installation Subtotal Standard Expenses 30% 131,733
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 570,844
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 43,911
Construction & field expenses 5% of purchased equip cost (B) 21,956Contractor 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) 4,391Model 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 7.2 kW-hr, 3156 hr/yr 326
Total Annual Direct Operating Costs 1,084
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 14,139
Property tax (1% total capital costs) 1% of total capital costs (TCI) 7,070
Insurance (1% total capital costs) 1% of total capital costs (TCI) 7,070
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 106,773
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 135,506
Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,590
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LNB OFA 1/8/2008 Page 75 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 3,400 10 0.55 7.2 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 20% of flue gas used for OFA)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 7.2 kW-hr 6,391 326 $/kwh, 7.2 kW-hr, 3156 hr/yr
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 LNB OFA 1/8/2008 Page 76 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 455,609
Purchased Equipment Total (B) 22% of control device cost (A) 553,565
Installation - Standard Costs 30% of purchased equip cost (B) 166,070
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 719,635
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605
Total Capital Investment (TCI) = DC + IC 1,425,985
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707
Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.8 67% 4.9 9.9 17,294
Notes & Assumptions
1 Price based on installation of LNB with OFA in a similar application
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LNB OFA 1/8/2008 Page 77 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 455,609
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 45,561
MN Sales Taxes 6.5% of control device cost (A) 29,615
Freight 5% of control device cost (A) 22,780
Purchased Equipment Total (B) 22% 553,565
Installation
Foundations & supports 8% of purchased equip cost (B) 44,285
Handling & erection 14% of purchased equip cost (B) 77,499
Electrical 4% of purchased equip cost (B) 22,143
Piping 2% of purchased equip cost (B) 11,071
Insulation 1% of purchased equip cost (B) 5,536
Painting 1% of purchased equip cost (B) 5,536
Installation Subtotal Standard Expenses 30% 166,070
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 719,635
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 55,357
Construction & field expenses 5% of purchased equip cost (B) 27,678Contractor 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) 5,536Model 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489
Total Annual Direct Operating Costs 1,247
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825
Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912
Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707
Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LNB OFA 1/8/2008 Page 78 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 20% of flue gas used for OFA)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 LNB OFA 1/8/2008 Page 79 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 455,609
Purchased Equipment Total (B) 22% of control device cost (A) 553,565
Installation - Standard Costs 30% of purchased equip cost (B) 166,070
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 719,635
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 171,605
Total Capital Investment (TCI) = DC + IC 1,425,985
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,247
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707
Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 13.8 67% 4.5 9.2 18,634
Notes & Assumptions
1 Price based on installation of LNB with OFA in a similar application.
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
3 CUECost Workbook Version 1.0, USEPA Document Page 2
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LNB OFA 1/8/2008 Page 80 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 455,609
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 45,561
MN Sales Taxes 6.5% of control device cost (A) 29,615
Freight 5% of control device cost (A) 22,780
Purchased Equipment Total (B) 22% 553,565
Installation
Foundations & supports 8% of purchased equip cost (B) 44,285
Handling & erection 14% of purchased equip cost (B) 77,499
Electrical 4% of purchased equip cost (B) 22,143
Piping 2% of purchased equip cost (B) 11,071
Insulation 1% of purchased equip cost (B) 5,536
Painting 1% of purchased equip cost (B) 5,536
Installation Subtotal Standard Expenses 30% 166,070
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 719,635
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 55,357
Construction & field expenses 5% of purchased equip cost (B) 27,678Contractor 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) 5,536Model 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 10.8 kW-hr, 3156 hr/yr 489
Total Annual Direct Operating Costs 1,247
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 17,825
Property tax (1% total capital costs) 1% of total capital costs (TCI) 8,912
Insurance (1% total capital costs) 1% of total capital costs (TCI) 8,912
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 134,603
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 170,707
Total Annual Cost (Annualized Capital Cost + Operating Cost) 171,954
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LNB OFA 1/8/2008 Page 81 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.14.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical UseFlow acfm ∆ P in H2O Efficiency Hp kW
Fan motor 5,100 10 0.55 10.8 EPA Cost Cont Manual 6th ed - Oxidizders Chapter 2.5.2.1
(assume 20% of flue gas used for OFA)
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
Maintenance
Maint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 10.8 kW-hr 9,587 489 $/kwh, 10.8 kW-hr, 3156 hr/yr
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 LNB OFA 1/8/2008 Page 82 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 175,993
Purchased Equipment Total (B) 22% of control device cost (A) 213,832
Installation - Standard Costs 30% of purchased equip cost (B) 64,150
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 277,981
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288
Total Capital Investment (TCI) = DC + IC 344,269
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722
Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.3 50% 7.1 7.1 6,653
Notes & Assumptions
1 Equipment cost based on estimate from John Zink
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 LNB 1/8/2008 Page 83 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 175,993
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 17,599
MN Sales Taxes 6.5% of control device cost (A) 11,440
Freight 5% of control device cost (A) 8,800
Purchased Equipment Total (B) 22% 213,832
Installation
Foundations & supports 8% of purchased equip cost (B) 17,107
Handling & erection 14% of purchased equip cost (B) 29,936
Electrical 4% of purchased equip cost (B) 8,553
Piping 2% of purchased equip cost (B) 4,277
Insulation 1% of purchased equip cost (B) 2,138
Painting 1% of purchased equip cost (B) 2,138
Installation Subtotal Standard Expenses 30% 64,150
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 277,981
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 21,383
Construction & field expenses 5% of purchased equip cost (B) 10,692Contractor 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Total Annual Direct Operating Costs 758
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885
Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443
Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722
Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.a: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
MaintenanceMaint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 175,993
Purchased Equipment Total (B) 22% of control device cost (A) 213,832
Installation - Standard Costs 30% of purchased equip cost (B) 64,150
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 277,981
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 66,288
Total Capital Investment (TCI) = DC + IC 344,269
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722
Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 13.8 50% 6.9 6.9 6,883
Notes & Assumptions
1 Equipment cost based on estimate from John Zink
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 175,993
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 17,599
MN Sales Taxes 6.5% of control device cost (A) 11,440
Freight 5% of control device cost (A) 8,800
Purchased Equipment Total (B) 22% 213,832
Installation
Foundations & supports 8% of purchased equip cost (B) 17,107
Handling & erection 14% of purchased equip cost (B) 29,936
Electrical 4% of purchased equip cost (B) 8,553
Piping 2% of purchased equip cost (B) 4,277
Insulation 1% of purchased equip cost (B) 2,138
Painting 1% of purchased equip cost (B) 2,138
Installation Subtotal Standard Expenses 30% 64,150
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 277,981
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 21,383
Construction & field expenses 5% of purchased equip cost (B) 10,692Contractor 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Total Annual Direct Operating Costs 758
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 6,885
Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,443
Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,443
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 32,497
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 46,722
Total Annual Cost (Annualized Capital Cost + Operating Cost) 47,480
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.b: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
