Appendix N 

Holcim-Clarksville BART Analysis 

April 24, 2008 
 

BART FIVE FACTOR ANALYSIS  HOLCIM (US) INC

CLARKSVILLE, MISSOURI

Prepared by: 

TRINITY CONSULTANTS

9777 Ridge Drive 

Suite 380 

Lenexa, Kansas 66219 

(913) 894-4500 

April 24, 2008 

Project 081701.0004 
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BART Analysis 

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY ........................................................................................ 1-1

2. INTRODUCTION AND BACKGROUND.................................................................... 2-1

3. BART APPLICABILITY DETERMINATION........................................................... 3-1

4. SO2 BART EVALUATION .................................................................................... 4-1

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL TECHNOLOGIES .......... 4-1 

4.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES ................ 4-2 

4.2.1 FUEL SUBSTITUTION ...........................................................................................4-2

4.2.2 RAW MATERIAL SUBSTITUTION / SELECTIVE MINING .......................................4-4

4.2.3 DRY LIME INJECTION/DRY LIME SCRUBBING ....................................................4-4

4.2.4 WET LIME SCRUBBING .......................................................................................4-6

4.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY EFFECTIVENESS .. 4-6 

4.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS..................................... 4-7 

4.4.1 WET LIME SCRUBBING .......................................................................................4-7

4.4.2 FUEL SUBSTITUTION ...........................................................................................4-9

4.4.3 DRY LIME SCRUBBING......................................................................................4-11

4.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS .................... 4-12 

4.6 PROPOSED BART FOR SO2 ................................................................................... 4-13 

5. NOX BART EVALUATION................................................................................... 5-1

5.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES......... 5-1 

5.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES............... 5-2 

5.2.1 LOW-NOX BURNER IN THE ROTARY KILN .........................................................5-2

5.2.2 FLUE GAS RECIRCULATION ................................................................................5-2

5.2.3 CEMENT KILN DUST INSUFFLATION ...................................................................5-3

5.2.4 MID-KILN FIRING OF SOLID FUEL WITH MIXING AIR FAN.................................5-3

5.2.5 SELECTIVE NONCATALYTIC REDUCTION............................................................5-5

5.2.6 SELECTIVE CATALYTIC REDUCTION...................................................................5-7

5.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS.. 5-8 

5.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 5-9 

5.4.1 MKF....................................................................................................................5-9

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ..................... 5-9 

5.6 PROPOSED BART FOR NOX.................................................................................. 5-10 
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LIST OF TABLES

TABLE 1-1. VISIBILITY IMPAIRMENT IMPROVEMENT..........................................................................1-2

TABLE 3-1. MODELED 24-HOUR EMISSIONS (AS AN HOURLY EQUIVALENT)....................................3-1

TABLE 3-2. SUMMARY OF STACK PARAMETERS ................................................................................3-1

TABLE 3-3. SUMMARY OF 98TH PERCENTILE VISIBILITY IMPACTS AND NUMBER OF DAYS WITH 

VISIBILITY IMPACT GREATER THAN 0.5 ΔDV.........................................................................3-2

TABLE 3-4. BREAKDOWN OF POLLUTANT SPECIFIC CONTRIBUTIONS TO VISIBILITY FOR THE 98TH

PERCENTILE DAY. ..................................................................................................................3-2

TABLE 4-1. EXISTING ACTUAL MAXIMUM 24-HOUR SO2 EMISSION RATES......................................4-1

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES.....................................................................4-1

TABLE 4-3. RANKING OF TECHNICALLY FEASIBLE KILN SO2 CONTROL TECHNOLOGIES BY 

EFFECTIVENESS ......................................................................................................................4-7

TABLE 4-4. COST ANALYSIS SUMMARY FOR WET LIME SCRUBBING ................................................4-9

TABLE 4-5. COST ANALYSIS SUMMARY FOR FUEL SUBSTITUTION..................................................4-10

TABLE 4-6. COST ANALYSIS SUMMARY FOR DRY LIME SCRUBBING ..............................................4-12

TABLE 4-7. SUMMARY OF EMISSION RATES MODELED IN SO2 CONTROL VISIBILITY IMPACT 

ANALYSIS .............................................................................................................................4-13

TABLE 4-8. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS4-13

TABLE 4-9. SUMMARY OF COST EFFECTIVENESS OF SO2 CONTROL OPTIONS .................................4-14

TABLE 5-1. EXISTING ACTUAL MAXIMUM 24-HOUR NOX EMISSION RATES.....................................5-1

TABLE 5-2. POSSIBLE NOX CONTROL TECHNOLOGIES ......................................................................5-2

TABLE 5-3. RANKING OF TECHNICALLY FEASIBLE KILN NOX CONTROL TECHNOLOGIES BY 

EFFECTIVENESS ......................................................................................................................5-9

TABLE 5-4. SUMMARY OF EMISSION RATES MODELED IN NOX CONTROL VISIBILITY IMPACT 

ANALYSIS .............................................................................................................................5-10

TABLE 5-5. NOX CONTROL VISIBILITY IMPACT ANALYSIS...............................................................5-10
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BART Analysis 

1. EXECUTIVE SUMMARY

This report documents the determination of the Best Available Retrofit Technology (BART) as 

proposed by Holcim (US) Inc. (Holcim) for the Portland cement manufacturing plant located in 

Clarksville, Missouri (Clarksville plant). This analysis is for the kiln system. Currently, particulate 

matter emissions from the kiln are controlled by an electrostatic precipitator. The Clarksville plant 

has other lesser emitting BART-eligible emissions units, all of which have Particulate Matter Control 

Devices (PMCDs) installed. The negligible visibility impairment attributable to these sources 

concludes that no additional controls are necessary to satisfy the requirements of the BART rule.1 

Holcim used the U.S. Environmental Protection Agency’s (EPA’s) guidelines2 in 40 CFR Part 51 to 

determine BART for the kiln. Specifically, Holcim conducted a five-step analysis to determine 

BART for SO2, NOX, and PM10 that included the following: 

1. Identifying all available retrofit control technologies; 

2. Eliminating technically infeasible control technologies; 

3. Evaluating the control effectiveness of remaining control technologies; 

4. Evaluating impacts and document the results; 

5. Evaluating visibility impacts 

Based on the five-step analysis, Holcim proposes the following as BART: 

Kiln: 

• PM10 – Holcim has determined that the existing electrostatic precipitator constitutes BART. 

This control device is effective for controlling PM10 from a wet kiln. 

• NOX – Holcim has determined that BART for the Holcim Clarksville Kiln is the installation 

and operation of a Mid Kiln Firing (MKF) system. 

• SO2 – Holcim proposes that no additional SO2 controls are required for BART compliance. 

Additional SO2 controls would require significant expenditures relative to the visibility 

improvements and are not justified. 

The proposed BART control strategies will result in reductions of the visibility impacts attributable to 

the Clarksville plant. A summary of the visibility improvement at Class I areas based on the existing 

emission rates and proposed BART emission rates is provided in Table 1-1. 

 1 Holcim submitted an inventory of all of the BART-eligible emission sources to the MDNR. Based on a review 

of this information, the MDNR concluded that the contributions from particulate matter from the non-kiln sources to 

visibility impairment is negligible and further analysis of these smaller particulate matter sources was not required. Meeting

with the MDNR dated January 23, 2008. 

2 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations 
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BART Analysis 

TABLE 1-1. VISIBILITY IMPAIRMENT IMPROVEMENT

Mingo National 

Wildlife Refuge 

Hercules Glades 

Wilderness Area 

Upper Buffalo 

Wilderness Area 

Existing 98% Impact (Δdv) 1.01 0.81 0.61 

BART 98% Impact (Δdv) 0.92 0.72 0.60 

Improvement 98% Impact (Δdv) 8.9% 11.1 1.6% 
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BART Analysis 

2. INTRODUCTION AND BACKGROUND

On July 1, 1999, the U.S. EPA published the final Regional Haze Rule (RHR). The objective of the 

RHR is to improve visibility in 156 specific areas across with United States, known as Class I areas. 

The Clean Air Act defines Class I areas as certain national parks (over 6000 acres), wilderness areas 

(over 5000 acres), national memorial parks (over 5000 acres), and international parks that were in 

existence on August 7, 1977. 

On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the Best Available 

Retrofit Technology (BART) rule, which included guidance for making source-specific BART 

determinations. The BART rule defines BART-eligible sources as sources that meet the following 

criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant, 

(2) Began operation between August 7, 1962 and August 7, 1977, and 

(3) Are included as one of the 26 listed source categories in the guidance. 

A BART-eligible source is subject to BART if the source is “reasonably anticipated to cause or 

contribute to visibility impairment in any federal mandatory Class I area.” EPA has determined that a 

source is reasonably anticipated to contribute to visibility impairment if the 98th percentile visibility 

impacts from the source are greater than 0.5 delta deciviews (∆dv) when compared against a natural 

background. Air quality modeling is the tool that is used to determine a source’s visibility impacts. 

Once it is determined that a source is subject to BART, a BART determination must address air 

pollution control measures for the source. The visibility regulations define BART as follows: 

“...an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant 

which is emitted by...[a BART-eligible source]. The emission limitation must be 

established on a case-by-case basis, taking into consideration the technology available, 

the cost of compliance, the energy and non air quality environmental impacts of 

compliance, any pollution control equipment in use or in existence at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which 

may reasonable be anticipated to result from the use of such technology. 

Specifically, the BART rule states that a BART determination should address the following five 

statutory factors: 

1. Existing controls 

2. Cost of controls 

3. Energy and non-air quality environmental impacts 

4. Remaining useful life of the source 

5. Degree of visibility improvement as a result of controls 
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BART Analysis 

Further, the BART rule indicates that the five basic steps in a BART analysis can be 

summarized as follows: 

1. Identify all available retrofit control technologies; 

2. Eliminate technically infeasible control technologies; 

3. Evaluate the control effectiveness of remaining control technologies; 

4. Evaluate impacts and document the results; 

5. Evaluate visibility impacts 

A BART determination should be made for each visibility affecting pollutant (VAP) by following the 

five steps listed above for each VAP. 

BART applicability was determined for the Clarksville plant based on an applicability analysis 

performed by the MDNR and a refined applicability analysis performed by Holcim. Both analyses 

determined that the kiln is subject to BART. The details of the applicability determination can be 

found in Section 3. 

Subsequently, Holcim performed an analysis to determine BART for each VAP for the kiln. The 

VAPs emitted by the kiln include NOx, SO2, and particulate matter with a mass mean diameter 

smaller than ten microns (PM10) of various forms (filterable coarse particulate matter [PMc], filterable 

fine particle matter [PMf], elemental carbon [EC], inorganic condensable particulate matter [IOR 

CPM] as sulfates [SO4], and organic condensable particulate matter [OR CPM] also referred to as 

secondary organic aerosols [SOA]). The BART determinations for SO2 and NOX can be found in 

Sections 4 and 5 respectively. 
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BART Analysis 

3. BART APPLICABILITY DETERMINATION

As stated in Section 2, a BART-eligible source is subject-to-BART if the source is “reasonably 

anticipated to cause or contribute to visibility impairment in any federal mandated Class I area.” EPA 

has determined that a source is reasonably anticipated to contribute to visibility impairment if the 98th

percentile of the visibility impacts from the source is greater than 0.5 ∆dv when compared against a 

natural background. The MDNR conducted air quality modeling for the kiln to predict the existing 

visibility impairment attributable to the Clarksville plant in the following Class I areas: 

• Mingo National Wildlife Refuge 

• Hercules Glade Wilderness Area 

• Upper Buffalo Wilderness Area 

Based on this modeling, the MDNR concluded that the Clarksville plant was subject to BART since 

the 98th percentile of the visibility impacts attributable to the kiln are greater than 0.5 Δdv when 

compared against a natural background for a Class I area. 

The modeling methods and procedures that Holcim followed were consistent with the methods and 

procedures that were followed in the MDNR’s original modeling. Table 3-1 summarizes the emission 

rates that were modeled for SO2, NOX, and PM103. The SO2 and NOx emission rates are the highest 

actual 24-hour emission rates based on 2003-2007 continuous emissions monitoring system (CEMS) 

data. The PM10 emission rates are based on data included in Holcim’s BART survey. 

TABLE 3-1. MODELED 24-HOUR EMISSIONS (AS AN HOURLY EQUIVALENT) 

SO2 NOX Total 

PM10 

(lb/hr) (lb/hr) (lb/hr) 

4889.38 3049.38 51.82 

Table 3-2 summarizes the stack parameters that were used to model the kiln. 

TABLE 3-2. SUMMARY OF STACK PARAMETERS

Parameter Value 

Actual Stack height (ft) 250 

Stack Diameter (ft) 21.7 

Exhaust Velocity (ft/s) 34.3 

Exhaust Temperature (F) 367 

The results of the modeling indicate that the 98th percentile of the visibility impacts are greater than 

0.5 Δdv when compared against a natural background. Since the visibility impacts are greater than 

0.5 Δdv, the kiln is subject to BART. The results of the modeling are summarized in Table 3-3. 

