Appendix P 

Holcim-Clarksville BART Analysis 

July 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 

July 24, 2008 

Project 081701.0004 
Holcim (US) Inc. i Trinity Consultants 

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 .......................................4-6

4.2.3 DRY LIME INJECTION/DRY LIME SCRUBBING ....................................................4-6

4.2.4 WET LIME SCRUBBING .......................................................................................4-8

4.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY EFFECTIVENESS .. 4-8 

4.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS..................................... 4-9 

4.4.1 WET LIME SCRUBBING .......................................................................................4-9

4.4.2 FUEL SUBSTITUTION .........................................................................................4-12

4.4.3 DRY LIME SCRUBBING......................................................................................4-14

4.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS .................... 4-15 

4.6 PROPOSED BART FOR SO2 ................................................................................... 4-17 

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...................................................................5-8

5.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS.. 5-9 

5.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................. 5-10 

5.4.1 MKF..................................................................................................................5-10

5.4.2 SNCR................................................................................................................5-11

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ................... 5-11 

5.6 PROPOSED BART FOR NOX.................................................................................. 5-12 

6. BART SUMMARY ................................................................................................ 6-1
Holcim (US) Inc. ii Trinity Consultants 

BART Analysis 

APPENDIX A. COAL COMPOSITION DATA..................................................................................

APPENDIX B. REVIEW OF THE POTENTIAL FOR PLUME OPACITY EXCEEDANCES 

RESULTING FROM THE USE OF A WET SCRUBBER .....................................................................

APPENDIX C. SELECTIVE MINING – QUARRY SCHEDULING OPTIMIZATION DISCUSSION ......

APPENDIX D. BART CONTROL COST TABLES..........................................................................
Holcim (US) Inc. iii Trinity Consultants 

BART Analysis 

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. CHARACTERISTICS OF PRB COAL VS. REGULAR BITUMINOUS COAL.............................4-3

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

EFFECTIVENESS ......................................................................................................................4-9

TABLE 4-5. COST ANALYSIS SUMMARY FOR WET LIME SCRUBBING ..............................................4-11

TABLE 4-6. COST ANALYSIS SUMMARY FOR FUEL SUBSTITUTION..................................................4-13

TABLE 4-7. COST ANALYSIS SUMMARY FOR DRY LIME SCRUBBING ..............................................4-15

TABLE 4-8. SUMMARY OF EMISSION RATES MODELED IN SO2 CONTROL VISIBILITY IMPACT 

ANALYSIS .............................................................................................................................4-16

TABLE 4-9. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS4-16

TABLE 4-10. SUMMARY OF COST EFFECTIVENESS OF SO2 CONTROL OPTIONS...............................4-18

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

TABLE 5-4. COST ANALYSIS SUMMARY FOR MKF ..........................................................................5-10

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

ANALYSIS .............................................................................................................................5-11
Holcim (US) Inc. iv Trinity Consultants 

BART Analysis 

TABLE 5-6. NOX CONTROL VISIBILITY IMPACT ANALYSIS...............................................................5-12

TABLE 6-1. VISIBILITY IMPAIRMENT IMPROVEMENT..........................................................................6-1
Holcim (US) Inc. 1-1 Trinity Consultants 

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 or equivalent technologies that will 

achieve a 20 percent reduction in the maximum daily NOX emission rate of 73,185 lbs that 

was used for visibility impact modeling. 

• SO2 – Holcim proposes that BART for the Holcim Clarksville Kiln is fuel substitution or 

equivalent technologies that will achieve a 23 percent reduction in the maximum daily SO2

emission rate of 117,345 lbs that was used for visibility impact modeling. 