MaintenanceMaint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 221,866
Purchased Equipment Total (B) 22% of control device cost (A) 269,567
Installation - Standard Costs 30% of purchased equip cost (B) 80,870
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 350,437
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566
Total Capital Investment (TCI) = DC + IC 434,003
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782
Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.8 50% 7.4 7.4 8,024
Notes & Assumptions
1 Equipment cost based on estimate from John Zink
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 221,866
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 22,187
MN Sales Taxes 6.5% of control device cost (A) 14,421
Freight 5% of control device cost (A) 11,093
Purchased Equipment Total (B) 22% 269,567
Installation
Foundations & supports 8% of purchased equip cost (B) 21,565
Handling & erection 14% of purchased equip cost (B) 37,739
Electrical 4% of purchased equip cost (B) 10,783
Piping 2% of purchased equip cost (B) 5,391
Insulation 1% of purchased equip cost (B) 2,696
Painting 1% of purchased equip cost (B) 2,696
Installation Subtotal Standard Expenses 30% 80,870
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 350,437
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 26,957
Construction & field expenses 5% of purchased equip cost (B) 13,478Contractor 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Total Annual Direct Operating Costs 758
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680
Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340
Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782
Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.c: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
MaintenanceMaint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 004 Stack/Vent Number SV 004 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Chemical Plant Cost IndexExpected Utiliztion Rate 28% Temperature 380 Deg F 1998/1999 390
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.19
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 221,866
Purchased Equipment Total (B) 22% of control device cost (A) 269,567
Installation - Standard Costs 30% of purchased equip cost (B) 80,870
Installation - Site Specific Costs n/a
Installation Total n/a Total Direct Capital Cost, DC 350,437
Total Indirect Capital Costs, IC 31% of purchased equip cost (B) 83,566
Total Capital Investment (TCI) = DC + IC 434,003
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 758
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782
Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540
Emission Control Cost Calculation
Max Emis Annual Cont Eff Cont Emis Reduction Cont CostPollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 13.8 50% 6.9 6.9 8,646
Notes & Assumptions
1 Equipment cost based on estimate from John Zink
2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 3.2 Chapter 2
Thermal Oxidizer cost factor used because it has the lowest multipiler for installation cost
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1) 221,866
Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC
Instrumentation 10% of control device cost (A) 22,187
MN Sales Taxes 6.5% of control device cost (A) 14,421
Freight 5% of control device cost (A) 11,093
Purchased Equipment Total (B) 22% 269,567
Installation
Foundations & supports 8% of purchased equip cost (B) 21,565
Handling & erection 14% of purchased equip cost (B) 37,739
Electrical 4% of purchased equip cost (B) 10,783
Piping 2% of purchased equip cost (B) 5,391
Insulation 1% of purchased equip cost (B) 2,696
Painting 1% of purchased equip cost (B) 2,696
Installation Subtotal Standard Expenses 30% 80,870
Site Preparation, as required Site Specific n/a
Buildings, as required Site Specific n/a
Site Specific - Other Site Specific n/aTotal Site Specific Costs n/a
Installation Total n/a
Total Direct Capital Cost, DC 350,437
Indirect Capital CostsEngineering, supervision 10% of purchased equip cost (B) 26,957
Construction & field expenses 5% of purchased equip cost (B) 13,478Contractor 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 COSTSDirect Annual Operating Costs, DC
Operating Labor
Operator 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Supervisor 15% 15% of Operator Costs 36
Maintenance
Maintenance Labor 61.00 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr 241
Maintenance Materials 100% of maintenance labor costs 241
Utilities, Supplies, Replacements & Waste Management
Total Annual Direct Operating Costs 758
Indirect Operating Costs
Overhead 60% of total labor and material costs 455
Administration (2% total capital costs) 2% of total capital costs (TCI) 8,680
Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,340
Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,340
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 40,967
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 58,782
Total Annual Cost (Annualized Capital Cost + Operating Cost) 59,540
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.15.d: NOX Control - Low NOX Burner with Flue Gas Recirculation
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28.0%
Unit Unit of Use Unit of Annual Annual CommentsItem Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Supervisor 15% of Op. NA 36 15% of Operator Costs
MaintenanceMaint Labor 61.00 $/Hr 0.01 hr/8 hr shift 4 241 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yr
Maint Mtls 100 % of Maintenance Labor NA 241 100% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
*annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Operating Unit: Utility Plant Heater Boiler #1
Emission Unit Number EU 001 Stack/Vent Number SV 001 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 769,260
Purchased Equipment Total (B) 0% of control device cost (A) 769,260
Installation - Standard Costs 15% of purchased equip cost (B) 138,467
Total Capital Investment (TCI) = DC + IC 1,084,406
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068
Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 14.3 50% 7.1 7.1 42,037
Notes & Assumptions
1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI
2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22
3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23
5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
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
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 769,260
Indirect Installation [1]
General Facilities 5% of purchased equip cost (A) 38,463
Engineerin & Home Office 10% of purchased equip cost (A) 76,926
Process Contingency 5% of purchased equip cost (A) 38,463
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852
Project Contingeny ( C) 15% of (A + B) 138,467
Total Plant Cost D A + B + C 1,061,579
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 21,232
Inventory Capital Reagent Vol * $/gal 1,596
Intial Catalyst and Chemicals 0 for SNCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406
Retrofit Installation Factor 30% 325,322
Total Capital Investment, Retrofit Installed 1,409,728
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 15.00 % of Total Capital Investment 162,661
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization 89
Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1
Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198
Total Annual Direct Operating Costs 166,949
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068
Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 SNCR #1 SNCR 96 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.a: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
NOx in 0.28 lb/MMBtu kW
NSR 1.37 equation 1.14
Power 2.0
Total 2.0
Reagent Use & Other Operating Costs Urea Use
11.73 lb/hr Neat equation 1.15
50% solution 71.0 lb/ft3 Density 50% Solution
23.46 lb/hr 2.5 gal/hr
831 gal $1,596 Inventory Cost
Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yrSupervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.0 kW-hr 1,753 89 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization
Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization
Urea 405 $/ton 0.0117 ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#1 SNCR #1 SNCR 97 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Operating Unit: Utility Plant Heater Boiler #2
Emission Unit Number EU 002 Stack/Vent Number SV 002 Chemical Engineering
Desgin Capacity 104 MMBtu/hr Standardized Flow Rate 11,005 scfm @ 32º F Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 17,000 acfm Inflation Adj 1.18
Expected Equipment Life 20 yrs Standardized Flow Rate 11,811 scfm @ 68º F
Dry Std Flow Rate 10,240 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 769,260
Purchased Equipment Total (B) 0% of control device cost (A) 769,260
Installation - Standard Costs 15% of purchased equip cost (B) 138,467
Total Capital Investment (TCI) = DC + IC 1,084,406
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 166,949
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068
Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 29.2 13.8 50% 6.9 6.9 43,495
Notes & Assumptions
1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI
2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22
3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23
5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 SNCR #2 SNCR 98 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 769,260
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 769,260
Indirect Installation [1]
General Facilities 5% of purchased equip cost (A) 38,463
Engineerin & Home Office 10% of purchased equip cost (A) 76,926
Process Contingency 5% of purchased equip cost (A) 38,463
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 153,852
Project Contingeny ( C) 15% of (A + B) 138,467
Total Plant Cost D A + B + C 1,061,579
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 21,232