 3 The non-kiln PM10 emissions were included in the model as part of the kiln PM10 emissions. 
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TABLE 3-3. SUMMARY OF 98TH PERCENTILE VISIBILITY IMPACTS AND NUMBER OF DAYS WITH 

VISIBILITY IMPACT GREATER THAN 0.5 ΔDV

 Visibility Impairment 

Class I Area 

98th % 

Δdv

Days > 0.5 

Δdv

Mingo Wilderness 1.01 75 

Hercules Glades Wilderness 0.81 40 

Upper Buffalo Wilderness 0.61 33 

Table 3-4 provides a breakdown of the visibility impacts listed in Table 3-3 by each VAP for the high 

(98th percentile) day (note that the specific percentiles vary from day to day, and location to location, 

the breakdown listed is an example of one event only). 

TABLE 3-4. BREAKDOWN OF POLLUTANT SPECIFIC CONTRIBUTIONS TO VISIBILITY 

FOR THE 98TH PERCENTILE DAY. 

Visibility 

Impairment 

Attributable 

to SO4

Visibility 

Impairment 

Attributable 

to NO3

Visibility 

Impairment 

Attributable 

to SOA 

Visibility 

Impairment 

Attributable 

to EC 

Visibility 

Impairment 

Attributable 

to PMc

Visibility 

Impairment 

Attributable 

to PMf

Total 

Visibility 

Impairment

Class I Area (%) (%) (%) (%) (%) (%) (Δdv) 

Mingo Wilderness 98.6 1.2 0 0 0 0.2 1.01 

Hercules Glades Wilderness 42.3 57.5 0 0 0 0.2 0.81 

Upper Buffalo Wilderness 95.7 4.2 0 0 0 0.1 0.61 

As shown in Table 3-4, the most significant contributors to the visibility impairment are sulfates 

(SO4) and nitrates (NO3). The SO4 contribution is from the chemical conversion of SO2 emitted by 

the kiln to SO4. The NO3 contribution is entirely from the chemical conversion of NOX emitted from 

the kiln. The contribution of PM10 to the total visibility impairment can be estimated as the sum of 

the contributions from SOA, EC, PMc, and PMf. The PM10 contribution is much smaller (<1%) than 

the contribution from SO2 and NOX. 
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BART Analysis 

4. SO2 BART EVALUATION

Sulfur, in the form of metallic sulfides (pyrite), sulfate, or organosulfur compounds, is often found in 

the raw materials used to manufacture cement and in the solid and liquid fuels burned in cement 

kilns.4 The raw materials and fuels for the Clarksville plant are no exception. Sulfur dioxide can be 

generated by the oxidation of sulfur compounds in the raw materials and fuels during operation of the 

pyroprocess. Constituents found in fuels, raw materials, and in-process materials, such as the alkali 

metals (sodium and potassium), calcium carbonate, and calcium oxide react with SO2 formed in the 

pyroprocess and much of the sulfur leaves the process in the principle product of the kiln system 

called clinker. 

The kiln is the only BART source which emits SO2, thus an SO2 BART evaluation was performed 

only for the kiln. The maximum actual 24-hour kiln SO2 emission rate that was modeled for the 

BART applicability determination is summarized in Table 4-1. . 

TABLE 4-1. EXISTING ACTUAL MAXIMUM 24-HOUR SO2 EMISSION RATES

SO2 24-Hour 

Emission Rate 

SO2 Hourly 

Equivalent Emission 

Rate 

 ton/24-hr lb/hr 

Kiln 58.67 4889.38 

4.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL 

TECHNOLOGIES

Step 1 of the BART determination is the identification of all available retrofit SO2 control 

technologies. A list of control technologies was obtained by reviewing the U.S. EPA’s Clean Air 

Technology Center, publicly-available air permits, applications, and technical literature published by 

the U.S. EPA, state agencies, and Regional Planning Organizations (RPOs). 

The available retrofit SO2 control technologies are summarized in Table 4-2. 

TABLE 4-2. AVAILABLE SO2 CONTROL TECHNOLOGIES

SO2 Control Technologies 

Fuel Substitution 

Raw Material Substitution 

Dry Lime Injection/Scrubbing 

Wet Lime Scrubbing 

 4 Miller, F. MacGregor and Hawkins, Garth J., ”Formation and Emission of Sulfur Dioxide from the Portland Cement 

Industry”, Proceedings of the Air and Waste Management Association, June 18-22, 2000. 
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4.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible SO2 control technologies that 

were identified in Step 1. 

4.2.1 FUEL SUBSTITUTION

Holcim uses a mixture of coal, petroleum coke, alternative fuels (synfuel), and oil as the 

primary fuels for the kiln. For example, the 2007 actual fuel usage breakdown on an 

energy input basis, was 3.4 percent coal, 84 percent petroleum coke, 11.8 percent synfuel, 

and 0.8 percent oil (the fuel usages are also on an as received basis). The sulfur content of 

the petroleum coke is approximately 5.72 percent and the sulfur content of the coal is 

approximately 3.45 percent. 

The design of the long wet kiln system is such that some of the SO2 resulting from fuel 

combustion may be emitted and the rest is absorbed in clinker or CKD. Therefore, if 

Holcim reduces sulfur in the fuel input to the kiln, a corresponding reduction in SO2

emissions from the kiln would be expected. Fuel sulfur content could be reduced by 

burning a coal with a lower sulfur content of 0.7 percent, in lieu of the current coal/coke, 

which would result in a lower overall fuel sulfur content. 

Determining the specific reduction in SO2 emissions from a reduction in fuel sulfur is 

complicated as the reactions in the kiln system are complex. The sulfur is introduced into 

the system in the fuel as well as the raw materials (pyrites) and the sulfur exits the kiln 

system in the product (clinker), the cement kiln dust (CKD), and out the stack as SO2. 

Further, although the sulfur in the clinker is small on a percentage basis, the magnitude of 

the clinker production is extremely large (greater than 1 million tons per year). 

Consequently, small changes in the amount of sulfur absorbed in the product can 

dramatically change the amount of SO2 emitted. The variation in sulfur in the raw 

materials from the quarry, the clinker quality requirement determined by the market, and 

the kiln conditions can all cause significant changes in kiln operating parameters, such as 

kiln burning temperature, kiln excess Oxygen, etc. These changes can have a strong 

impact on the sulfur absorbed in the clinker and CKD and hence on SO2 emissions. These 

operating conditions can also strongly change how the fuel sulfur affects SO2 emissions. 

Reviewing the data yields that there is no linear correlation between fuel sulfur and SO2

emissions. To calculate an SO2 control effectiveness, based on switching to a lower sulfur 

fuel, a high number of assumptions must be made with a very low confidence in the 

accuracy. Regardless, an attempt has been made. 

The assumptions, based on long term averages in 2007, which can vary significantly on an 

annual and short term (24-hr) basis, include that 65 percent of sulfur input in the kiln 

system is from fuel, 35 percent of sulfur input is from raw materials, and approximately 

30-35 percent of total sulfur input is estimated to ultimately be emitted as SO2 in the stack. 

Based on the 2007 data, if all of the current coal and coke is replaced with low sulfur coal, 

the sulfur input from fuel is calculated to be reduced by approximately 85 percent. 

Following is a summary of the sulfur input reduction from the use of low sulfur coal. The 

low sulfur coal has a lower heat content (26 Gj/Metric ton) and higher moisture content 
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than the coke currently being used (33 Gj/Metric ton), so a higher volume of low sulfur 

coal is needed than coke reduced. 

Current – 2007 Average

Coke Usage: 160,915 metric tons 

Low Heat Content 32.510 Gj/Mt 

Sulfur Content: 5.72 % 

Sulfur Input from Coke: 9,204 metric tons 

Current Coal Usage: 9,432 metric tons 

Low Heat Content 22.177 Gj/Mt 

Sulfur Content: 3.45 % 

Sulfur Input from Coal: 325 metric tons 

Total Sulfur Input from Coke/Coal: 9,529 metric tons 

Low Sulfur Coal Replacement

Coal Usage: 208,546 metric tons 

Heat Content 26.266 Gj/Mt 

Sulfur Content: 0.7 % 

Total Sulfur Input from Coal: 1,459 metric tons 

Net reduction in sulfur input from coal:

 9,529 metric tons – 1,459 metric tons = 8,070 metric tons = 8,893 tons 

The SO2 reduction calculation, based on the calculated sulfur reduction, is very 

complicated. The pyrite sulfur from the raw materials can volatilize at relatively low 

temperatures in the kiln, in an area where the sulfur comes in contact with the kiln feed that 

has only minimally been calcined into CaO. Consequently, less of this sulfur reacts with 

the CaO and thus is emitted. Again, if the sulfur reacted with the CaO, it would be 

absorbed into the clinker and CKD. The fuel sulfur, on the other hand, enters the kiln in 

the burning zone and travels the entire length of the kiln, coming in contact with much 

higher concentrations of CaO, thus having a much greater chance of being absorbed. 

Consequently, there is no simple linear relationship between fuel sulfur and SO2 emissions 

that can be used to confidently calculate an SO2 reduction. 

The fuel sulfur reduction of 8,893 tons corresponds with a 54 percent reduction of the total 

sulfur (fuel and raw material sulfur) input to the kiln system in 2007. As mentioned above, 

a large fraction of fuel sulfur would have been absorbed by the CaO in the system, and thus 

would not have been emitted as SO2, while SO2 emitted from the pyrite in the raw 

materials has less of a chance of being absorbed, so there is not a directly proportional 

reduction in SO2 with the sulfur reduction from the fuels, nor with the total sulfur 

reduction. Holcim estimates that based on the year 2007 data, the actual SO2 reduction is 

about 40% - 50%. 
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These reductions are the maximum reductions in tons of SO2 that can be expected, 

especially if overall emissions of SO2 increase from other sources (such as raw materials). 

As mentioned previously, the actual reduction will vary significantly, especially on a short 

term basis. Holcim estimates that the net reduction in SO2 would be in the range of 40 

percent to 50 percent. 

Holcim considers this technology to be technically feasible and will consider it further. 

4.2.2 RAW MATERIAL SUBSTITUTION / SELECTIVE MINING

In a long wet kiln, not only the pyritic sulfur, but total sulfur in the raw materials will have 

an impact on SO2 emissions. 

Part of the pyritic sulfur reacts with oxygen and forms SO2 at the relatively lower 

temperature zone of the kiln. The rest of the sulfur, such as sulfates and sulfur compounds, 

enters the kiln at higher temperature zones, where more SO2 is volatized. Some of this SO2

will pass the length of the kiln without being absorbed and will thus be emitted to the 

stack. 

Using raw materials with lower sulfur content can reduce the potential for SO2 emissions 

from a wet kiln system. The limestone, shale, and other raw materials used at the 

Clarksville plant contain pyrites and total sulfur in varying concentrations. If zones or 

layers in the on-site quarry could be identified and mined selectively such that lower sulfur 

content materials are used, the emission rate of SO2 could be reduced. Holcim has 

conducted a complete quarry investigation, and based on the quarry scheduling 

optimization (QSO) model and computation, after 1-2 years of mining, the plant will be 

facing an area that has an even higher total sulfur content than that currently being used. 

Thus, there will be a higher total sulfur content in the raw material in the next 3-10 years. 

The total sulfur in the raw materials is expected to increase by an additional ~30% without 

selective quarrying, and by ~20% if some form of selective quarrying can be identified. 

Similarly, no significant reduction of pyritic sulfur from selective mining is anticipated. 

Selective mining is not considered a technically feasible SO2

 control technology for the 

kiln. Moreover, Holcim is concerned that actual annual emissions resulting from normal 

variability at the plant will lead to an increase in SO2 emissions as a result of total sulfur 

increases in the raw materials from the quarry. This variability will need to be considered 

in any potential BART control strategy. 

4.2.3 DRY LIME INJECTION/DRY LIME SCRUBBING

Dry Lime Injection, or Dry Lime Scrubbing (DLS), consists of injecting hydrated lime, 

Ca(OH)2, into the flue gas. The Ca(OH)2 reacts with SO2 in the flue gas stream to create 

fine particles of CaSO3 or CaSO4. The particles are collected in the particulate matter 

control device (PMCD) serving the kiln. 

The current PMCD was not sized/designed to handle the additional particulate matter 

loading that would result from this technology. Consequently, adding DLS could cause 
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PM emissions and opacity to increase above permitted levels requiring Holcim to replace 

the existing PMCD (an ESP) with a new PMCD (a Baghouse). 

Holcim is aware of only one other long term application of this technology on a wet kiln, 

which is on a smaller wet kiln in Belgium. Consequently, very little data exists to directly 

quantify the feasibility or benefit (emission reduction) of such a system. Regardless, 

Holcim is considering the technology to be technically feasible. 

The effectiveness of DLS is impacted by both the temperature and the residence time/air 

flow rate at the location it is injected. At Clarksville, the injection point would be between 

the kiln outlet and the PMCD. At this location, the temperature is approximately 200 deg 

C (415 deg F). The temperature can not be increased at this location as the plant has 

limitations on the inlet temperature to the PMCD from both the Portland Cement MACT 

and the Hazardous Waste Combustion MACT in order to meet the Dioxin/Furan (D/F) 

limit. Further, lowering the temperature would lead to lower ESP efficiency and opacity 

problems. Figure 4-1 is a plot of SO2 reduction versus reaction temperature from a 

commonly used article entitled “What is Achievable with Today’s Technologies”, Mark S. 