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 
Holcim (US) Inc. 1-2 Trinity Consultants 

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) 0.79 0.64 0.48 

Improvement 98% Impact (Δdv) 22% 21% 22% 
Holcim (US) Inc. 2-1 Trinity Consultants 

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 
Holcim (US) Inc. 2-2 Trinity Consultants 

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. 
Holcim (US) Inc. 3-1 Trinity Consultants 

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. 
Holcim (US) Inc. 3-2 Trinity Consultants 

BART Analysis 

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. 
Holcim (US) Inc. 4-1 Trinity Consultants 

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. 
Holcim (US) Inc. 4-2 Trinity Consultants 

BART Analysis 

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. Oil is typically used during preheat of the kiln after a 

maintenance outage. Coal is also typically used during the kiln startup after an extended 

shutdown. Coal offers better flame control and appropriate heat distribution during heatup 

and ramp up of production. The main source of solid fuel for the kiln is petroleum coke. 

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. Holcim contacted fuel suppliers and found a 

low sulfur Colorado (CO) coal, 0.7 % sulfur, and a regionally available 3.0% sulfur coal 

that could be used in lieu of the current coal/coke, which would result in a lower overall 

fuel sulfur content. A number of coal sources were rejected for high chlorine content. For 

example, a 1.0 percent sulfur source was found but the chlorine content was 1.3 percent 

(the mine has recently shut down as well), another mine had coal with sulfur in the 1.0 

percent and 2.5 percent range, but with chlorine contents in the 0.3 percent range. Further, 

a 2.8 percent sulfur coal was identified, but it also had too high of a chlorine content, 0.12 

percent, to be usable. The 3.0 percent sulfur coal is reported as having a chlorine content 

of 0.05 percent which is preferable (Note that the 2007 average chlorine content in the coke 

was 0.08 percent. A summary of the coal composition data obtained is provided in 

Appendix A. In addition, the plant is subject to chlorine input limitations from 

HWCMACT. Chlorine contents higher than current levels would very likely cause visible 

plumes/opacity issues as further described in Appendix B. 

Powder River Basin (PRB) coal, which can have a sulfur content in the range of 0.35 

percent, was not considered a feasible alternative fuel due to a number of issues. These 

include difficult physical characteristics, a higher cost of transportation verses the CO coal, 

the lower heat content relative to the CO coal, and others. The high moisture content and 

short auto-ignition time lead to an increased risk of spontaneous combustion relative to 

other coal sources that is further exacerbated by the fact that the PRB coal would need to 

be delivered via barge. The use of PRB coal could also require the replacement of current 

coal handling equipment to meet the Class II Division 2, Group F, National Electrical Code 

(NEC). Further , the lower energy content of PRB coal would require increased volumetric 

throughput verses the CO coal. Table 4-3 provides a summary of the characteristics of 

PRB coal verses regular bituminous coal. 
Holcim (US) Inc. 4-3 Trinity Consultants 

BART Analysis 

TABLE 4-3. CHARACTERISTICS OF PRB COAL VS. REGULAR BITUMINOUS COAL

 PRB Coal Bituminous Coal 

Moisture 20 – 30% 6 – 12% 

Ash 4 - 6% 6 – 18% 

Volatiles 30 – 32% 33 – 43% 

Fixed Carbon 34 – 38% 45 – 60% 

LHV (Btu/lb) 8,000 – 9,000 11,000 – 14,000 

Explosibility Index 208 bar.m/s < 180 bar.m/s 

Maximum pressure developed during 

an explosion 115 psi < 100 psi 

Minimum explosive concentration 20 g/m3 60 g/m3 

Auto-Ignition times 15-30 days 90 – 120 days 

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. Although these parameters were continuously monitored and controlled, 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. 

Low Sulfur CO Coal – 0.7 percent sulfur

Based on the 2007 data, if all of the current coal and coke is replaced with a 0.7 percent 

low sulfur coal, the sulfur input from fuel is calculated to be reduced by approximately 85 

percent (Synfuel levels were held constant and tires were not included as they have a 
Holcim (US) Inc. 4-4 Trinity Consultants 

BART Analysis 

higher sulfur content than the Low Sulfur CO coal) . Following is a summary of the sulfur 

input reduction from the use of low sulfur coal. The low sulfur CO coal has a lower heat 

content (26 Gj/Metric ton) and higher moisture content than the coke currently being used 

(33 Gj/Metric ton), so a higher volume of low sulfur CO coal is needed than coke reduced. 