Inventory Capital Reagent Vol * $/gal 1,596
Intial Catalyst and Chemicals 0 for SNCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,084,406
Retrofit Installation Factor 30% 325,322
Total Capital Investment, Retrofit Installed 1,409,728
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 15.00 % of Total Capital Investment 162,661
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization 89
Water 0.08 $/mgal, 11 gph, 3156 hr/yr, 28% utilization 1
Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 4,198
Total Annual Direct Operating Costs 166,949
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 133,068
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 133,068
Total Annual Cost (Annualized Capital Cost + Operating Cost) 300,018
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 SNCR #2 SNCR 99 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.b: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
NOx in 0.28 lb/MMBtu kW
NSR 1.37 equation 1.14
Power 2.0
Total 2.0
Reagent Use & Other Operating Costs Urea Use
11.73 lb/hr Neat equation 1.15
50% solution 71.0 lb/ft3 Density 50% Solution
23.46 lb/hr 2.5 gal/hr
831 gal $1,596 Inventory Cost
Water Use 11 gal/hr Inject at 10% solution Fuel Use 0.19 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yrSupervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 15 % of Total Capital Investment 162,661 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.0 kW-hr 1,753 89 $/kwh, 2 kW-hr, 3156 hr/yr, 28% utilization
Water 0.08 $/mgal 11.2 gph 10 1 $/mgal, 11 gph, 3156 hr/yr, 28% utilization
Urea 405 $/ton 0.0117 ton/hr 10 4,198 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#2 SNCR #2 SNCR 100 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Operating Unit: Utility Plant Heater Boiler #4
Emission Unit Number EU 004 Stack/Vent Number 0 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 905,717
Purchased Equipment Total (B) 0% of control device cost (A) 905,717
Installation - Standard Costs 15% of purchased equip cost (B) 163,029
Total Capital Investment (TCI) = DC + IC 1,277,232
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730
Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 14.8 50% 7.4 7.4 47,792
Notes & Assumptions
1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI
2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22
3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23
5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 SNCR #4 SNCR 101 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 905,717
Indirect Installation [1]
General Facilities 5% of purchased equip cost (A) 45,286
Engineerin & Home Office 10% of purchased equip cost (A) 90,572
Process Contingency 5% of purchased equip cost (A) 45,286
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143
Project Contingeny ( C) 15% of (A + B) 163,029
Total Plant Cost D A + B + C 1,249,889
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 24,998
Inventory Capital Reagent Vol * $/gal 2,345
Intial Catalyst and Chemicals 0 for SNCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232
Retrofit Installation Factor 30% 383,169
Total Capital Investment, Retrofit Installed 1,660,401
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 15.00 % of Total Capital Investment 191,585
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131
Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1
Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166
Total Annual Direct Operating Costs 197,883
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730
Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 SNCR #4 SNCR 102 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.c: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
NOx in 0.28 lb/MMBtu kW
NSR 1.37 equation 1.14
Power 2.9
Total 2.9
Reagent Use & Other Operating Costs Urea Use
17.23 lb/hr Neat equation 1.15
50% solution 71.0 lb/ft3 Density 50% Solution
34.46 lb/hr 3.6 gal/hr
1,220 gal $2,345 Inventory Cost
Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yrSupervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization
Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization
Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#4 SNCR #4 SNCR 103 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Operating Unit: Utility Plant Heater Boiler #5
Emission Unit Number EU 005 Stack/Vent Number SV 005 Chemical Engineering
Desgin Capacity 153 MMBtu/hr Standardized Flow Rate 16,508 scfm @ 32º F Plant Cost Index
Expected Utiliztion Rate 28% Temperature 380 Deg F 2000 394
Expected Annual Hours of Operation 3,156 Hours Moisture Content 13.3% 2005 465
Annual Interest Rate 7.0% Actual Flow Rate 25,500 acfm Inflation Adj 1.18
Expected Equipment Life 20 yrs Standardized Flow Rate 17,716 scfm @ 68º F
Dry Std Flow Rate 15,360 dscfm @ 68º F
CONTROL EQUIPMENT COSTS
Capital Costs
Direct Capital Costs
Purchased Equipment (A) 905,717
Purchased Equipment Total (B) 0% of control device cost (A) 905,717
Installation - Standard Costs 15% of purchased equip cost (B) 163,029
Total Capital Investment (TCI) = DC + IC 1,277,232
Operating Costs
Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 197,883
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730
Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613
Emission Control Cost Calculation
Max Emis Annual Control Eff Controlled Emis Reduction Control Cost
Pollutant Lb/Hr T/Yr % T/yr T/yr $/Ton Rem
Nitrous Oxides (NOx) 42.9 13.8 50% 6.9 6.9 51,494
Notes & Assumptions
1 Capital Cost per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.19
Capital costs adjusted from 2000 dollars to 2005 dollars using CEPCI
2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22
3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25
4 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23
5 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 SNCR #5 SNCR 104 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)
CAPITAL COSTS
Direct Capital Costs
Purchased Equipment (A) (1)
Purchased Equipment Costs (A) - Absorber + packing + auxillary equipment, EC 905,717
Instrumentation 10% of control device cost (A) NA
MN Sales Taxes 6.5% of control device cost (A) NA
Freight 5% of control device cost (A) NA
Purchased Equipment Total (A) 905,717
Indirect Installation [1]
General Facilities 5% of purchased equip cost (A) 45,286
Engineerin & Home Office 10% of purchased equip cost (A) 90,572
Process Contingency 5% of purchased equip cost (A) 45,286
Total Indirect Installation Costs (B) 20% of purchased equip cost (A) 181,143
Project Contingeny ( C) 15% of (A + B) 163,029
Total Plant Cost D A + B + C 1,249,889
Allowance for Funds During Construction (E) 0 for SNCR 0
Royalty Allowance (F) 0 for SNCR 0
Pre Production Costs (G) 2% of (D+E)) 24,998
Inventory Capital Reagent Vol * $/gal 2,345
Intial Catalyst and Chemicals 0 for SNCR 0
Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I 1,277,232
Retrofit Installation Factor 30% 383,169
Total Capital Investment, Retrofit Installed 1,660,401
OPERATING COSTS
Direct Annual Operating Costs, DC
Operating Labor
Operator NA -
Supervisor NA -
Maintenance
Maintenance Total 15.00 % of Total Capital Investment 191,585
Maintenance Materials NA % of Maintenance Labor -
Utilities, Supplies, Replacements & Waste Management
Electricity 0.05 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization 131
Water 0.08 $/mgal, 17 gph, 3156 hr/yr, 28% utilization 1
Urea 405.00 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization 6,166
Total Annual Direct Operating Costs 197,883
Indirect Operating Costs
Overhead NA of total labor and material costs NA
Administration (2% total capital costs) NA of total capital costs (TCI) NA
Property tax (1% total capital costs) NA of total capital costs (TCI) NA
Insurance (1% total capital costs) NA of total capital costs (TCI) NA
Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 156,730
Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 156,730
Total Annual Cost (Annualized Capital Cost + Operating Cost) 354,613
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 SNCR #5 SNCR 105 of 106
US Steel - Minntac
Draft BART Emission Control Cost Analysis
Table A.16.d: NOx Control - Selective Non-Catalytic Reduction (SNCR)
Capital Recovery Factors
Primary Installation
Interest Rate 7.00%
Equipment Life 20 years
CRF 0.0944
Electrical Use
NOx in 0.28 lb/MMBtu kW
NSR 1.37 equation 1.14
Power 2.9
Total 2.9
Reagent Use & Other Operating Costs Urea Use
17.23 lb/hr Neat equation 1.15
50% solution 71.0 lb/ft3 Density 50% Solution
34.46 lb/hr 3.6 gal/hr
1,220 gal $2,345 Inventory Cost
Water Use 17 gal/hr Inject at 10% solution Fuel Use 0.28 MMBtu/hr
Operating Cost Calculations Annual hours of operation: 3,156
Utilization Rate: 28%
Unit Unit of Use Unit of Annual Annual Comments
Item Cost $ Measure Rate Measure Use* Cost
Operating Labor
Op Labor 61.00 $/Hr 0.0 hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 3156 hr/yrSupervisor 15% of Op. NA - 15% of Operator Costs
Maintenance
Maintenance Total 15 % of Total Capital Investment 191,585 % of Total Capital Investment
Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor
Utilities, Supplies, Replacements & Waste Management
Electricity 0.051 $/kwh 2.9 kW-hr 2,572 131 $/kwh, 3 kW-hr, 3156 hr/yr, 28% utilization
Water 0.08 $/mgal 16.5 gph 15 1 $/mgal, 17 gph, 3156 hr/yr, 28% utilization
Urea 405 $/ton 0.0172 ton/hr 15 6,166 $/ton, 0 ton/hr, 3156 hr/yr, 28% utilization
** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor
See Summary page for notes and assumptions
P:\Mpls\23 MN\69\2369A42 Minntac BART Assistance\_MovedFromMpls_P\00 MN Taconite BART (2006)\Facility Control Cost Spreadsheets\Minntac\Minntac Process Boilers BART
#5 SNCR #5 SNCR 106 of 106
Memorandum
To: Margaret McCourtney
From: Andrew Skoglund
Subject: Revisions per your comments
Date: May 16, 2006
Project: Taconite Industry BART Clients
c: Mary Jean Fenske, Barr Taconite BART Project Team, Taconite BART Industry Reps.