Terry, Krupp Polysius Corp, 2001. As indicated in the figure, at a temperature of 200 deg 

C (415 deg F), the reduction level is approximately 30 percent, which is the lowest 

reduction level over the temperature range presented. 

FIGURE 4-1. SO2 REDUCTION VERSUS REACTION TEMPERATURE FOR HYDRATED LIME 

The molar ratio of lime (calcium source) to SO2 is much higher than in a typical coal fired 

boiler due to a number of factors, some of which include the higher CO2 and dust levels in 

the cement kiln system exhaust. The CO2 competes with SO2,in the reaction with the lime, 

and the higher dust loading reduces the even distribution of the lime in the gas. Based on 

a communication with the Obourg plant in Belgium, a molar ratio of between 4:1 and 6:1 
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has been used. The larger size of the Clarksville kiln will make it more difficult to evenly 

distribute the lime to the kiln gas and thus Holcim anticipates that a molar ratio of 6:1 will 

be required to achieve a maximum control efficiency of 20 - 30 percent. 

Holcim considers this technology to be technically feasible and will consider it further. 

4.2.4 WET LIME SCRUBBING

Wet lime scrubbing (WLS) is a name for a traditional tailpipe wet scrubber. This process 

involves passing the flue gas from the main PMCD through a sprayed aqueous suspension 

of Ca(OH)2 or CaCO3 (limestone) that is contained in an appropriate scrubbing device. In 

the case of the Clarksville plant, the basic underlying economics would dictate the use of 

ground limestone as the scrubbing reagent. Use of the cement kiln dust as a scrubbing 

reagent was not considered as a viable option for Clarksville due to its high chlorine 

content and a large amount of inerts. In WLS, the aqueous suspension of scrubbing 

reagent is not taken to dryness as it is in DLS. The SO2 reacts with the scrubbing reagent 

to form CaSO3.H20 or gypsum that is collected and retained as aqueous sludge. The sludge 

is either dewatered and disposed of or used as synthetic gypsum. 

The scrubbing efficiency of WLS can vary from an estimated 80 percent to 95 percent of 

the SO2 in the flue gas treated by the scrubber5. Further, WLS is a high maintenance 

process with high rates of downtime expected from build up or plug up of mist-eliminators 

or spray nozzles and the severe wear and corrosion of components. Holcim has found that 

high levels of hydrocarbons (THC) in the gas stream have caused significant corrosivity 

and foam build-up at their Dundee plant. Further, it significantly influences the system 

availability and the efficiency. The THC levels at the Clarksville plant may also lead to 

build up and plugging, and thus an availability (uptime) of the WLS of 95 percent is 

assumed. 

Despite these identified drawbacks, WLS is considered a technically feasible BART 

option. 

4.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Table 4-3 provides the effectiveness of each technology in the form of an annual 

average efficiency. 

 5 Assessment of Control Technology Options for BART-Eligible Sources Steam Electric Boilers, Industrial 

Boilers, Cement Plants and Paper and Pulp Facilities. Prepared by Northeast States for Coordinated Air Use Management In 

Partnership with The Mid-Atlantic/Northeast Visibility Union, March 2005, Page 4-21, Table IV-4. Range of Removal 

Efficiencies of Wet SO2 Scrubbers for Long Wet Kilns. 
Holcim (US) Inc. 4-7 Trinity Consultants 

BART Analysis 

TABLE 4-3. RANKING OF TECHNICALLY FEASIBLE KILN SO2 CONTROL TECHNOLOGIES BY 

EFFECTIVENESS

Control Technology 

Effectiveness 

SO2 Reduction 

(Percent Reduction – Annual Basis) 

Wet Lime Scrubbing 80-95% 

Fuel Substitution 40-50% 

Dry Lime Scrubbing 20-30% 

4.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS 

Step four of the BART analysis procedure is the impact analysis. The BART determination 

guidelines list the four factors to be considered in the impact analysis: 

• Cost of compliance 

• Energy impacts 

• Non-air quality impacts; and 

• The remaining useful life of the source 

Holcim has conducted an impact analysis for the remaining SO2 control options. 

4.4.1 WET LIME SCRUBBING

Cost of Compliance 

Holcim utilized a recent WLS vendor bid as the basis for the economic analysis to 

determine the annualized cost for WLS. Holcim divided the annualized cost of WLS by 

the annual tons of SO2 reduced to determine the cost effectiveness for WLS. The “annual 

tons reduced” were determined by subtracting the estimated controlled annual emissions 

from the existing annual emissions. The existing annual emissions should be considered 

both on a projected actual and a potential to emit (PTE) basis. The projected actual (PA) 

annual SO2 emissions provided to the MDNR in the recent Mid Kiln Firing (MKF) permit 

application was 11,481 tons/year6. The PTE listed in the MKF permit is 13,298 tons/year. 

The estimated controlled annual emissions were calculated by applying an 80 percent to 95 

percent control efficiency and a 95 percent control device uptime, to the projected actual 

annual and PTE emissions. Table 4-4 provides a summary of the cost effectiveness 

analysis related to WLS. The detailed cost analysis table is provided in Appendix A. 

The equipment cost includes both the WLS system and a limestone preparation system. 

The limestone preparation system includes 2 Ball Mills used to grind the limestone 

received to a specific fineness. 

 6The projected actual annual emission rate was determined as part of the construction permit application process 

to support the August 27, 2007 Mid Kiln Firing construction permit. Permit Number 082007-019. 
Holcim (US) Inc. 4-8 Trinity Consultants 

BART Analysis 

The cost effectiveness analysis does not include the cost to construct a new exhaust stack, 

which may be needed to employ the WLS technology, and it does not include the possible 

additional cost for the equipment relocation on site due to the limited space available for 

the WLS system. 

The control cost factors were obtained from the EPA’s Control Cost Manual, 6th Edition. 

Some of the factors have been scaled, as indicated, based on the construction being a 

retrofit, rather than Greenfield, and company knowledge of the actual cost of similar 

size/type projects. 

Two factors that significantly increase the cost of this technology are the need to reheat the 

exhaust gas and the cost of sludge disposal. 

Exhaust Gas Reheat

A common concern of utilizing a wet scrubber on a cement kiln exhaust gas is the probable 

formation of a detached plume resulting in opacity violations. For a typical cement kiln 

stack, if the exhaust gas contains NH3, HCl, and SO2, sub-micron aerosols of NH4Cl and 

(NH4)2SO4 may form when the gas temperature is reduced after exiting the stack. A 

detached plume is predicted to occur when the exhaust gas is cooled to the dew point at or 

near the exit of the stack and prior to the dilution of the aerosol forming constituents. The 

wet scrubber requires the exhaust gas to be cooled to the dew point at the inlet of the 

scrubber. As the temperature of the exhaust gas is cooled in the scrubber, a visible plume 

condition is nearly assured. The sub-micron NH4Cl aerosol will be formed and is difficult 

to remove in the scrubber. This problem has been reported for wet scrubbers used at 

cement plants. As the plant is subject to a 20 percent opacity limitation from both the 

PCMACT and HWCMACT, even a small increase in opacity could lead to an exceedance 

of the standard, which is not acceptable. Based on information from Holcim’s Dundee, 

Michigan plant, Holcim anticipates that the temperature of the exhaust gas at the exit of the 

scrubber would be approximately 170 deg F. To keep the sub-micron particles from 

forming at the exit of the stack, reheating the exhaust gas, after the scrubber, is required. 

Without having any data to determine an optimum outlet temperature for the stack gas 

(after a scrubber is installed), Holcim has conservatively determined that to counteract this 

effect, the exhaust gas would need to be reheated to the current gas temperature after the 

ESP of approximately 380 deg F. This re-heating would most likely be achieved using 

natural gas combustion. The natural gas combustion would lead to a 97 ton/year increase 

in NOx emissions that would negatively impact visibility gains from the SO2 reduction. 

Sludge Disposal 

The sludge generated from the WLS system may require disposal. Therefore, Holcim has 

determined the cost of disposal based on a bid from Area Disposal Services, Inc. for the 

disposal fee ($36/ton), as well as the cost for trailer rental ($120/month) and transportation 

($220/load). 
Holcim (US) Inc. 4-9 Trinity Consultants 

BART Analysis 

WLS may also lead to an increase in PM emissions because some particles of limestone or 

CaSO3 will be entrained in the flue gas and subsequently be emitted from the scrubber. 

WLS is also known to increase emissions of sulfuric acid mist.7

TABLE 4-4. COST ANALYSIS SUMMARY FOR WET LIME SCRUBBING

Control Case 

Control 

Effectiveness Annual Cost 

Existing Annual 

Emissions 

Pollutant*

Removed 

Cost** 

Effectiveness 

Cost*** 

Impact 

(%) ($/yr) (tons/yr) (tons/yr) ($/ton) ($/ton clinker) 

WLS – PA 80% $24,706,548 11,481 8,726 $2,863 $20 

WLS – PA 95% $25,246,115 11,481 10,362 $2,460 $21 

WLS – PTE 80% $25,161,975 13,298 10,106 $2,514 $21 

WLS – PTE 95% $25,786,935 13,298 12,001 $2,166 $21 *

Assumes 95% uptime. 

**Includes 97 tons of NOx generated. 

***Based on a maximum historical actual clinker production rate of 1,215,708 tons/year. 

The significant increases in cost per ton of clinker produced from using WLS, as shown in 

Table 4-4, would likely eliminate any profit margin currently realized by the plant. Thus, 

it would not be economically feasible to operate the plant with WLS. 

Energy Impacts 

A wet scrubber requires an additional fan of considerable horsepower to move the flue gas 

through the scrubber. The exhaust gas reheat requirement will utilize approximately 

1,000,000 MMcf/year of natural gas, which will itself lead to an increase in NOx emissions 

of 97 tons/yr. 

Non Air-Quality Impacts 

Without reheating, a frequent steam plume and/or detached plume can be expected at the 

discharge of the wet scrubber that would result in visual impairment in the area. 

The WLS technology could generate over 50,000 tons per year of waste (sludge) that will 

require disposal in a landfill. 

Remaining Useful Life 

The remaining useful life of the kiln does not impact the annualized cost of WLS because 

the useful life is anticipated to be at least as long as the capital cost recovery period, which 

is 15 years. 

4.4.2 FUEL SUBSTITUTION

Cost of Compliance 

 7 Innovations in Portland Cement Manufacturing, Portland Cement Association, 2004, pg. 660 & 669 
Holcim (US) Inc. 4-10 Trinity Consultants 

BART Analysis 

The increased cost of using low sulfur coal includes the relative increase in fuel cost as 

well as the cost of a new coal mill system. Low sulfur coal is harder than the current 

coal/coke utilized and has a lower heat content; consequently, a higher volume of coal 

grinding will be needed than the current mill can achieve. The increased grinding 

requirement would also have an additional energy requirement. A bid for a new coal mill, 

classifier, and mill motors, was obtained from GEBR. Pfeiffer USA Inc. Table 4-5 

provides a summary of the cost effectiveness analysis related to Fuel Substitution. The 

detailed cost analysis table is provided in Appendix A. 

The cost effectiveness analysis does not include the cost to construct any new storage or 

handling facilities for the low sulfur coal that may be required. 

The control cost factors were obtained from the EPA’s Control Cost Manual, 6th Edition. 

Some of the factors have been scaled, as indicated, based on the construction being a 

retrofit, rather than greenfield, and company knowledge of the actual cost of similar 

size/type projects. 

TABLE 4-5. COST ANALYSIS SUMMARY FOR FUEL SUBSTITUTION

Control Case 

Control 

Effectiveness Annual Cost 

Existing Annual 

Emissions 

Pollutant 

Removed 

Cost 

Effectiveness 

Cost*

Impact 

(%) ($/yr) (tons/yr) (tons/yr) ($/ton) ($/ton clinker) 

Fuel Sub – PA 40% $27,022,178 11,481 4,592 $5,884 $22 

Fuel Sub – PA 50% $27,022,178 11,481 5,741 $4,707 $22 

Fuel Sub – PTE 40% $27,022,178 13,298 5,319 $5,080 $22 

Fuel Sub – PTE 50% $27,022,178 13,298 6,649 $4,064 $22 

*

Based on a maximum historical actual clinker production rate of 1,215,708 tons/year 

The significant increases in cost per ton of clinker produced from using Fuel Substitution, 

as shown in Table 4-5, would likely eliminate any profit margin currently realized by the 

plant. Thus, it would not be economically feasible to operate the plant with Fuel 

Substitution. 

Energy Impacts 

The low sulfur coal will require additional energy for grinding. The actual increase is 

difficult to estimate. 

Non Air-Quality Impacts 

None. 