Current – 2007 Average from coal/coke

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 CO 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%. 
Holcim (US) Inc. 4-5 Trinity Consultants 

BART Analysis 

Regional Coal – 3.0 percent.

A scenario that includes replacing the current coal/coke with a 3.0 percent coal was also 

evaluated. In this scenario, a revised fuel mix is used that includes: 

1) replacing the current coal and coke usage making up approximately 87.5 percent of the 

fuel mix with a 3.0 percent sulfur coal at 72 percent of the fuel mix, 

2) increasing Synfuel from approximately 12 percent to 18 percent of the fuel mix, and 

3) using tires at approximately 12 percent of the fuel mix (as discussed in MKF section). 

The details of the scenario are as follows: 

Current – 2007 Average from coal/coke

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 

Regional 3.0 Percent Sulfur Coal Scenario – Fuel Mix Changes

3.0 % Coal Usage: 169,241 metric tons 

Low Heat Content 25.8 Gj/Mt 

Sulfur Content: 3.0 % 

Sulfur Input from Coal: 5,077 metric tons 

Synfuel Usage (Increase): 4,520 metric tons 

Low Heat Content 20.2 Gj/Mt 

Sulfur Content: 0.21 % 

Sulfur Input from Synfuel: 10 metric tons 

Tires: 25,500 metric tons 

Low Heat Content 28.0 Gj/Mt 

Sulfur Content: 1.83 % 

Sulfur Input from Tires: 467 metric tons 

Total Sulfur Input from 3.0 percent Coal Scenario: 5,554 metric tons 

Net reduction in sulfur input from 3.0 percent coal scenario:

 9,529 metric tons – 5,554 metric tons = 3,966 metric tons = 4,372 tons 

The result is a net reduction of approximately 42 percent in the sulfur input from the fuel 

mix which corresponds to an overall sulfur input reduction of approximately 28 percent. 
Holcim (US) Inc. 4-6 Trinity Consultants 

BART Analysis 

Holcim estimates that the actual SO2 reduction from this fuel switch would be 

approximately 20-25 percent. 

These reductions are the maximum reductions in tons of SO2 that can be expected. As 

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

term basis. Holcim estimates that the net reduction in SO2 for 3.0 percent sulfur coal 

scenario would be 20-25 percent and for low sulfur CO coal 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 theoretically be reduced. 

The Clarksville Quarry Scheduling Optimization (QSO) Model was created specifically for 

predicting relevant mineralogical parameters related to clinker production. Major oxides 

(Ca, Mg, Si, and Fe) are the primary focus of this predictive model. The sampling protocol 

and data analysis required for major oxide components was never intended to be adequate 

for the accurate prediction of minor components, such as sulfur and sulfur compounds (See 

Appendix C for additional discussions on selective mining limitations based on Holcim’s 

QSO (Quarry Scheduling Optimization) computer model).

Based on the lack of available data to predict if selective mining would be feasible, Holcim 

has concluded that selective mining is not considered a technically feasible SO2

 control 

technology for the kiln. 

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 
Holcim (US) Inc. 4-7 Trinity Consultants 

BART Analysis 

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 
Holcim (US) Inc. 4-8 Trinity Consultants 

BART Analysis 

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 4-4 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. 4-9 Trinity Consultants 

BART Analysis 

TABLE 4-4. 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 20-50% 

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, scaled to 2012 dollars6, 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/year7. 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 4-5 

provides a summary of the cost effectiveness analysis related to WLS. The detailed cost 

analysis table is provided in Appendix D. 

 6 The most recent U.S. Department of Labor, Producer Price Index Industry Data, from April 2004 – April 2008 

indicates that costs have increased by the ratio of 143.2/102.9 over the last 5 year period (or 8.06 points per year). The 

original bid was from 2005. Consequently, the equipment cost was scaled up to 2012 (8 years) by multiplying by the 

following percentage (100 + (8 x 8.06)) percent = 1.645. 