Attached is a revised version of our proposed changes to the BART-analysis modeling protocol. They are
set up in the format described in Appendix G to the modeling protocol. The proposed OZONE.DAT files
and a figure depicting the proposed modeling domain are also included, as requested.
The PSD modeling protocols referenced for the CALMET parameters are based on PSD modeling
protocols submitted for Mesabi Nugget LLC, Northshore Mining Line 5 Restart, and Minnesota Steel
Industries LLC. Each of these facilities has submitted a modeling protocol using MM4/MM5 data with
observations for review. The values noted are representative of those that were used after receiving
comment from the FLMs. The Minnesota Steel Industries modeling protocol was submitted in May 2005,
with FLM response on June 14, 2005. FLMs approved of the submitted values.
The comments section regarding receptors has been revised to indicate that we will be using a subset of the
original MPCA receptor group, using only BWCA and Voyageurs receptors.
Thank you,
Andrew J. Skoglund
Barr Engineering Co.
(952) 832 - 2685
Barr Engineering Company Appendix B
4700 West 77th Street • Minneapolis, MN 55435-4803
Phone: 952-832-2600 • Fax: 952-832-2601 • www.barr.com An EEO Employer Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO
!;N
Barr F
ooter
: Date
: 6/3/
2004
4:10
:56 PM
File
: C:\T
emp\T
est.m
xd U
ser:
bal
0 100Kilometers
MODELING DOMAINTaconite BART ModelingTaconite Industry Group
Minnesota
0 100Miles
LegendModeling Domain
Class I AreaBWCAVoyageurs
TERREL
Variable Description Value Default Comments
GTOPO30 GTOPO 30-sec data - n/a 1 degree DEM files will be used
XREFKM Reference point coordinates for grid 168 n/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
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 4 14898, 14918, 94983, 4837
NX Number of X grid cells 40 n/a
NY Number of Y grid cells 30 n/a
XORIGKM Reference point coordinates for grid 168 n/a
YORIGKM Reference point coordinates for grid 720 n/a
NOOBS No Observation Mode 0 Y Include Surface, Upper Air and 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
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
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
Input Group 0b
Input Group 2
Input Group 2
Input Group 2
Input Group 4
Input Group 5
Input Group 6
CALPUFF
Variable Description Value Default Comments
NX Number of X grid cells in met grid 40 n/a
NY Number of Y grid cells in met grid 30 n/a
XORIGKM Reference point coordinates for met grid 168 n/a
YORIGKM Reference point coordinates for met grid 720 n/a
IBCOMP X index of LL corner 1 n/a
JBCOMP Y index of LL corner 1 n/a
IECOMP X index of UR corner 40 n/a
JECOMP Y index of UR corner 30 n/a
MOZ Ozone data input option 1 N OZONE.DAT from MN, WI, and MI observation stations
NREC Number of non-gridded receptors 1222 n/a Using only BWCA and Voyageurs from MPCA protocol
Input Group 11
Input Group 17
Input Group 4
Appendix C
1. CALPUFF Modeling System
The CALPUFF Modeling System is the required model for determining visual impacts at long distances
from sources. This model was used in accordance with the guidelines found in the Best Available
Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of
Minnesota, Final1, with the modifications found in Appendix B.
The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a
number of pre-processing programs. These pre-processing programs are designed to prepare available
meteorological and geophysical data for input into CALMET. Each of these modeling components are
described below:
• CALMET is a meteorological model that develops hourly wind and temperature fields on a three-
dimensional gridded modeling domain. Associated two-dimensional fields such as mixing
heights, terrain elevations, land use categories and dispersion properties are also included in the
file produced by CALMET.
• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from
one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical
transformations as each puff moves away from the source, using the multi-dimensional grids
generated by CALMET.
• CALPUFF produces an output file containing hourly concentrations of pollutants which are
processed by CALPOST to yield estimates of ambient air extinction coefficients and related
measures of visibility impairment at selected averaging times and locations.
Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate
system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets
and overcome other size limitations, CALPUFF was recompiled with several size parameters increased.
1 MPCA, Final March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject to BART in the State of Minnesota.
CALMET
Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data,
precipitation data, and upper air data were used to generate the CALMET data set for use in the
CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells
(north-south) with a grid spacing of 12 km. This grid encompasses MinnTac sources, the BWCAW and
Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files
required by CALMET were obtained from the MPCA.
CALPUFF
CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to
the values specified in the revised modeling protocol (Appendix B).
The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5µ to
10µ), and PM2.5 (fine particulate matter, under 2.5µ).
The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical
transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates
of transformation. The MESOPUFF-generated transformation rates are a function of the background
ozone and ammonia concentrations, the former set by observations, the latter using monthly average
values provided by MPCA.
The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and
Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files.
CALPOST
CALPOST converted the hourly concentration and monthly average relative humidity files generated by
CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction
coefficients were compared to the 20% best days background extinction coefficients designated in the
modeling protocol.
2. Visibility Impacts Analysis
As indicated in EPA’s final BART guidance2, states are required to consider the degree of visibility
improvement resulting from the retrofit technology in combination with other factors, such as economics
and technical feasibility, when determining BART for an individual source.
The CALPUFF program models how a pollutant contributes to visibility impairment with consideration
for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions
between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting
impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts.
Assessing Visibility Impairment
The visibility impairment contribution for different emission rate scenarios can be determined using the
CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control
Agency (MPCA). The Minnesota BART modeling protocol3 describes the CALPUFF model inputs
including the meteorological data set and background atmospheric ammonia and ozone concentrations
along with the functions of the CALPOST post processing. There are two criteria with which to assess the
expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days
on which a source exceeds an impairment threshold.
As defined by federal guidance4 a source "contributes to visibility impairment” if the 98th percentile of
any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally
protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota
Pollution Control Agency identified this facility as having BART eligible source(s)5 that could cause or
contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a
source contributes to impairment on the 98th percentile, the severity of the visibility impairment
contribution or reasonably attributed visibility impairment can be gauged by assessing the number of days
on which a source exceeds 0.5 dV.