Remaining Useful Life 

The remaining useful life of the kiln does not impact the annualized cost because the useful 

life is anticipated to be at least as long as the capital cost recovery period, which is 15 

years. However, the existing coal mill would need to be replaced at a significant expense. 
Holcim (US) Inc. 4-11 Trinity Consultants 

BART Analysis 

4.4.3 DRY LIME SCRUBBING

Cost of Compliance 

The increased cost of DLS includes the cost of hydrated lime as well as the injection 

system and replacing the existing ESP with a new baghouse. As the DLS injection system 

would likely be a custom application, Holcim’s engineering department has estimated that 

the DLS injection system equipment cost would be approximately $1,000,000. Holcim 

obtained a bid for retrofitting the existing ESP with a Baghouse from GE Energy. A 

detailed analysis has not yet been completed to determine if the retrofit will be capable of 

handling the additional dust loading from the DLS system. 

The quantity of hydrated lime required is calculated below on a PA and PTE basis as 

follows: 

Hydrated Lime Requirement.

PA Basis: 

The projected actual annual emission level of SO2 is 11,481 tons 

A molar ratio of 6:1, Ca(OH)2 to SO2, is required. The Ca(OH)2 required is 

calculated by multiplying by the ratio of molecular weights: 

6 x 11,481 tons SO2 x (74 ton Ca(OH)2/ 64 SO2) = 79,649 tons Ca(OH)2

The estimated purity of the hydrated lime is 96.8 percent Ca(OH)2. Consequently, 

the amount required is scaled as follows: 

79,649 tons Ca(OH)2 / 0.968 = 82,282 tons hydrated lime 

PTE Basis: 

The PTE annual emission level of SO2 is 13,298 tons 

A molar ratio of 6:1, Ca(OH)2 to SO2, is required. The Ca(OH)2 required is 

calculated by multiplying by the ratio of molecular weights: 

6 x 13,298 tons SO2 x (74 ton Ca(OH)2/ 64 SO2) = 92,255 tons Ca(OH)2

The estimated purity of the hydrated lime is 96.8 percent Ca(OH)2. Consequently, 

the amount required is scaled as follows: 

92,255 tons Ca(OH)2 / 0.968 = 95,304 tons hydrated lime 

Table 4-6 provides a summary of the cost effectiveness analysis related to DLS. The 

detailed cost analysis table is provided in Appendix A. The control cost factors were 

obtained from the EPA’s Control Cost Manual, 6th Edition. Some of the factors have been 
Holcim (US) Inc. 4-12 Trinity Consultants 

BART Analysis 

scaled, as indicated, based on the construction being a retrofit, rather than greenfield, and 

company knowledge of the actual cost of similar size/type projects. 

TABLE 4-6. COST ANALYSIS SUMMARY FOR DRY LIME SCRUBBING

Control Case 

Control 

Effectiveness Annual Cost 

Existing Annual 

Emissions 

Pollutant 

Removed 

Cost 

Effectiveness 

Cost*

Impact 

(%) ($/yr) (tons/yr) (tons/yr) ($/ton) ($/ton clinker) 

DLS – PA 20% $15,607,401 11,481 2,181 $7,155 $13 

DLS – PA 30% $15,607,401 11,481 3,272 $4,770 $13 

DLS – PTE 20% $17,638,856 13,298 2,527 $6,981 $15 

DLS – PTE 30% $17,638,856 13,298 3,790 $4,654 $15 

*

Based on a maximum historical actual clinker production rate of 1,215,708 tons/year 

The significant increases in cost per ton of clinker produced from using DLS, as shown in 

Table 4-6, would likely eliminate any profit margin currently realized by the plant. Thus, 

it would not be economically feasible to operate the plant with DLS. 

Energy Impacts 

Additional electricity is needed for the pump used to inject the lime into the kiln gas. 

Non Air-Quality Impacts 

Utilizing DLS could also increase the amount of CKD sent to the landfill. 

Remaining Useful Life 

The remaining useful life of the kiln does not impact the annualized cost because the useful 

life is anticipated to be at least as long as the capital cost recovery period, which is 15 

years. 

4.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS 

A final impact analysis was conducted to assess the visibility improvement for the existing emission 

rate when compared to the emission rate of WLS, Fuel Substitution, and DLS. The existing emission 

rates, and emission rates associated with controls, were modeled using CALPUFF. The existing 

emission rate is the same rate that was modeled for the BART applicability analysis. The SO2

emission rate associated with WLS, Fuel Substitution, and DLS is the existing emission rates less the 

average anticipated control of 87.5 percent, 45 percent, and 25 percent respectively. The emission 

rates are summarized in Table 4-7. 
Holcim (US) Inc. 4-13 Trinity Consultants 

BART Analysis 

TABLE 4-7. SUMMARY OF EMISSION RATES MODELED IN SO2 CONTROL VISIBILITY IMPACT 

ANALYSIS 

 Emission Rate Scenario Emission Rate 

 SO2 NOX PM10 

 (lb/hr) (lb/hr) (lb/hr) 

WLS – 87.5% 611 3,049 51.82 

Fuel Substitution – 45% 2,689 3,049 51.82 

DLS – 25% 3,667 3,049 51.82 

Base case – Max 24-hr avg. 4,889 3,049 51.82 

Comparisons of the existing visibility impacts and the visibility impacts based on WLS, Fuel 

Substitution, and DLS are provided in Table 4-8. The visibility improvement associated with the 

controls are also shown in Table 4-8; this value was calculated as the difference between the existing 

visibility impairment and the visibility impairment for the controlled emission rates as measured by 

the 98th percentile modeled visibility impact. 

TABLE 4-8. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT 

ANALYSIS

Mingo National 

Wildlife Refuge 

Hercules Glades 

Wilderness Area 

Upper Buffalo 

Wilderness Area 

Existing 98% Impact (Δdv) 1.01 0.81 0.61 

WLS 98% Impact (Δdv) 0.48 0.31 0.21 

WLS Improvement 98% Impact (Δdv) 0.53 0.50 0.40 

Fuel Subs. 98% Impact (Δdv) 0.70 0.58 0.37 

Fuel Subs Improvement 98% Impact (Δdv) 0.31 0.23 0.24 

DLS 98% Impact (Δdv) 0.87 0.70 0.48 

DLS Improvement 98% Impact (Δdv) 0.14 0.11 0.13 

4.6 PROPOSED BART FOR SO2

In order to determine BART for SO2, Holcim reviewed each control option’s availability, as well as 

its cost of compliance, energy impacts, and non-air quality impacts, as well as the remaining useful 

life of the kiln. Table 4-9 summarizes the cost effectiveness for the controls based on the tons of SO2

reduced and the visibility improvement in deciviews. 
Holcim (US) Inc. 4-14 Trinity Consultants 

BART Analysis 

TABLE 4-9. SUMMARY OF COST EFFECTIVENESS OF SO2 CONTROL OPTIONS

 

Existing 

Emissions 

Reduced 

Annual 

Emissions Annual Cost 

Cost**

Effectiveness 

Cost 

Impact 

Control Option* (tons/yr) (tons/yr) ($/yr) ($/ton) ($/ton clinker) 

WLS–PA–80% 11,481 8,726 $24,706,548 $2,863 $20 

Fuel Sub – PA - 40% 11,481 4,592 $27,022,178 $5,884 $22 

DLS – PA - 20% 11,481 2,181 $15,607,401 $7,155 $13 

*

The worst case scenario from a cost effectiveness perspective is provided. **Includes 97 tons of NOx generated for WLS 

 

Control Type 

WLS–PA–80% 

Base 98th 

Percentile 

Impact 

Controlled 98th

Percentile 

Impact 

98th Percentile 

Improvement 

98th

Percentile 

Improvement 

Cost 

Effectiveness 

Class I Area (DV) (DV) (DV) (%) ($/DV) 

Mingo 1.01 0.48 0.53 52.5 $46,616,128 

Hercules 0.81 0.31 0.50 61.7 $49,413,096 

Buffalo 0.61 0.21 0.40 65.6 $61,766,370 

Control Type 

Fuel Subs. 

Base 98th 

Percentile 

Impact 

Controlled 98th

Percentile 

Impact 

98th Percentile 

Improvement 

98th

Percentile 

Improvement 

Cost 

Effectiveness 

Class I Area (DV) (DV) (DV) (%) ($/DV) 

Mingo 1.01 0.70 0.31 30.7 $87,168,317 

Hercules 0.81 0.58 0.23 28.4 $117,487,732 

Buffalo 0.61 0.37 0.24 39.3 $112,592,410 

Control Type 

DLS 

Base 98th 

Percentile 

Impact 

Controlled 98th

Percentile 

Impact 

98th Percentile 

Improvement 

98th

Percentile 

Improvement 

Cost 

Effectiveness 

Class I Area (DV) (DV) (DV) (%) ($/DV) 

Mingo 1.01 0.87 0.14 13.9 $111,481,434 

Hercules 0.81 0.70 0.11 13.6 $141,885,461 

Buffalo 0.61 0.48 0.13 21.3 $120,056,929 

Based on the five step analysis outlined by EPA, this analysis demonstrates that the cost of 

compliance associated with WLS, Fuel Substitution, and DLS is extremely high on a $/ton of SO2

removed basis, and especially on a $/DV of improvement basis. A cost range of $46 million - $141 

million/DV is well beyond expectations of the BART program. Holcim has concluded that the 

current inherent scrubbing by the cement kiln process is the only feasible control and no additional 

BART control option is economically feasible. Notwithstanding, Holcim has been diligently working 

on capturing SO3 in clinker and significantly increased SO3 in the clinker in the past five years. 

Holcim continues to work on process optimization to further increase the SO3 capture in the clinker. 
Holcim (US) Inc. 5-1 Trinity Consultants 

BART Analysis 

5. NOX BART EVALUATION

In Portland cement kilns, the NOx that is generated is primarily classified into one of two categories, 

i.e., thermal NOx or fuel NOx8. Thermal NOx occurs as a result of the high-temperature oxidation of 

molecular nitrogen present in the combustion air. Fuel NOx is created by the oxidation of 

nitrogenous compounds present in the fuel. It is also possible for nitrogenous compounds to be 

present in the raw material feed and become oxidized to form additional NOx referred to as feed NOx. 

Due to the high flame temperature in the burning zone of the rotary kiln (3400o F), NOx emissions 

from the kiln tend to be mainly comprised of thermal NOx. Although NOx emissions from cement 

kilns include both nitrogen oxide (NO) and nitrogen dioxide (NO2), typically, less than 10% of the 

total NOx in the flue gas is NO2.9

The kiln is the only BART source which emits NOx, thus a NOx BART evaluation was performed 

only for the kiln. The maximum actual 24-hour kiln NOx emission rate that was modeled for the 

BART applicability determination is summarized in Table 4-1. The NOx 24-hour maximum actual 

emission rate was determined from analyzer data for November 24, 2007. 

TABLE 5-1. EXISTING ACTUAL MAXIMUM 24-HOUR NOX EMISSION RATES

NOx 24-Hour 

Emission Rate 

NOx Hourly 

Equivalent Emission 

Rate 

 ton/24-hr lb/hr 

Kiln 36.59 (73,185 lbs) 3,049 

5.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL 

TECHNOLOGIES

Step 1 of the BART determination is the identification of all available retrofit NOX control 

technologies. A list of control technologies was obtained by reviewing the U.S. EPA’s Clean Air 

Technology Center, control equipment vendor information, publicly-available air permits, 

applications, and technical literature published by the U.S. EPA and the RPOs. 

The available retrofit NOX control technologies are summarized in Table 5-2. 

 8 NOx Formation and Variability in Portland Cement Kiln Systems, Penta Engineering, December 1998. 

9 IBID. 
Holcim (US) Inc. 5-2 Trinity Consultants 

BART Analysis 

TABLE 5-2. POSSIBLE NOX CONTROL TECHNOLOGIES

Kiln Control Technologies 

Low NOx Burner 

Flue Gas Recirculation 

CKD Insufflation 

Mid-Kiln Firing of Tires 

Selective Noncatalytic Reduction 

Selective Catalytic Reduction 

5.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NOX control technologies that 

were identified in Step 1. 

5.2.1 LOW-NOX BURNER IN THE ROTARY KILN

Low NOx burners (LNBs) reduce the amount of NOx formed at the flame. The principle of 

all LNBs is the same: stepwise or staged combustion and localized exhaust gas 

recirculation (i.e. at the flame). As applied to the rotary cement kiln, the low-NOx burner 

creates primary and secondary combustion zones at the end of the main burner pipe to 

reduce the amount of NOx initially formed at the flame. In the high-temperature primary 

zone, combustion is initiated in a fuel-rich environment in the presence of a less than 

stoichiometric oxygen concentration. The oxygen-deficient condition at the primary 

combustion site minimizes thermal and fuel NOx formation and produces free radicals that 

chemically reduce some of the NOx that is being generated in the flame. 

In the secondary zone, combustion is completed in an oxygen-rich environment. The 

temperature in the secondary combustion zone is much lower than in the first; therefore, 

lower NOx formation is achieved as combustion is completed. CO that has been generated 

in the primary combustion zone as an artifact of the sub-stoichiometric combustion is fully 

oxidized in the secondary combustion zone. 

Low-NOx burners are considered to be a technically feasible option for NOX control. As 

Holcim already has a LNB, the technology will not be considered further. 