2 40 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-
to-Bart in the State of Minnesota. 4 40 CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-
to-Bart in the State of Minnesota.
De minimis Modeling
As a part of the streamlined BART approach, a method for removing insignificant sources from further BART evaluation was developed, with guidance from MPCA. Sources meeting a de
minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis. For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98th percentile modeled impact for these sources was 0.04 dV, meeting the required de
minimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.
Modeled 98th Percentile Impact
2002 2003 2004 2002-2004 Maximum
BWCA 0.040 0.034 0.029 0.031 0.040
Voyageurs 0.019 0.020 0.016 0.018 0.020
Predicting 24-Hour Maximum Emission Rates
Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for 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.
Appendix C
1. CALPUFF Modeling System
The CALPUFF Modeling System is the required model for determining visual impacts at long distances
from sources. This model was used in accordance with the guidelines found in the Best Available
Retrofit Technology (BART) Modeling Protocol to Determine Sources Subject-to-BART in the State of
Minnesota, Final1, with the modifications found in Appendix B.
The CALPUFF system consists of three main components (CALMET, CALPUFF and CALPOST) and a
number of pre-processing programs. These pre-processing programs are designed to prepare available
meteorological and geophysical data for input into CALMET. Each of these modeling components are
described below:
• CALMET is a meteorological model that develops hourly wind and temperature fields on a three-
dimensional gridded modeling domain. Associated two-dimensional fields such as mixing
heights, terrain elevations, land use categories and dispersion properties are also included in the
file produced by CALMET.
• CALPUFF is a transport and dispersion model that follows the “puffs” of material emitted from
one or more sources as they travel downwind. CALPUFF simulates dispersion and chemical
transformations as each puff moves away from the source, using the multi-dimensional grids
generated by CALMET.
• CALPUFF produces an output file containing hourly concentrations of pollutants which are
processed by CALPOST to yield estimates of ambient air extinction coefficients and related
measures of visibility impairment at selected averaging times and locations.
Lambert conformal coordinates (LCC) were used in the modeling. To accommodate this coordinate
system, it was necessary to use CALPUFF version 5.711a. To allow the use of larger meteorological sets
and overcome other size limitations, CALPUFF was recompiled with several size parameters increased.
1 MPCA, Final March 2006. Best Available Retrofit Technology (BART) Modeling Protocol to Determine Sources
Subject to BART in the State of Minnesota.
CALMET
Three years (2002-2004) of MM5 prognostic mesoscale meteorological data, surface weather data,
precipitation data, and upper air data were used to generate the CALMET data set for use in the
CALPUFF model. The CALMET computational grid was 175 grid cells (east-west) by 120 grid cells
(north-south) with a grid spacing of 12 km. This grid encompasses MinnTac sources, the BWCAW and
Voyageurs National Park. USGS digital elevation maps (DEMs) and land use land cover (LULC) files
required by CALMET were obtained from the MPCA.
CALPUFF
CALPUFF model input files were set up for each year of CALMET data. Model parameters were set to
the values specified in the revised modeling protocol (Appendix B).
The CALPUFF modeling considered the emission of SO2, NOx, PM10 (coarse particulate matter, 2.5µ to
10µ), and PM2.5 (fine particulate matter, under 2.5µ).
The CALPUFF modeling also tracked SO4, NO3, and HNO3, which are generated by the chemical
transformation of the emitted SO2 and NOx. The default MESOPUFF II algorithms described the rates
of transformation. The MESOPUFF-generated transformation rates are a function of the background
ozone and ammonia concentrations, the former set by observations, the latter using monthly average
values provided by MPCA.
The CALPUFF modeling used the receptors for the Boundary Water Canoe Area Wilderness and
Voyageurs National Park provided by the MPCA in the original subject-to-BART modeling files.
CALPOST
CALPOST converted the hourly concentration and monthly average relative humidity files generated by
CALPUFF into 24-hour time-averaged extinction coefficients. These emissions-based extinction
coefficients were compared to the 20% best days background extinction coefficients designated in the
modeling protocol.
2. Visibility Impacts Analysis
As indicated in EPA’s final BART guidance2, states are required to consider the degree of visibility
improvement resulting from the retrofit technology in combination with other factors, such as economics
and technical feasibility, when determining BART for an individual source.
The CALPUFF program models how a pollutant contributes to visibility impairment with consideration
for the background atmospheric ammonia, ozone and meteorological data. Additionally, the interactions
between the visibility impairing pollutants NOx, SO2 and PM10 can play a large part in predicting
impairment. It is therefore important to take a multi-pollutant approach when assessing visibility impacts.
Assessing Visibility Impairment
The visibility impairment contribution for different emission rate scenarios can be determined using the
CALMET, CALPUFF, and CALPOST modeling templates provided by the Minnesota Pollution Control
Agency (MPCA). The Minnesota BART modeling protocol3 describes the CALPUFF model inputs
including the meteorological data set and background atmospheric ammonia and ozone concentrations
along with the functions of the CALPOST post processing. There are two criteria with which to assess the
expected post-BART visibility improvement: the 98th percentile delta deciview and the number of days
on which a source exceeds an impairment threshold.
As defined by federal guidance4 a source "contributes to visibility impairment” if the 98th percentile of
any year’s modeling results meets or exceeds the threshold of five-tenths of a deciview (dV) at a federally
protected Class I area receptor. The pre-BART evaluation of this criterion conducted by the Minnesota
Pollution Control Agency identified this facility as having BART eligible source(s)5 that could cause or
contribute to visibility impairment at Minnesota Class I areas. In addition to establishing whether or not a
source contributes to impairment on the 98th percentile, the severity of the visibility impairment
contribution or reasonably attributed visibility impairment can be gauged by assessing the number of days
on which a source exceeds 0.5 dV.
2 40 CFR 51, Appendix Y. 3 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-
to-Bart in the State of Minnesota. 4 40 CFR 51, Appendix Y. 5 MPCA, March 2006, Best Available Retrofit Tecnology (BART) Moeling Protocol to Determine Sources Subject-
to-Bart in the State of Minnesota.
De minimis Modeling
As a part of the streamlined BART approach, a method for removing insignificant sources from further BART evaluation was developed, with guidance from MPCA. Sources meeting a de
minimis threshold would not require further BART analysis. A de minimis threshold of 0.05 dV was used in this analysis. For this facility, twelve sources were modeled, SV003, 010, 019, 020, 086, 088, 182, and 187 as well as the PM and SO2 emissions from SV001, 002, 004, and 005 were modeled. The maximum 98th percentile modeled impact for these sources was 0.04 dV, meeting the required de
minimis threshold of 0.05 dV. This exempts these sources from further BART analysis. A summary of the de minimis modeling is in the table below.
Modeled 98th Percentile Impact
2002 2003 2004 2002-2004 Maximum
BWCA 0.040 0.034 0.029 0.031 0.040
Voyageurs 0.019 0.020 0.016 0.018 0.020
Predicting 24-Hour Maximum Emission Rates
Pursuant to guidance from MPCA and to be consistent with use of the highest daily emissions for 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.