5.2.2 FLUE GAS RECIRCULATION

Flue gas recirculation involves the use of oxygen-deficient flue gas from some point in the 

process as a substitute for primary air in the main burner pipe in the rotary kiln. Flue gas 

recirculation (FGR) lowers the peak flame temperature and develops localized reducing 

conditions in the burning zone through a significant reduction of the oxygen content of the 

primary combustion “air.” The intended effect of the lower flame temperature and 

reducing conditions in the flame is to decrease both thermal and fuel NOx formation in the 

rotary kiln. 
Holcim (US) Inc. 5-3 Trinity Consultants 

BART Analysis 

While FGR is a practiced control technology in the electric utility industry, Holcim is not 

aware of any attempt to apply FGR to a cement kiln because of the unique process 

requirements of the industry, i.e., a hot flame is required to complete the chemical reactions 

that form clinker minerals from the raw materials. The process of producing clinker in a 

cement kiln requires the heating of raw materials to about 2700°F for a brief but 

appropriate time to allow the desired chemical reactions that form the clinker minerals to 

occur. A short, high-temperature flame of about 3400°F is necessary to meet this process 

requirement. The long/lazy flame that would be produced by FGR would result in the 

production of lower or unacceptable quality clinker because of the resulting undesirable 

mineralogy. Clinkering reactions must take place in an oxidizing atmosphere in the 

burning zone to generate clinker that can be used to produce acceptable cement. FGR 

would tend to produce localized or general reducing conditions that also could 

detrimentally affect clinker quality. Due to these important limitations on the application 

of FGR and the lack of a successful demonstration on a cement kiln in the United States, 

FGR is not a technically feasible control option for NOx control at this time. 

5.2.3 CEMENT KILN DUST INSUFFLATION

Cement kiln dust (CKD) is a residual byproduct that can be produced by any of the four 

basic types of cement kiln systems. CKD is most often treated as a waste even though 

there are some beneficial uses. However, as a means of recycling usable CKD to the 

cement pyroprocess, CKD sometimes is injected or insufflated into the burning zone of the 

rotary kiln in or near the main flame. The presence of these cold solids within or in close 

proximity to the flame has the effect of cooling the flame and/or the burning zone thereby 

reducing the formation of thermal NOx. The insufflation process is somewhat 

counterintuitive because a basic requirement of a cement kiln is a very hot flame to heat the 

clinkering raw materials to about 2700o F in as short a time as possible. The Clarksville 

plant already uses this technology and it is already included in the baseline. Therefore, this 

option is removed from consideration for BART. 

5.2.4 MID-KILN FIRING OF SOLID FUEL WITH MIXING AIR FAN

Secondary combustion is defined as follows: a portion of the fuel is fired in a location 

other than the burning zone. This reduces thermal NOx generation because the temperature 

in the secondary combustion zone is less than 2100 °F. Mid-kiln firing (MKF) of solid 

fuels is an example of secondary combustion and includes fuels such as used tires, oil filter 

fluff, plastics, spent activated carbon and carbon black, asphalt shingles, diaper 

manufacturing waste, and other combustible solids. MKF improves clinker process energy 

efficiency, allows for greater operational flexibility with respect to fuel types, and is 

currently listed as a NOx control technology in 10 CSR 10-6.380 Control of NOx 

Emissions from Portland Cement Kilns. 

An example of a MKF system is the Cadence feed form MKF technology which was first 

introduced in 1989. It is comprised of three primary components: (1) a staging arm or 

“feed fork,” that picks up the fuel modules and positions them for entry into the kiln, (2) 

two pivoting doors that open to allow the fuel to drop into the kiln, and (3) a drop tube that 
Holcim (US) Inc. 5-4 Trinity Consultants 

BART Analysis 

extends through the side wall of the kiln. In addition to these basic components, feed fork 

technology also requires a delivery system which positions the fuel models so they can be 

picked up by the feed fork and a mechanism for opening the doors so the fuel can enter the 

kiln. Due to rotation of the kiln, fuel can only be injected once per revolution from the top, 

as shown in Figure 5-1. 

FIGURE 5-1. MID-KILN FIRING SCHEMATIC10

High-pressure air, in the range of a 2-10 percent replacement of the primary combustion 

air, could be injected through the shell of the rotary kiln and into the calcining zone to 

where a mixing air fan mixes the air with the gas and fuel within the rotary kiln for more 

complete combustion of the solid fuel. 

By adding fuel mid-kiln, MKF changes both the flame temperature and flame length. 

These changes should reduce thermal NOX formation by burning part of the fuel at a lower 

temperature and by creating reducing conditions at the mid-kiln fuel injection point which 

may destroy some of the NOX formed upstream in the kiln burning zone. 

Clarksville has the largest long kiln in the world. The kiln has a 7 meter diameter and a 

very high thermal capacity. Using whole tires to replace 10% of total fuel consumption 

will require four whole tires being fed to the mid-kiln door per kiln revolution, 12% fuel 

replacement would require 5 tires per revolution. The maximum tire feed rate per 

revolution that Holcim is aware of, on similar applications, is three tires per revolution. 

Holcim is concerned that the greater the number of tires fed per revolution, on a continuous 

basis, the greater the potential for process upsets from unstable feeding. Holcim has found 

that kilns being fed even one to three tires per revolution can have problems with stable, 

uniform feeding. In addition, if too many tires burn at the bottom of the kiln, a high local 

temperature could result which would disturb the normal operation of the kiln and 

potentially increase NOx. Further, due to the large kiln diameter, the reducing zone 

created by burning tires may only impact a small cross section of the entire cross section of 

the kiln, thus having less of an overall reduction in NOx than anticipated. 

 10 NOX Control Technologies for the Cement Industry, EC/R Incorporated, Chapel Hill, NC, USA, U.S. EPA 

Contract NO. 68-D98-025, U.S. EPA RTP, September 19, 2000. 
Holcim (US) Inc. 5-5 Trinity Consultants 

BART Analysis 

In an effort to better understand these uncertainties, Holcim hired CINAR Company, the 

expert in this field, to conduct modeling of the system and to predict NOx reduction. Their 

study predicted that a 15% NOx reduction would occur at 10% replacement (replace 10% 

of the current fuel with tires) and 27% NOx reduction for 15% replacement. 

To then determine the thermal substitution rate (TSR) of tires that the Clarksville plant is 

capable of utilizing, three additional factors must be considered: 

1. Tire availability. The local market only has sustainable resources of 10-12% TSR; 

2. Tire feeding limit: 12% TSR equates to five tires being fed per revolution. 

3. The thermal stability of operation in a large kiln. 15% TSR is predicted to be the 

maximum for short term periods, whereas 10-12% TSR is predicted to be achievable 

on a long term basis. 

Based on the lack of experience using MKF of tires on kilns the size of Clarksville, Holcim 

is relying on the computer modeling (regardless of the general uncertainty that exists with 

computer models) to estimate the NOx reduction. Holcim anticipates that MKF of tires 

may achieve up to 20% percent NOx reduction at a TSR of 12 percent on a long term basis. 

MKF is considered to be a technically feasible option for NOx control. Further, Holcim 

has already received a construction permit that would allow the installation of MKF, 

whereas other technologies would require a new construction permit application process, 

the result of which is unknown. 

5.2.5 SELECTIVE NONCATALYTIC REDUCTION

In the relatively narrow temperature window of 1600 to 1995°F, ammonia (NH3) reacts 

with NOx without the need for a catalyst to form water and molecular nitrogen in 

accordance with the following simplified reactions. 

4NO + 4NH3 + O2 Æ 4N2 + 6H2O 

2NO2 + 4NH3 + O2 Æ 3N2 + 6H2O 

As applied to NOx control from cement kilns and other combustion sources, this 

technology is called selective noncatalytic reduction (SNCR). Above this temperature 

range, the NH3 is oxidized to NOx thereby increasing NOx emissions. Below this 

temperature range, the reaction rate is too slow for completion and unreacted NH3 may be 

emitted from the pyroprocess. This temperature window generally is available at some 

location within the rotary kiln. The NH3 could be delivered to the kiln shell through the 

use of anhydrous NH3, or an aqueous solution of NH3 (ammonium hydroxide) or urea. 

A concern about application of SNCR technology is the breakthrough of unreacted NH3 as 

“ammonia slip” and its subsequent reaction in the atmosphere with SO2, sulfur trioxide 

(SO3), hydrogen chloride (HCl) and/or chlorine (Cl2) to form a detached plume of sub-
Holcim (US) Inc. 5-6 Trinity Consultants 

BART Analysis 

micron particles. As NH3 or Urea injection rates are increased, to attempt to achieve 

higher levels of reduction, NH3 emission levels are increased. 

Industry Experience

Ash Grove Cement Company installed a full scale SNCR system on one of its wet kilns in 

Midlothian, Texas. Ash Grove has reported that it is achieving a 35 to 40% NOx 

reduction; however, as this application has just started, no data is available to verify this 

reduction is being achieved or on what averaging period or the long term sustainability.11 

Holcim’s wet plant in Lumbres, France utilizes SNCR. It is the earliest application of 

SNCR on a long kiln in the world and has been running for multiple years. The plant has 

found that NH3 slip increases as the urea injection rate increases especially when the molar 

ratio is more than 1.0 (i.e. the NH3 added is more than needed for the reaction). At this 

level, significant amounts of NH3 are unreacted. The plant reports achieving 20 percent 

NOx reduction at a 1.0 molar ratio of NH3/NOx and 40 percent at a molar ratio of 1.5 as 

shown in Figure 5-2. 

FIGURE 5-2. NOX REDUCTION VERSUS NH3 MOLAR RATIO OBSERVED AT 

HOLCIM LUMBRES PLANT.

However, at 20 percent NOx reduction, the NH3 slip is reported to be 10 mg/m3, while at 

40 percent reduction, the NH3 slip can be 20 – 30 mg/m3

 (a 50 percent to 100 percent 

increase). Based on experiences at many cement plants with SO2 and HCl in the exhaust 

gas, which is also the case for the Clarksville plant, a 20 mg/Nm3 NH3 increase would 

cause a severe increase in plume visibility. The Lumbres plant is also smaller than 

 11 BART Five Factor Analysis. Ash Grove Cement Company Montana City, Montana. Dated June 2007. Page 

5-9. 
Holcim (US) Inc. 5-7 Trinity Consultants 

BART Analysis 

Clarksville, having a diameter of only 3.3 meters versus Clarksville’s 7 meter diameter 

kiln. The larger diameter of Clarksville’s kiln would make distribution of the reagent 

across the kiln more difficult, and would reduce the effectiveness to an unknown degree. 

Based on the concerns with NH3 slip at high molar ratios, and the uncertainty regarding the 

level of effectiveness of the reagent in Clarksville’s large diameter kiln, Holcim anticipates 

that at a molar ratio of about 1.0, an average annual control efficiency of 20 percent could 

likely be achieved without excessive NH3 slip. However, a pilot study would need to be 

conducted to verify this. Regardless, SNCR is considered to be a technically feasible 

option for NOX control. 

5.2.6 SELECTIVE CATALYTIC REDUCTION

Selective Catalytic Reduction (SCR) is an add-on control technology for the control of 

emissions of the oxides of nitrogen (NOx) from a combustion process. SCR has been 

successfully employed in the electric power industry. The basic SCR system consists of a 

system of catalyst grids placed in series with each other within a vessel that is located in a 

part of the process where the normal flue gas temperature is in the required range. An 

ammonia-containing reagent is injected at a controlled rate upstream of the catalyst grids 

that are designed to ensure relatively even flue gas distribution within the grids, to provide 

good mixing of the reagent and flue gas, and to result in minimum ammonia (NH3) slip.12 

The NH3 reacts with NOx compounds (i.e., NO and NO2) on the surface of the catalyst in 

equal molar amounts (i.e., one molecule of NH3 reacts with one molecule of NOx). 

Common reagents include aqueous NH3, anhydrous NH3 and urea [(NH2)2CO]. In the 

presence of the catalyst, the injected ammonia is converted by OH-

 radicals to ammonia 

radicals (i.e., NH2

-

), which, in turn, react with NOx to form N2 and H2O. The SCR catalyst 

enables the necessary reactions to occur at lower temperatures than those required for 

Selective Non-Catalytic Reduction (SNCR). While catalysts can be effective over a larger 

range of temperatures, the optimal temperature range for SCR is 570 - 750o F. 

The catalyst system used in SCR applications usually consists of (1) a porous honeycomb 

of a ceramic substrate onto which catalyst has been attached to the surface of the ceramic 

material, or (2) a flat or corrugated plate onto which catalytic material has been deposited 

on the surface. A porous metal oxide with a high surface area-to-volume ratio acts as a 

catalyst base. On this base, typically titanium dioxide (TiO2), one or more metal oxide 

catalysts are deposited in various concentrations. In SCR applications, the active catalyst 

material typically consists of vanadium pentoxide (V2O5), tungsten trioxide (WO3), and 

molybdenum trioxide (MoO3) in various combinations. The composition, also known as 

the catalyst formulation, is tailored by the catalyst vendor to best suit a particular SCR 

application. Catalyst deactivation through poisoning, fouling, masking, sintering and 

erosion are common problems for SCR catalysts that, without careful process design and 

operation, could be exacerbated. If not fouled by sulfur dioxide (SO2), the catalysts used 

in SCR have a propensity to oxidize sulfur dioxide (SO2) in the flue gas to sulfur trioxide 

(SO3), a more undesirable pollutant. 