� �N
Barr Footer: Date: 7/5/2006 1:27:58 PM File: I:\projects\23\00\Minntac.mxd User: ams
1000
100200
MetersM
inntac Aerial P
hoto
1000
100200
Meters
Taconite BART Analysis
NOx Control
Indurating Furnaces
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2 Reference(s)
This table is part of the Taconite BART Report and should not be
distributed without the full text of the report so that the information is
not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly
avail
ab
le c
on
tro
l
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le
for
this
so
urc
e?
Approximate
Control
Efficiency MP
CA
Taco
nit
e B
AR
T
Rep
ort
MP
CA
BA
RT
Gu
idan
ce
(Att
ach
men
t 2)
Oth
er2
Comments Basic Principle
Combustion Controls
1 Overfire Air (OFA) Y N --- --- --- xNOx formation front is not stationary in
an indurating furnace
Combustion air is separated into primary and secondary flow sections to
achieve complete burnout and to encourage the formation of N2 rather
than NOx
2External Flue Gas
Recirculation (EFGR)Y Y N --- --- x x
Mixes flue gas with combustion air which reduces oxygen content and
therefore reduces flame temperature
3 Low-NOx Burners Y Y
Y
(preheat
burners)
Y
(preheat
burners)
10-20% x x x
Higher control efficiency at the burner,
but the listed control efficiency is for
the entire furnace.
Burners are designed to reduce NOx formation through restriction of
oxygen, flame temperature, and/or residence time
4Induced Flue Gas
Recirculation BurnersY Y N --- --- x x x
Need to be upfired. Need convective
loop to get gas recirculatedDraws flue gas to dilute the fuel in order to reduce the flame temperature
5 Low Excess Air Y N --- --- --- xNeed high O2 for process requirements
and product qualityReduces oxygen content in flue gas and reduces flame temperature
6Burners out of Service
(BOOS)Y N --- --- --- x
Need capacity of all burners for worst
case scenario
Shut off the fuel flow from one burner or more to create fuel rich and fuel
lean zones
7 Fuel Biasing Y N --- --- --- x Power plant technology
Combustion is staged by diverting fuel from the upper level burners to the
lower ones or from the center to the side burners to create fuel-rich and
fuel-lean zones
8 Reburning Y N --- --- --- xKiln configuration not correct for this
technology.
Part of the total fuel heat input is injected into the furnace in a region
above the primary (main burners) flames to create a reducing atmosphere
(re-burn zone), where hydrocarbon radicals react with NOx to produce
elemental nitrogen
9 Load Reduction N --- --- --- --- xPower plant technology -product
demand side solution
This is a strategy to reduce load on a power plant by reducing the
electrical demand throught efficiency projects.
10 Energy Efficiency Projects Y Y
Y
(for large
projects like
heat-recoup)
Y
(for large
projects like
heat-recoup)
Site-specific x decrease amount of fuel required to make an acceptable product
11 Coal Drying Y N --- --- --- x Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is
required to be burned. Specific energy efficiency project
12
Coal Addition to Pellets with
Low Excess Air in the
Induration Furnace
N --- --- --- --- x Check on status of research Reduce flame temperature and energy requirements
13 Ported Kilns Y Y
Y
(grate-kilns
only)
N
(Metso says
no NOx
improvement)
--- x x Applicable to grate kilns. Provides additional oxygen for pellet oxidation which reduces the overall
energy use of the kiln
14 Combustion Zone Cooling Y N --- --- --- x Boiler technologyCooling of the primary flame zone by heat transfer to surrounding
surfaces
15 Alternate Fuels Y Y
Y
(for furnaces
capable of
multiple fuels)
Y
(not required
by BART)
Site-specific x x
Requires case by case analysis.
Typically, facilities experience lower
NOx when burning solid fuels.
Lower combustion temps with solid fuels vs gas. May also reduce fuel
NOx by using a fuel with less nitrogen.
16Oxygen Enhanced
CombustionN --- --- --- --- x Research level A small fraction of the combustion air is replaced with oxygen.
Taconite BART Analysis
NOx Control
Indurating Furnaces
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2 Reference(s)
This table is part of the Taconite BART Report and should not be
distributed without the full text of the report so that the information is
not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly
avail
ab
le c
on
tro
l
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le
for
this
so
urc
e?
Approximate
Control
Efficiency MP
CA
Taco
nit
e B
AR
T
Rep
ort
MP
CA
BA
RT
Gu
idan
ce
(Att
ach
men
t 2)
Oth
er2
Comments Basic Principle
17 Preheat Combustion N --- --- --- --- x Research level
Pulverized coal preheated and volatiles and fuel-bound nitrogen
compounds are released in a controlled reducing atmosphere where the
nitrogen compounds are reduced to N2.
18 ROFA-ROTAMIX Y N --- --- --- x
Can't achieve correct temperature
window (1400-1800F). Too hot in kiln
too cold in reheat
Combination of OFA and SCR. Wall-fired or tangentially-fired furnace that
utilizes high velocity overfire air. Additional NOx reductions are achieved
with ammonia injection (Rotamix)
19 NOx CEMS Y N --- --- --- x x Optimization of combustion
20 Parametric Monitoring Y N --- --- --- x x Optimization of combustion
38Catalyst Injection
(EPS Technologies)N --- --- --- --- x Research Level
A combustion catalyst is directly injected into the air intake stream and
delivered to the combustion site, initiating chemical reactions that change
the dynamics of the flame.
Post Combustion Controls
21Non-Selective Catalytic
Reduction (NSCR)Y N --- --- --- x x
For clean services. Too much stuff in
flue gas would poison catalyst
Under near stoichiometric conditions, in the presence of a catalyst, NOx is
reduced by CO, resulting in nitrogen (N2) and carbon dioxide (CO2).
22Low Temperature Oxidation
(LTO) - Tri-NOx® Y N --- --- --- x x Used for higher flue gas concentrations
Utilizes an oxidizing agent such as ozone to oxidize various pollutants
including NOx
23Low Temperature Oxidation
(LTO) - LoTOxY N --- --- --- x x x
Has been included as an "applicable
and available" technology in recent
BACT analyses from multiple facilities.
Utilizes an oxidizing agent such as ozone to oxidize various pollutants
including NOx
24Selective Catalytic
Reduction (SCR)Y Y Y Y 80% x x x
Need to inject at appropriate
temperature (reheat will be required).
Applicable on clean side only.
Although this hasn't been
demonstrated on an indurating
furnace, the stream characteristics
appear to make this technology
feasible.
Ammonia (NH3) is injected into the flue gas stream in the presence of a
catalyst to convert NOx into N2 and water
25 Regenerative SCR Y N --- --- --- x Clean side only
26Selective Non-Catalytic
Reduction (SNCR)Y N --- --- --- x x
Can't achieve correct temperature
window (1400-1800F). Too hot in kiln
too cold in reheat
Urea or ammonia-based chemicals are injected into the flue gas stream to
convert NO to molecular nitrogen, N2, and water
27 Adsorption N --- --- --- --- x Still in research stages. Use of char (activated carbon) to adsorb oxides of nitrogen
28 Absorption Y N --- --- --- x Similar to TriNOx
Use of water, hydroxide and carbonate solutions, sulfuric acid, organic
solutions, molten alkali carbonates, or hydroxides to absorb oxides of
nitrogen.
29 Oxidizer Y N --- --- --- x Redundant to regenerative SCR
Gas stream is sent through the regenerative, recuperative, catalytic or
direct fired oxidizer where pollutants are heated to a combustion point and
destroyed.
Taconite BART Analysis
NOx Control
Indurating Furnaces
Available and Applicable ReviewRevised: August 23, 2006
Step 1 Step 2 Reference(s)
This table is part of the Taconite BART Report and should not be
distributed without the full text of the report so that the information is
not taken out of context.
Refe
ren
ce N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly
avail
ab
le c
on
tro
l
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le
for
this
so
urc
e?
Approximate
Control
Efficiency MP
CA
Taco
nit
e B
AR
T
Rep
ort
MP
CA
BA
RT
Gu
idan
ce
(Att
ach
men
t 2)
Oth
er2
Comments Basic Principle
30 SNOX N --- --- --- --- x Early commercial development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by
catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter
passes through a novel glass-tube condenser in which the SO3 is
hydrated to H2SO4 vapor and then condensed to a concentrated liquid
sulfuric acid (H2SO4).
31 SOx-NOx-Rox-Box N --- --- --- --- xTechnology has not been
demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and
ammonia injection upstream of a zeolitic selective catalytic reduction
(SCR) catalyst incorporated in the baghouse to reduce NOx emissions.
32 Electron (E-Beam) Process N --- --- --- --- xNo operating commercial applications
on coal
Electron beam irradiation in the presence of ammonia to initiate chemical
conversion of sulfur and nitrogen oxides into components which can be
easily collected by conventional methods such as an ESP or baghouse.
33 Electrocatalytic Oxidation N --- --- --- --- xSimilar to cold plasma. Will keep
watch for availability of this technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen
dioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-
thermal plasma.
On recent project, the vender was doing final trials on full-scale
applications.
34 NOXSO N --- --- --- ---
Commercial version of adsorption.
Limited experience (proof-of-concept
tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from
flue gas from coal-fired utility and industrial boilers. In the process, the
SO2 is converted to a saleable sulfur by-product (liquid SO2, elemental
sulfur, or sulfuric acid) and the NOx is converted to nitrogen and oxygen.
35 Copper-Oxide N --- --- --- --- xAbsorption and SCR. Experience
limited to pilot scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres
of alumina, to form copper sulfate. Ammonia is injected into the flue gas
before the absorption reactor and a selective catalytic reduction-type
reaction occurs that reduces the nitric oxides in the flue gas. In the
regeneration step, the copper sulfate is reduced in a regenerator with a
reducing agent, such as natural gas, producing a concentrated stream of
SO2.
36 Cold Plasma N --- --- --- --- x Research Level
37 Biofilters Y N --- --- --- x Not applicable to furnaces.
Gas stream is passed through a filter medium of soil and microbes.
Pollutants are adsorbed and degraded by microbial metabolism forming
the products carbon dioxide and water.
38 Pahlman Process N --- --- --- --- x Research Level
Gas stream is passed through a filter baghouse in which specially-
developed, small-particle, high-surface area metal oxide sorbent have
been deployed. Pollutants are removed from the gases by adsorption.
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
2) c) New and Emerging Environmental Technologies, http://neet.rti.org/
2) d) ND BART Reports
Taconite BART Analysis
SO2 Control
Indurating Furnaces
Available and Applicable Review
Revised: August 23, 2006
Step 1 Step 2 Reference(s)
This table is part of the Taconite BART Report and should not be
distributed without the full text of the report so that the information is
not taken out of context.
Ref
eren
ce N
o.1
SO2 Pollution Control
TechnologyIs
th
is a
gen
era
lly
avail
ab
le c
on
tro
l
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le
for
this
so
urc
e?
Approximate
Control
Efficiency
MP
CA
Ta
con
ite
BA
RT
Rep
ort
MP
CA
BA
RT
Gu
ida
nce
(Att
ach
men
t 2
)
Oth
er2
Comments Basic Principle
1Wet Scrubbing (High
Efficiency)Y Y Y Y 90-95% x x x Absorption and reaction using an alkaline reagent to produce a solid compound
2Wet Scrubbing (Low
Efficiency)Y Y Y Y <50% x x x Absorption and reaction using an alkaline reagent to produce a solid compound
3Wet Walled Electrostatic
Precipitator (WWESP)Y Y Y Y 80% x x
Suspended particles are separated from the flue gas stream, attracted to plates, and
collected in hoppers
4 Dry sorbent injection Y Y Y N --- x x x
Pulverized lime or limestone is directly injected into the duct upstream of the fabric
filter. Dry sorption of SO2 onto the lime or limestone particle occurs and the solid
particles are collected with a fabric filter
5 Spray Dryer Absorption (SDA) Y Y Y N --- x xLime slurry is sprayed into an absorption tower where SO2 is absorbed by the
slurry, forming CaSO3/CaSO4
6 Alternative Fuels Y Y
Y
(for furnaces
capable of
multiple fuels)
Y
(not required
by BART)
Site-specific x x Natural gas is base case Use a fuel with lower sulfur content.
7 Load Reduction N --- --- --- --- x Power plant technologyThis is a strategy to reduce load on a power plant by reducing the electrical
demand throught efficiency projects.
8 Energy Efficiency Projects Y Y
Y
(for large
projects like
heat-recoup)
Y
(for large
projects like
heat-recoup)
Site-specific x decrease amount of fuel required to make an acceptable product
9 Coal Drying Y N --- --- --- x Applies only to facilities that burn coalDry coal will increase the as-burned BTU value, and therefore less fuel is required
to be burned. Specific energy efficiency project
10 Bio Filters N --- --- --- --- x Research level
Gas stream passes through a packed bed of specially engineered biomedia which
supports the growth of active bacterial species. The pollutants in the gas stream are
biodegraded or biotransformed into innocuous products, such as carbon dioxide,
water, chloride ion in water, sulfate or nitrate ions in water.
11 CANSOLV Regenerable SO2 N --- --- --- --- x Research level
An aqueous solution of proprietary diamine captures SO2 from the feed gas in a
countercurrent absorption tower. The rich solvent is regenerated by steam
stripping, giving a byproduct of pure, water saturated SO2 gas and lean solvent for
recycling to the absorber.
12 Pahlman Process N --- --- --- --- x Research level
Gas stream is passed through a filter baghouse in which specially-developed, small-
particle, high-surface area metal oxide sorbent have been deployed. Pollutants are
removed from the gases by adsorption.
13 SOx-NOx-Rox-Box N --- --- --- --- x Technology has not been demonstrated
Dry sorbent injection upstream of the baghouse for removal of SOx and ammonia
injection upstream of a zeolitic selective catalytic reduction (SCR) catalyst
incorporated in the baghouse to reduce NOx emissions.
14 Electron (E-Beam) Process N --- --- --- --- xNo operating commercial applications on
coal
Electron beam irradiation in the presence of ammonia to initiate chemical
conversion of sulfur and nitrogen oxides into components which can be easily
collected by conventional methods such as an ESP or baghouse.
Taconite BART Analysis
SO2 Control
Indurating Furnaces
Available and Applicable Review
Revised: August 23, 2006
Step 1 Step 2 Reference(s)
This table is part of the Taconite BART Report and should not be
distributed without the full text of the report so that the information is
not taken out of context.
Ref
eren
ce N
o.1
SO2 Pollution Control
TechnologyIs
th
is a
gen
era
lly
avail
ab
le c
on
tro
l
tech
no
log
y?
Is t
he c
on
tro
l te
ch
no
log
y
avail
ab
le t
o i
nd
ura
tin
g
furn
aces?