 12 Slip refers to the quantity of unreacted reagent that exits the SCR reactor. 
Holcim (US) Inc. 5-8 Trinity Consultants 

BART Analysis 

Because the reaction rate of NH3 and NOx is temperature dependent, the temperature of the 

flue gas stream to be controlled is the most important consideration in applying SCR 

technology to any combustion source. The optimum temperature range for SCR 

application is about 300o C (570o F) to 450o C (840o F). This range of normal process 

temperature would occur within the kiln of a long wet kiln, rather than in the exhaust gas 

between the wet kiln and the PMCD inlet. 

SCR has not been applied to any wet cement plant in the world and is not 

considered an available technology. 

As explained in more detail below, a technology is considered "available" if it can be 

obtained by the applicant through commercial channels or is otherwise available within the 

common sense meaning of the term. An available technology is “applicable” if it can 

reasonably be installed and operated on the source type under consideration. A technology 

that is available and applicable is technically feasible. Availability in this context is further 

explained using the following process commonly used for bringing a control technology 

concept to reality as a commercial product: concept stage; research and patenting; bench 

scale or laboratory testing; pilot scale testing; licensing and commercial demonstration; and 

Commercial sales. 

A control technique is considered available, within the context presented above, if it has 

reached the licensing and commercial sales stage of development. A source would not be 

required to experience extended time delays or resource penalties to allow research to be 

conducted on a new technique. Neither is it expected that an applicant would be required 

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

dissimilar source type. Consequently, technologies in the pilot scale testing stages of 

development would not be considered available. An exception would be if the technology 

were proposed and permitted under the qualifications of an innovative control device 

consistent with the provisions of 40 CFR 52.21(v) or, where appropriate, the applicable 

SIP [in which case it would be considered available]. 

Therefore, SCR is eliminated from further consideration as BART for NOx control at the 

Clarksville plant. 

. 

5.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Table 5-3 presents potential NOx technically feasible control technologies by 

effectiveness. 
Holcim (US) Inc. 5-9 Trinity Consultants 

BART Analysis 

TABLE 5-3. RANKING OF TECHNICALLY FEASIBLE KILN NOX CONTROL TECHNOLOGIES BY 

EFFECTIVENESS

Control Technology 

Effectiveness 

NOX Emissions Level 

(%) 

MKF 20% 

SNCR 20% 

LNB, CKD Insufflation, and Synfuel Already utilized at Clarksville 

5.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS 

Step four for the BART analysis procedure is the impact analysis. The BART determination 

guidelines list four factors to be considered in the impact analysis: 

• Cost of compliance 

• Energy impacts 

• Non-air quality impacts; and 

• The remaining useful life of the source 

5.4.1 MKF 

Cost of Compliance 

Holcim anticipates that MKF and SNCR have relatively the same level of effectiveness. 

Because SNCR would require a pilot study to prove or verify the effectiveness of NOx 

reduction, Holcim is accepting the use of MKF as BART. As Holcim is accepting the most 

stringent control option available as BART, the cost of compliance is not required to be 

evaluated. 

Energy Impacts and Non Air-Quality Impacts 

There are no known adverse energy or non-air impacts from MKF. MKF of tires has the 

benefit of eliminating tires from landfills and illegal dumping. It also reduces CO2

emissions (a Green House Gas) and reduces fossil fuel use. 

Remaining Useful Life 

The remaining useful life of the kiln does not impact the annualized costs of MKF because 

the useful life is anticipated to be at least as long as the capital cost recovery period, which 

would be 15 years. 

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS 

The final impact analysis was conducted to assess the visibility improvement for existing emission 

rates when compared to the emission rate with MKF. The existing emission rates and emission rates 

associated with MKF were modeled using CALPUFF. The existing emission rates are the same rates 

that were modeled for the BART applicability analysis. The NOx emission rate associated with MKF 
Holcim (US) Inc. 5-10 Trinity Consultants 

BART Analysis 

was the existing emission rate less an average reduction of 20 percent. The emission rate is 

summarized in Table 5-4. 

TABLE 5-4. SUMMARY OF EMISSION RATES MODELED IN NOX CONTROL VISIBILITY

IMPACT ANALYSIS

Emission Rate 

 SO2 NOX PM10

 Emission Rate Scenario (lb/hr) (lb/hr) (lb/hr) 

MKF, 4,889 2,440 51.82 

Base case – High 24 hr average 4,889 3,049 51.82 

Comparisons of the 98th percentile existing visibility impacts and the visibility impacts based on MKF 

are provided in Table 5-5. The visibility improvement associated with MKF are also shown in Table 

5-5; this was calculated as the difference between the existing visibility impairment and the visibility 

impairment for the remaining control options as measured by the 98th percentile modeled visibility 

impact. 

TABLE 5-5. NOX CONTROL VISIBILITY IMPACT ANALYSIS

 

Existing 

98% Impact 

(Δdv) 

MKF 

98% Impact 

(Δdv) Improvement 

Mingo 1.01 0.92 8.9%

Hercules 0.81 0.72 11.1% 

Upper Buffalo 0.61 0.60 1.6% 

As seen in Tables 5-5, the MKF option results in a visibility improvement of up to 11.1 percent in the 

Hercules Glades Class I area. 

5.6 PROPOSED BART FOR NOX 

Based on the five step analysis outlined by EPA, MKF was identified as the highest ranking feasible 

add-on control technology. Energy and environmental impacts were assessed for this technology and 

the visibility improvements were evaluated against existing conditions. Consistent with EPA 

guidance, economic impacts were not assessed as Holcim was willing to utilize the highest ranked 

control technology. The visibility impact analysis demonstrates that the utilization of MKF to 

achieve a 2,440 lb/hr NOx emission rate results in up to an 11.1 percent visibility improvement. 

Neither non-air quality nor energy impacts associated with this control technology eliminate it in 

favor of retaining the existing rates as BART. 

Holcim has determined that BART for the facility is MKF. Based on the lack of site specific, or 

significant industry data, for the use of this technology on wet cement kilns, it is possible that Holcim 

will further evaluate the MKF system and determine that MKF results in limited or no additional 

benefit. In the future, an alternative technology or methodology may become feasible and could be 

implemented as needed. Holcim will continue to utilize the NOx controls that are already in place, 

including LNB, insufflation, and the use of alternative fuels as available.
Appendix A. Control Cost Tables 
Table A-1. Wet Limestone Scrubber Control Cost Analysis Based on Projected Actual Emissions and 80% Control.

Direct Costs

Purchased Equipment Costs

Wet Scrubber Unit including Limestone Prep System $10,524,352

Instrumentation (15% of EC) $1,578,653

Sales Tax (5% of EC) $526,218

Freight (5% of EC) $526,218

Subtotal, Purchased Equipment Cost (PEC) $13,155,441

Direct Installation Costs

Foundation (10% of PEC) $1,315,544

Supports (10% of PEC) $1,315,544

Handling and Erection (50% of PEC) $6,577,720

Electrical (10% of PEC) $1,315,544

Piping (30% of PEC) $3,946,632

Extending gas line 1/2 mile to plant $500,000

Insulation for Ductwork (5% of PEC) $657,772

Painting (1% of PEC) $131,554

Subtotal, Direct Installation Cost $15,760,311

Site Preparation N/A

Buildings N/A

Total Direct Cost $28,915,752

Indirect Costs

Engineering (10% of PEC) $1,315,544

Construction and Field Expense (15% of PEC) $1,973,316

Contractor Fees (10% of PEC) $1,315,544

Start-up (1% of PEC) $131,554

Performance Test (1% of PEC) $131,554

Contingencies (5% of PEC) $657,772

Total Indirect Cost $5,525,285

Total Capital Investment (TCI) $34,441,037

Direct Annual Costs

Hours per Year (365 days per year, 24 hours per day), 90% Uptime 7,884

Operating Labor

Operator (8 men/yr, 2,080 hrs/yr, $64.50/hr) $1,073,280

Supervisor (15% of operator) $160,992

Subtotal, Operating Labor $1,234,272

Maintenance

Labor (6 men/yr, 2,080 hrs/yr, $64.50/hr) $804,960

Material (5% of Total Direct Cost) 1,445,788 $ 

Subtotal, Maintenance $2,250,748

Utilities

Electricity

Pump (kW) 2,342

Cost ($/kW-hr) $0.0410

Subtotal, Electricity $757,054

Limestone for slurry 

Amount Required (ton/yr) 13,961 

Cost ($/ton) $3.00

Subtotal, Lime $41,883

Water

Amount Required (gpm) 122.0

Cost ($/1000 gallons) $1.00

Subtotal, Water $64,128

Sludge Disposal

Amount Generated (tpy) 57,943 

Disposal Fee ($/ton) $36.00

Monthly Rent for Trailer @ $120/month $1,440

Cost for Box Transportation @ $220/load (assume 17 tons/trailer) $749,853

Subtotal, Sludge $2,837,247

Subtotal, Utilities $3,700,312

Natural Gas Reheat (assuming a 210 deg F temp drop and reheat)

Gas Required (MMCF/yr) 1,020,986

Cost ($/MMBTU) $10.06

Subtotal, Natural Gas $10,271,123

Total Direct Annual Costs $17,456,454

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $2,091,012

Administrative (2% TCI) $688,821

Property Tax (1% TCI) $344,410

Insurance (1% TCI) $344,410

Capital Recovery (15 year life, 7 percent interest) $3,781,441

Total Indirect Annual Cost $7,250,094

Conclusion

Total Annualized Cost $24,706,548

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 80%, 95% uptime 8,726

Pollutant Generated - NOx tons/yr 97

Net Pollutant Removed - tons/yr 8,629

Cost Per Ton of Pollutant Removed $2,863
Table A-2. Wet Limestone Scrubber Control Cost Analysis Based on Projected Actual Emissions and 95% Control.

Direct Costs

Purchased Equipment Costs

Wet Scrubber Unit including Limestone Prep System $10,524,352

Instrumentation (15% of EC) $1,578,653

Sales Tax (5% of EC) $526,218

Freight (5% of EC) $526,218

Subtotal, Purchased Equipment Cost (PEC) $13,155,441

Direct Installation Costs

Foundation (10% of PEC) $1,315,544

Supports (10% of PEC) $1,315,544

Handling and Erection (50% of PEC) $6,577,720

Electrical (10% of PEC) $1,315,544

Piping (30% of PEC) $3,946,632

Extending gas line 1/2 mile to plant $500,000

Insulation for Ductwork (5% of PEC) $657,772

Painting (1% of PEC) $131,554

Subtotal, Direct Installation Cost $15,760,311

Site Preparation N/A

Buildings N/A

Total Direct Cost $28,915,752

Indirect Costs

Engineering (10% of PEC) $1,315,544

Construction and Field Expense (15% of PEC) $1,973,316

Contractor Fees (10% of PEC) $1,315,544

Start-up (1% of PEC) $131,554

Performance Test (1% of PEC) $131,554

Contingencies (5% of PEC) $657,772

Total Indirect Cost $5,525,285

Total Capital Investment (TCI) $34,441,037

Direct Annual Costs

Hours per Year (365 days per year, 24 hours per day), 90% Uptime 7,884

Operating Labor

Operator (8 men/yr, 2,080 hrs/yr, $64.50/hr) $1,073,280

Supervisor (15% of operator) $160,992

Subtotal, Operating Labor $1,234,272

Maintenance

Labor (6 men/yr, 2,080 hrs/yr, $64.50/hr) $804,960

Material (5% of Total Direct Cost) 1,445,788 $ 

Subtotal, Maintenance $2,250,748

Utilities

Electricity

Pump (kW) 2,342

Cost ($/kW-hr) $0.0410

Subtotal, Electricity $757,054

Limestone for slurry 

Amount Required (ton/yr) 16,579 

Cost ($/ton) $3.00

Subtotal, Lime $49,736

Water

Amount Required (gpm) 122.0

Cost ($/1000 gallons) $1.00

Subtotal, Water $64,128

Sludge Disposal

Amount Generated (tpy) 68,808 

Disposal Fee ($/ton) $36.00

Monthly Rent for Trailer @ $120/month $1,440

Cost for Box Transportation @ $220/load (assume 17 tons/trailer) $890,450

Subtotal, Sludge $3,368,961

Subtotal, Utilities $4,239,878

Natural Gas Reheat (assuming a 210 deg F temp drop and reheat)

Gas Required (MMCF/yr) 1,020,986

Cost ($/MMBTU) $10.06

Subtotal, Natural Gas $10,271,123

Total Direct Annual Costs $17,996,021

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $2,091,012

Administrative (2% TCI) $688,821

Property Tax (1% TCI) $344,410

Insurance (1% TCI) $344,410

Capital Recovery (15 year life, 7 percent interest) $3,781,441

Total Indirect Annual Cost $7,250,094

Conclusion

Total Annualized Cost $25,246,115

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 95%, 95% uptime 10,362

Pollutant Generated - NOx tons/yr 97

Net Pollutant Removed - tons/yr 10,265

Cost Per Ton of Pollutant Removed $2,460
Table A-3. Wet Limestone Scrubber Control Cost Analysis Based on PTE and 80% Control.