Is t
he c
on
tro
l te
ch
no
log
y
ap
pli
cab
le t
o t
his
sp
ecif
ic
so
urc
e?
Is i
t te
ch
nic
all
y f
easib
le
for
this
so
urc
e?
Approximate
Control
Efficiency
MP
CA
Ta
con
ite
BA
RT
Rep
ort
MP
CA
BA
RT
Gu
ida
nce
(Att
ach
men
t 2
)
Oth
er2
Comments Basic Principle
15 Electrocatalytic Oxidation N --- --- --- --- xSimilar to cold plasma. Will keep watch for
availability of this technology
Utilizes a reactor in which SO2, NOx, and mercury are oxidized to nitrogen
dioxide (NO2), sulfuric acid, and mercuric oxide respectively using non-thermal
plasma.
On recent project, the vender was doing final trials on full-scale applications.
16 NOXSO N --- --- --- ---Commercial version of adsorption. Limited
experience (proof-of-concept tests).
Uses a regenerable sorbent to simultaneously adsorb SO2 and NOx from flue gas
from coal-fired utility and industrial boilers. In the process, the SO2 is converted to
a saleable sulfur by-product (liquid SO2, elemental sulfur, or sulfuric acid) and the
NOx is converted to nitrogen and oxygen.
17 Copper-Oxide N --- --- --- --- xAbsorption and SCR. Experience limited to
pilot scale.
SO2 in the flue gas reacts with copper oxide, supported on small spheres of
alumina, to form copper sulfate. Ammonia is injected into the flue gas before the
absorption reactor and a selective catalytic reduction-type reaction occurs that
reduces the nitric oxides in the flue gas. In the regeneration step, the copper sulfate
is reduced in a regenerator with a reducing agent, such as natural gas, producing a
concentrated stream of SO2.
18 SNOX N --- --- --- --- x Early commercial development stage
Catalytic reduction of NOx in the presence of ammonia (NH3), followed by
catalytic oxidation of SO2 to SO3. The exit gas from the SO3 converter passes
through a novel glass-tube condenser in which the SO3 is hydrated to H2SO4 vapor
and then condensed to a concentrated liquid sulfuric acid (H2SO4).
19 Cold Plasma N --- --- --- --- x Research level
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
2) c) New and Emerging Environmental Technologies, http://neet.rti.org/
2) d) ND BART Reports
Summary of Relevant Economic Feasibility ($/ton) Control Costs
Avg. Expected Values
($/ton)
Limiting/Marginal values
($/ton)
Reference Regulatory Body/Rule SO2 NOx SO2 NOx Comments
BART 100 - 1000 100 - 1000 70 FR 39135
BART 281 - 1296 70 FR 39135 Table 3
BART 919 70 FR 39133 FR Notice 6JULY05 Final Rule
BART Guidelines disparagingly reference "thousands of dollars per ton" in commenting on the need to exceed MACT and its general unreasonableness.
70 FR 25210 CAIR CAIR 1300 Estimated Marginal cost 2009
BART(proposed rule) 200-1000
BART proposed lists this as values for 90-95% SO2 control, which is still assumed, or .1 to .15 lb/MMBtu. Dropped from final to give states flexibility to require more. Says for scrubbers, bypasses aren't BART, only 100% scrubbing is BART. FR Notice 5MAY04 Proposed Rule
BART(proposed rule) 0.2 lb/MMBtu for NOx is assumed reasonable. Recognizes that some sources may need SCR to get this level. For those, state discretion of the cost vs. visibility value is necessary.
CAIR(using IPM) 1000 1500
CAIR ( 2009 in 1999$) 900 2400
CAIR ( 2015 in 1999$) 1800 3000
Midwest RPO Report Referencing CAIR
CAIR (depending on Nat'l emissions)
1200 - 3000 1400- 2100 This was modeled with TRUM (Technology Retrofitting Updating Model) to develop the marginal values.
Kammer EPA Decision Kammer Decision > 1000 > 1000
LADCO Midwest RPO Boiler Analysis
LADCO/Midwest RPO 1240 - 3822 607 - 4493
MANE-VU BART Control Assessment
MANE-VU 200 - 500 200 - 1500
Bowers vs. SWAPCA Bowers vs. SWAPCA 300 300 1000 1000 954-1134 was ruled too much, in favor of 256-310 for SO2. This did consider incremental value. Sections XVII to XIX
WRAP 3000 WRAP Trading Program Methodology EPA - Referenced by
Wrap
References EPA-600S\7-90-018. Low is <$500/ton, Moderate is $500-3000/ton, High is over $3000/ton
The dollars per ton estimates cited above were obtained from BART guidance, documentation of similar regulatory programs such as CAIR, and relevant court decisions. These materials indicate that most EPA sanctioned documents, including the final BART ruling, concretely support an average expected reasonable cost range of $1,300 to $1,800 per ton of NOx removed and a range of $1,000 to $1,300 per ton of SO2 removed. The BART presumptive limits were set based on cost effective controls that were on average less than these ranges. As an example, the presumptive SO2 limit was established based on an average cost effectiveness of less than $1,000/ton. As the cost analysis extends into RPO, WRAP and other regional planning documentation, the cost ranges become more variable and difficult to predict. For ease of comparison, the federally established ranges for NOx and SO2 were used as a BART cost threshold basis.
Taconite BART Analysis
NOX Control
Process Boilers
Available and Applicable Review
Step 1 Step 2
Re
fere
nc
e N
o.1
NOx Pollution Control
Technology Is t
his
a g
en
era
lly
av
aila
ble
co
ntr
ol
tec
hn
olo
gy
?
Is t
he
co
ntr
ol te
ch
no
log
y
av
aila
ble
to
pro
ce
ss
bo
ile
rs?
Is t
he
co
ntr
ol te
ch
no
log
y
ap
plic
ab
le t
o t
his
sp
ec
ific
so
urc
e?
Is it
tec
hn
ica
lly
fe
as
ible
for
this
so
urc
e?
Approximate Control
Efficiency
Combustion Controls
1External Flue Gas
Recirculation (EFGR)Y Y N N ---
2 Low-NOx Burners (LNB) Y Y Y Y 50%
3 LNB with Overfire Air (OFA) Y Y Y Y 68%
4Induced Flue Gas
Recirculation BurnersY Y Y Y 75%
10 Energy Efficiency Projects Y Y Y Y Site-specific
15 Alternate Fuels Y Y Y
Y
(not required by
BART)
Site-specific
Post Combustion Controls
21Non-Selective Catalytic
Reduction (NSCR)Y N --- --- ---
22Low Temperature Oxidation
(LTO) - Tri-NOx® Y N --- --- ---
23Low Temperature Oxidation
(LTO) - LoTOxY Y Y Y 90%
24Selective Catalytic
Reduction (SCR)Y Y Y Y 80%
25 Regenerative SCR Y Y Y Y 70%
26Selective Non-Catalytic
Reduction (SNCR)Y Y Y Y 50%
1) This number is for reference only. It does not in any way rank the control technologies.
2) a) Air Pollution: Its Origin And Control. Wark, Kenneth; Warner, Cecil F.; and Davis, Wayne T. 1998. Addison Wesley Longman, Inc.
2) b) US EPA Basic Concepts in Environmental Science, Module 6, http://www.epa.gov/eogapti1/module6/index.htm
2) c) New and Emerging Environmental Technologies, http://neet.rti.org/
2) d) ND BART Reports