Direct Costs

Purchased Equipment Costs

Wet Scrubber Unit including Limestone Prep System $10,524,352

Instrumentation (15% of EC) $1,578,653

Sales Tax (5% of EC) $526,218

Freight (5% of EC) $526,218

Subtotal, Purchased Equipment Cost (PEC) $13,155,441

Direct Installation Costs

Foundation (10% of PEC) $1,315,544

Supports (10% of PEC) $1,315,544

Handling and Erection (50% of PEC) $6,577,720

Electrical (10% of PEC) $1,315,544

Piping (30% of PEC) $3,946,632

Extending gas line 1/2 mile to plant $500,000

Insulation for Ductwork (5% of PEC) $657,772

Painting (1% of PEC) $131,554

Subtotal, Direct Installation Cost $15,760,311

Site Preparation N/A

Buildings N/A

Total Direct Cost $28,915,752

Indirect Costs

Engineering (10% of PEC) $1,315,544

Construction and Field Expense (15% of PEC) $1,973,316

Contractor Fees (10% of PEC) $1,315,544

Start-up (1% of PEC) $131,554

Performance Test (1% of PEC) $131,554

Contingencies (5% of PEC) $657,772

Total Indirect Cost $5,525,285

Total Capital Investment (TCI) $34,441,037

Direct Annual Costs

Hours per Year (365 days per year, 24 hours per day), 90% Uptime 7,884

Operating Labor

Operator (8 men/yr, 2,080 hrs/yr, $64.50/hr) $1,073,280

Supervisor (15% of operator) $160,992

Subtotal, Operating Labor $1,234,272

Maintenance

Labor (6 men/yr, 2,080 hrs/yr, $64.50/hr) $804,960

Material (5% of Total Direct Cost) 1,445,788 $ 

Subtotal, Maintenance $2,250,748

Utilities

Electricity

Pump (kW) 2,342

Cost ($/kW-hr) $0.0410

Subtotal, Electricity $757,054

Limestone for slurry 

Amount Required (ton/yr) 16,170 

Cost ($/ton) $3.00

Subtotal, Lime $48,511

Water

Amount Required (gpm) 122.0

Cost ($/1000 gallons) $1.00

Subtotal, Water $64,128

Sludge Disposal

Amount Generated (tpy) 67,113 

Disposal Fee ($/ton) $36.00

Monthly Rent for Trailer @ $120/month $1,440

Cost for Box Transportation @ $220/load (assume 17 tons/trailer) $868,526

Subtotal, Sludge $3,286,046

Subtotal, Utilities $4,155,739

Natural Gas Reheat (assuming a 210 deg F temp drop and reheat)

Gas Required (MMCF/yr) 1,020,986

Cost ($/MMBTU) $10.06

Subtotal, Natural Gas $10,271,123

Total Direct Annual Costs $17,911,881

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $2,091,012

Administrative (2% TCI) $688,821

Property Tax (1% TCI) $344,410

Insurance (1% TCI) $344,410

Capital Recovery (15 year life, 7 percent interest) $3,781,441

Total Indirect Annual Cost $7,250,094

Conclusion

Total Annualized Cost $25,161,975

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) - PTE 13,298

Pollutant Removed (tons SO2/yr) - 80%, 95% uptime 10,106

Pollutant Generated - NOx tons/yr 97

Net Pollutant Removed - tons/yr 10,009

Cost Per Ton of Pollutant Removed $2,514
Table A-4. Wet Limestone Scrubber Control Cost Analysis Based on PTE and 95% Control.

Direct Costs

Purchased Equipment Costs

Wet Scrubber Unit including Limestone Prep System $10,524,352

Instrumentation (15% of EC) $1,578,653

Sales Tax (5% of EC) $526,218

Freight (5% of EC) $526,218

Subtotal, Purchased Equipment Cost (PEC) $13,155,441

Direct Installation Costs

Foundation (10% of PEC) $1,315,544

Supports (10% of PEC) $1,315,544

Handling and Erection (50% of PEC) $6,577,720

Electrical (10% of PEC) $1,315,544

Piping (30% of PEC) $3,946,632

Extending gas line 1/2 mile to plant $500,000

Insulation for Ductwork (5% of PEC) $657,772

Painting (1% of PEC) $131,554

Subtotal, Direct Installation Cost $15,760,311

Site Preparation N/A

Buildings N/A

Total Direct Cost $28,915,752

Indirect Costs

Engineering (10% of PEC) $1,315,544

Construction and Field Expense (15% of PEC) $1,973,316

Contractor Fees (10% of PEC) $1,315,544

Start-up (1% of PEC) $131,554

Performance Test (1% of PEC) $131,554

Contingencies (5% of PEC) $657,772

Total Indirect Cost $5,525,285

Total Capital Investment (TCI) $34,441,037

Direct Annual Costs

Hours per Year (365 days per year, 24 hours per day), 90% Uptime 7,884

Operating Labor

Operator (8 men/yr, 2,080 hrs/yr, $64.50/hr) $1,073,280

Supervisor (15% of operator) $160,992

Subtotal, Operating Labor $1,234,272

Maintenance

Labor (6 men/yr, 2,080 hrs/yr, $64.50/hr) $804,960

Material (5% of Total Direct Cost) 1,445,788 $ 

Subtotal, Maintenance $2,250,748

Utilities

Electricity

Pump (kW) 2,342

Cost ($/kW-hr) $0.0410

Subtotal, Electricity $757,054

Limestone for slurry 

Amount Required (ton/yr) 19,202 

Cost ($/ton) $3.00

Subtotal, Lime $57,607

Water

Amount Required (gpm) 122.0

Cost ($/1000 gallons) $1.00

Subtotal, Water $64,128

Sludge Disposal

Amount Generated (tpy) 79,697 

Disposal Fee ($/ton) $36.00

Monthly Rent for Trailer @ $120/month $1,440

Cost for Box Transportation @ $220/load (assume 17 tons/trailer) $1,031,374

Subtotal, Sludge $3,901,910

Subtotal, Utilities $4,780,698

Natural Gas Reheat (assuming a 210 deg F temp drop and reheat)

Gas Required (MMCF/yr) 1,020,986

Cost ($/MMBTU) $10.06

Subtotal, Natural Gas $10,271,123

Total Direct Annual Costs $18,536,841

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $2,091,012

Administrative (2% TCI) $688,821

Property Tax (1% TCI) $344,410

Insurance (1% TCI) $344,410

Capital Recovery (15 year life, 7 percent interest) $3,781,441

Total Indirect Annual Cost $7,250,094

Conclusion

Total Annualized Cost $25,786,935

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) - PTE 13,298

Pollutant Removed (tons SO2/yr) - 95%, 95% uptime 12,001

Pollutant Generated - NOx tons/yr 97

Net Pollutant Removed - tons/yr 11,904

Cost Per Ton of Pollutant Removed $2,166
Table A-5. Fuel Substitution Control Cost Analysis Based on Projected Actual Emissions and 40% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $3,864,000

Instrumentation (15% of EC) $579,600

Sales Tax (5% of EC) $193,200

Freight (5% of EC) $193,200

Subtotal, Purchased Equipment Cost (PEC) $4,830,000

Direct Installation Costs

Foundation (10% of PEC) $483,000

Supports (10% of PEC) $483,000

Handling and Erection (50% of PEC) $2,415,000

Electrical (10% of PEC) $483,000

Piping (30% of PEC) $1,449,000

Insulation for Ductwork (5% of PEC) $9,660

Painting (1% of PEC) $48,300

Subtotal, Direct Installation Cost $5,370,960

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,200,960

Indirect Costs

Engineering (10% of PEC) $483,000

Construction and Field Expense (15% of PEC) $724,500

Contractor Fees (10% of PEC) $483,000

Start-up (1% of PEC) $48,300

Performance Test (1% of PEC) $48,300

Contingencies (5% of PEC) $241,500

Total Indirect Cost $2,028,600

Total Capital Investment (TCI) $12,229,560

Direct Annual Costs

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage by the ratio of maximum annual clinker 

production (1,215,708 tons) to 2007 actual clinker production (1,035,283 tons)

Reduction in coke usage (metric ton/yr) 188,959 

Heat Value (Gj / Mt) 32.510 

Heat (Gj / yr) 6,143,045 

Cost ($/Gj) $1.74

Subtotal, reduction in coke cost -$10,688,898

Reduction in coal usage (metric ton/yr) 11,076 

Heat Value (Gj / Mt) 22.177 

Heat (Gj / yr) 245,627 

Cost ($/Gj) $2.41

Subtotal, reduction in coal cost -$591,962

Increase in low sulfur coal usage - Amount Required (metric ton/yr) 244,891 

Heat Value (Gj / Mt) 26.266 

Heat (Gj / yr) 6,432,296 

Cost ($/Gj) $5.67

Subtotal, increase in Low Sulfur Coal cost $36,471,116

Total Direct Annual Cost (increase) $25,190,256

Indirect Annual Costs

Administrative (2% TCI) $244,591

Property Tax (1% TCI) $122,296

Insurance (1% TCI) $122,296

Capital Recovery (15 year life, 7 percent interest) $1,342,740

Total Indirect Annual Cost $1,831,922

Conclusion

Total Annualized Cost $27,022,178

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 40% 4,592

Cost Per Ton of Pollutant Removed $5,884
Table A-6. Fuel Substitution Control Cost Analysis Based on Projected Actual Emissions and 50% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $3,864,000

Instrumentation (15% of EC) $579,600

Sales Tax (5% of EC) $193,200

Freight (5% of EC) $193,200

Subtotal, Purchased Equipment Cost (PEC) $4,830,000

Direct Installation Costs

Foundation (10% of PEC) $483,000

Supports (10% of PEC) $483,000

Handling and Erection (50% of PEC) $2,415,000

Electrical (10% of PEC) $483,000

Piping (30% of PEC) $1,449,000

Insulation for Ductwork (5% of PEC) $9,660

Painting (1% of PEC) $48,300

Subtotal, Direct Installation Cost $5,370,960

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,200,960

Indirect Costs

Engineering (10% of PEC) $483,000

Construction and Field Expense (15% of PEC) $724,500

Contractor Fees (10% of PEC) $483,000

Start-up (1% of PEC) $48,300

Performance Test (1% of PEC) $48,300

Contingencies (5% of PEC) $241,500

Total Indirect Cost $2,028,600

Total Capital Investment (TCI) $12,229,560

Direct Annual Costs

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage by the ratio of maximum annual clinker 

production (1,215,708 tons) to 2007 actual clinker production (1,035,283 tons)

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage to maximum actual production levels)

Reduction in coke usage (metric ton/yr) 188,959 

Heat Value (Gj / Mt) 32.510 

Heat (Gj / yr) 6,143,045 

Cost ($/Gj) $1.74

Subtotal, reduction in coke cost -$10,688,898

Reduction in coal usage (metric ton/yr) 11,076 

Heat Value (Gj / Mt) 22.177 

Heat (Gj / yr) 245,627 

Cost ($/Gj) $2.41

Subtotal, reduction in coal cost -$591,962

Increase in low sulfur coal usage - Amount Required (metric ton/yr) 244,891 

Heat Value (Gj / Mt) 26.266 

Heat (Gj / yr) 6,432,296 

Cost ($/Gj) $5.67

Subtotal, increase in Low Sulfur Coal cost $36,471,116

Total Direct Annual Cost (increase) $25,190,256

Indirect Annual Costs

Administrative (2% TCI) $244,591

Property Tax (1% TCI) $122,296

Insurance (1% TCI) $122,296

Capital Recovery (15 year life, 7 percent interest) $1,342,740

Total Indirect Annual Cost $1,831,922

Conclusion

Total Annualized Cost $27,022,178

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 50% 5,741

Cost Per Ton of Pollutant Removed $4,707
Table A-7. Fuel Substitution Control Cost Analysis Based on PTE and 40% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $3,864,000

Instrumentation (15% of EC) $579,600

Sales Tax (5% of EC) $193,200

Freight (5% of EC) $193,200

Subtotal, Purchased Equipment Cost (PEC) $4,830,000

Direct Installation Costs

Foundation (10% of PEC) $483,000

Supports (10% of PEC) $483,000

Handling and Erection (50% of PEC) $2,415,000

Electrical (10% of PEC) $483,000

Piping (30% of PEC) $1,449,000

Insulation for Ductwork (5% of PEC) $9,660

Painting (1% of PEC) $48,300

Subtotal, Direct Installation Cost $5,370,960

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,200,960

Indirect Costs

Engineering (10% of PEC) $483,000

Construction and Field Expense (15% of PEC) $724,500

Contractor Fees (10% of PEC) $483,000

Start-up (1% of PEC) $48,300

Performance Test (1% of PEC) $48,300

Contingencies (5% of PEC) $241,500

Total Indirect Cost $2,028,600

Total Capital Investment (TCI) $12,229,560

Direct Annual Costs

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage by the ratio of maximum annual clinker 

production (1,215,708 tons) to 2007 actual clinker production (1,035,283 tons)

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage to maximum actual production levels)

Reduction in coke usage (metric ton/yr) 188,959 

Heat Value (Gj / Mt) 32.510 

Heat (Gj / yr) 6,143,045 

Cost ($/Gj) $1.74

Subtotal, reduction in coke cost -$10,688,898

Reduction in coal usage (metric ton/yr) 11,076 

Heat Value (Gj / Mt) 22.177 

Heat (Gj / yr) 245,627 

Cost ($/Gj) $2.41

Subtotal, reduction in coal cost -$591,962

Increase in low sulfur coal usage - Amount Required (metric ton/yr) 244,891 

Heat Value (Gj / Mt) 26.266 

Heat (Gj / yr) 6,432,296 

Cost ($/Gj) $5.67

Subtotal, increase in Low Sulfur Coal cost $36,471,116

Total Direct Annual Cost (increase) $25,190,256

Indirect Annual Costs

Administrative (2% TCI) $244,591

Property Tax (1% TCI) $122,296

Insurance (1% TCI) $122,296

Capital Recovery (15 year life, 7 percent interest) $1,342,740

Total Indirect Annual Cost $1,831,922

Conclusion

Total Annualized Cost $27,022,178

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 13,298

Pollutant Removed (tons SO2/yr) - 40% 5,319

Cost Per Ton of Pollutant Removed $5,080
Table A-8. Fuel Substitution Control Cost Analysis Based on PTE and 50% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $3,864,000

Instrumentation (15% of EC) $579,600

Sales Tax (5% of EC) $193,200

Freight (5% of EC) $193,200

Subtotal, Purchased Equipment Cost (PEC) $4,830,000

Direct Installation Costs

Foundation (10% of PEC) $483,000

Supports (10% of PEC) $483,000

Handling and Erection (50% of PEC) $2,415,000

Electrical (10% of PEC) $483,000

Piping (30% of PEC) $1,449,000

Insulation for Ductwork (5% of PEC) $9,660

Painting (1% of PEC) $48,300

Subtotal, Direct Installation Cost $5,370,960

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,200,960

Indirect Costs

Engineering (10% of PEC) $483,000

Construction and Field Expense (15% of PEC) $724,500

Contractor Fees (10% of PEC) $483,000

Start-up (1% of PEC) $48,300

Performance Test (1% of PEC) $48,300

Contingencies (5% of PEC) $241,500

Total Indirect Cost $2,028,600

Total Capital Investment (TCI) $12,229,560

Direct Annual Costs

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage by the ratio of maximum annual clinker 

production (1,215,708 tons) to 2007 actual clinker production (1,035,283 tons)

Increased Fuel Cost (calculated by scaling 2007 annual average fuel usage to maximum actual production levels)

Reduction in coke usage (metric ton/yr) 188,959 

Heat Value (Gj / Mt) 32.510 

Heat (Gj / yr) 6,143,045 

Cost ($/Gj) $1.74

Subtotal, reduction in coke cost -$10,688,898

Reduction in coal usage (metric ton/yr) 11,076 

Heat Value (Gj / Mt) 22.177 

Heat (Gj / yr) 245,627 

Cost ($/Gj) $2.41

Subtotal, reduction in coal cost -$591,962

Increase in low sulfur coal usage - Amount Required (metric ton/yr) 244,891 

Heat Value (Gj / Mt) 26.266 

Heat (Gj / yr) 6,432,296 

Cost ($/Gj) $5.67

Subtotal, increase in Low Sulfur Coal cost $36,471,116

Total Direct Annual Cost (increase) $25,190,256

Indirect Annual Costs

Administrative (2% TCI) $244,591

Property Tax (1% TCI) $122,296

Insurance (1% TCI) $122,296

Capital Recovery (15 year life, 7 percent interest) $1,342,740

Total Indirect Annual Cost $1,831,922

Conclusion

Total Annualized Cost $27,022,178

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 13,298

Pollutant Removed (tons SO2/yr) - 50% 6,649

Cost Per Ton of Pollutant Removed $4,064
Table A-9. Dry Lime Scrubbing - Control Cost Analysis Based on Projected Actual Emissions and 20% Control.

Direct Costs

Purchased Equipment Costs

Dry Lime Injection System $1,000,000

Retrofit ESPs with Baghouse $3,000,000

 Total Equipment Cost $4,000,000

Instrumentation (15% of EC) $600,000

Sales Tax (5% of EC) $200,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $5,000,000

Direct Installation Costs

Foundation (10% of PEC) $500,000

Supports (10% of PEC) $500,000

Handling and Erection (50% of PEC) $2,500,000

Electrical (10% of PEC) $500,000

Piping (30% of PEC) $1,500,000

Insulation for Ductwork (5% of PEC) $10,000

Painting (1% of PEC) $50,000

Subtotal, Direct Installation Cost $5,560,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,560,000

Indirect Costs

Engineering (10% of PEC) $500,000

Construction and Field Expense (15% of PEC) $750,000

Contractor Fees (10% of PEC) $500,000

Start-up (1% of PEC) $50,000

Performance Test (1% of PEC) $50,000

Contingencies (5% of PEC) $250,000

Total Indirect Cost $2,100,000

Total Capital Investment (TCI) $12,660,000

Direct Annual Costs

Operating Labor

Operator (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Supervisor (15% of operator) $1,314

Subtotal, Operating Labor $10,074

Maintenance

Labor (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Material (5% of Total Direct Cost). Increased to account for high rate of 

damaged bags that is expected. 528,000 $ 

Subtotal, Maintenance $536,760

Lime

Hydrated lime/Sulfur molar ratio, min. Ca/S 6.0

MW of Ca(OH)2 74

MW of SO2 64

Purity of the Comercial lime % 96.8

Lime Required - Short Tons 82282

Cost ($/short ton) 156.00 $ 

Subtotal, Lime $12,836,066

Total Direct Annual Costs $13,382,900

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $328,100

Administrative (2% TCI) $253,200

Property Tax (1% TCI) $126,600

Insurance (1% TCI) $126,600

Capital Recovery (15 year life, 7 percent interest) $1,390,000

Total Indirect Annual Cost $2,224,500

Conclusion

Total Annualized Cost $15,607,401

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 20% removal, 95% uptime 2,181

Cost Per Ton of Pollutant Removed $7,155
Table A-10. Dry Lime Scrubbing - Control Cost Analysis Based on Projected Actual Emissions and 30% Control.

Direct Costs

Purchased Equipment Costs

Dry Lime Injection System $1,000,000

Retrofit ESPs with Baghouse $3,000,000

 Total Equipment Cost $4,000,000

Instrumentation (15% of EC) $600,000

Sales Tax (5% of EC) $200,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $5,000,000

Direct Installation Costs

Foundation (10% of PEC) $500,000

Supports (10% of PEC) $500,000

Handling and Erection (50% of PEC) $2,500,000

Electrical (10% of PEC) $500,000

Piping (30% of PEC) $1,500,000

Insulation for Ductwork (5% of PEC) $10,000

Painting (1% of PEC) $50,000

Subtotal, Direct Installation Cost $5,560,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,560,000

Indirect Costs

Engineering (10% of PEC) $500,000

Construction and Field Expense (15% of PEC) $750,000

Contractor Fees (10% of PEC) $500,000

Start-up (1% of PEC) $50,000

Performance Test (1% of PEC) $50,000

Contingencies (5% of PEC) $250,000

Total Indirect Cost $2,100,000

Total Capital Investment (TCI) $12,660,000

Direct Annual Costs

Operating Labor

Operator (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Supervisor (15% of operator) $1,314

Subtotal, Operating Labor $10,074

Maintenance

Labor (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Material (5% of Total Direct Cost). Increased to account for high rate of 

damaged bags that is expected. 528,000 $ 

Subtotal, Maintenance $536,760

Lime

Hydrated lime/Sulfur molar ratio, min. Ca/S 6.0

MW of Ca(OH)2 74

MW of SO2 64

Purity of the Comercial lime % 96.8

Lime Required - Short Tons 82282

Cost ($/short ton) 156.00 $ 

Subtotal, Lime $12,836,066

Total Direct Annual Costs $13,382,900

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $328,100

Administrative (2% TCI) $253,200

Property Tax (1% TCI) $126,600

Insurance (1% TCI) $126,600

Capital Recovery (15 year life, 7 percent interest) $1,390,000

Total Indirect Annual Cost $2,224,500

Conclusion

Total Annualized Cost $15,607,401

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 11,481

Pollutant Removed (tons SO2/yr) - 30% removal, 95% uptime 3,272

Cost Per Ton of Pollutant Removed $4,770
Table A-11. Dry Lime Scrubbing - Control Cost Analysis Based on PTE and 20% Control.

Direct Costs

Purchased Equipment Costs

Dry Lime Injection System $1,000,000

Retrofit ESPs with Baghouse $3,000,000

 Total Equipment Cost $4,000,000

Instrumentation (15% of EC) $600,000

Sales Tax (5% of EC) $200,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $5,000,000

Direct Installation Costs

Foundation (10% of PEC) $500,000

Supports (10% of PEC) $500,000

Handling and Erection (50% of PEC) $2,500,000

Electrical (10% of PEC) $500,000

Piping (30% of PEC) $1,500,000

Insulation for Ductwork (5% of PEC) $10,000

Painting (1% of PEC) $50,000

Subtotal, Direct Installation Cost $5,560,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,560,000

Indirect Costs

Engineering (10% of PEC) $500,000

Construction and Field Expense (15% of PEC) $750,000

Contractor Fees (10% of PEC) $500,000

Start-up (1% of PEC) $50,000

Performance Test (1% of PEC) $50,000

Contingencies (5% of PEC) $250,000

Total Indirect Cost $2,100,000

Total Capital Investment (TCI) $12,660,000

Direct Annual Costs

Operating Labor

Operator (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Supervisor (15% of operator) $1,314

Subtotal, Operating Labor $10,074

Maintenance

Labor (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Material (5% of Total Direct Cost). Increased to account for high rate of 

damaged bags that is expected. 528,000 $ 

Subtotal, Maintenance $536,760

Lime

Hydrated lime/Sulfur molar ratio, min. Ca/S 6.0

MW of Ca(OH)2 74

MW of SO2 64

Purity of the Comercial lime % 96.8

Lime Required - Short Tons 95305

Cost ($/short ton) 156.00 $ 

Subtotal, Lime $14,867,521

Total Direct Annual Costs $15,414,355

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $328,100

Administrative (2% TCI) $253,200

Property Tax (1% TCI) $126,600

Insurance (1% TCI) $126,600

Capital Recovery (15 year life, 7 percent interest) $1,390,000

Total Indirect Annual Cost $2,224,500

Conclusion

Total Annualized Cost $17,638,856

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 13,298

Pollutant Removed (tons SO2/yr) - 20% removal, 95% uptime 2,527

Cost Per Ton of Pollutant Removed $6,981
Table A-12. Dry Lime Scrubbing - Control Cost Analysis Based on PTE and 30% Control.

Direct Costs

Purchased Equipment Costs

Dry Lime Injection System $1,000,000

Retrofit ESPs with Baghouse $3,000,000

 Total Equipment Cost $4,000,000

Instrumentation (15% of EC) $600,000

Sales Tax (5% of EC) $200,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $5,000,000

Direct Installation Costs

Foundation (10% of PEC) $500,000

Supports (10% of PEC) $500,000

Handling and Erection (50% of PEC) $2,500,000

Electrical (10% of PEC) $500,000

Piping (30% of PEC) $1,500,000

Insulation for Ductwork (5% of PEC) $10,000

Painting (1% of PEC) $50,000

Subtotal, Direct Installation Cost $5,560,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $10,560,000

Indirect Costs

Engineering (10% of PEC) $500,000

Construction and Field Expense (15% of PEC) $750,000

Contractor Fees (10% of PEC) $500,000

Start-up (1% of PEC) $50,000

Performance Test (1% of PEC) $50,000

Contingencies (5% of PEC) $250,000

Total Indirect Cost $2,100,000

Total Capital Investment (TCI) $12,660,000

Direct Annual Costs

Operating Labor

Operator (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Supervisor (15% of operator) $1,314

Subtotal, Operating Labor $10,074

Maintenance

Labor (0.5 hr/shift, 3 shifts/day, 365 d/yr, $16/hr) $8,760

Material (5% of Total Direct Cost). Increased to account for high rate of 

damaged bags that is expected. 528,000 $ 

Subtotal, Maintenance $536,760

Lime

Hydrated lime/Sulfur molar ratio, min. Ca/S 6.0

MW of Ca(OH)2 74

MW of SO2 64

Purity of the Comercial lime % 96.8

Lime Required - Short Tons 95305

Cost ($/short ton) 156.00 $ 

Subtotal, Lime $14,867,521

Total Direct Annual Costs $15,414,355

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $328,100

Administrative (2% TCI) $253,200

Property Tax (1% TCI) $126,600

Insurance (1% TCI) $126,600

Capital Recovery (15 year life, 7 percent interest) $1,390,000

Total Indirect Annual Cost $2,224,500

Conclusion

Total Annualized Cost $17,638,856

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 13,298

Pollutant Removed (tons SO2/yr) - 30% removal, 95% uptime 3,790

Cost Per Ton of Pollutant Removed $4,654