7The 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. 4-10 Trinity Consultants 

BART Analysis 

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. 

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. 

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. A 

thorough evaluation of the stack gas constituents was conducted by Holcim and it was 

determined that to prevent an unacceptable increase in opacity from occurring, the stack 

gas would need to be reheated (if a scrubber is installed) to at least the current gas 

temperature after the ESP of approximately 380 deg F (see Appendix B for the detailed 

analysis). 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). In addition, Holcim also looked at the corresponding cost of building an 

onsite landfill for disposal, but based on information provided by MDNR, the time and 
Holcim (US) Inc. 4-11 Trinity Consultants 

BART Analysis 

resources required to obtain a permit, and the additional liability associated with an onsite 

landfill, Holcim decided not to pursue that option. 

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.8

TABLE 4-5. 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% $24,385,436 11,481 8,726 $2,826 $20 

WLS – PA 95% $24,925,003 11,481 10,362 $2,428 $21 

WLS – PTE 80% $24,840,863 13,298 10,106 $2,482 $20 

WLS – PTE 95% $25,465,823 13,298 12,001 $2,139 $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 4-5, 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. 

 8 Innovations in Portland Cement Manufacturing, Portland Cement Association, 2004, pg. 660 & 669 
Holcim (US) Inc. 4-12 Trinity Consultants 

BART Analysis 

4.4.2 FUEL SUBSTITUTION

Cost of Compliance 

Low sulfur CO coal

The increased cost of using low sulfur CO coal (0.7 percent sulfur) includes the relative 

increase in fuel cost as well as the cost of a new coal mill system. Low sulfur CO 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. and was scaled to 2012 dollars9, 

Regional 3.0 percent sulfur coal

The increased cost of the regional 3.0 percent sulfur coal scenario includes the relative 

increase in fuel cost as well as the cost of a new primary air fan and associated equipment. 

The 3.0 percent sulfur coal has a lower heat content than coke; consequently, a higher 

volume of coal will be needed that will require a larger primary air fan. Holcim is 

proposing to change the coal mill primary air fan and associated equipment. Reducing the 

capital cost does not have a significant impact on the outcome of the cost analysis. That is, 

eliminating the capitol cost completely only reduces the cost from $1,286/ton SO2 to 

$1,039/ton SO2. Consequently, Holcim has chosen to not spend additional time and effort 

documenting these costs. 

Table 4-6 provides a summary of the cost effectiveness analysis related to Fuel 

Substitution. The detailed cost analysis table is provided in Appendix D. 

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

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

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

 9 The most recent U.S. Department of Labor, Producer Price Index Industry Data, from April 2004 – April 2008 

indicates that costs have increased by the ratio of 143.2/102.9 over the last 5 year period (or 8.06 points per year). The 

original bid was from 2007. Consequently, the equipment cost was scaled up to 2012 (5 years) by multiplying by the ratio 

of 143.2/102.9. 
Holcim (US) Inc. 4-13 Trinity Consultants 

BART Analysis 

TABLE 4-6. 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 23% $3,933,016 11,481 2,641 $1,489 $3 

Fuel Sub – PA 40% $27,218,156 11,481 4,592 $5,927 $22 

Fuel Sub – PA 50% $27,218,156 11,481 5,741 $4,741 $22 

Fuel Sub – PTE 23% $3,933,016 13,298 3,059 $1,286 $3 

Fuel Sub – PTE 40% $27,218,156 13,298 5,319 $5,117 $22 

Fuel Sub – PTE 50% $27,218,156 13,298 6,649 $4,094 $22 

*

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

The 3.0 percent sulfur coal option (used 23 percent control as the average) is cost effective 

and will be considered further. 

The low sulfur CO coal option (40 to 50 percent control) is not cost effective and results in 

significant increases in cost per ton of clinker produced that would likely eliminate any 

profit margin currently realized by the plant. Thus, it would not be economically feasible 

to operate the plant with the low sulfur CO coal scenario. 

In addition, for this analysis Holcim did consider the blending of solid fuel but considered 

it also to not be cost effective. In order to properly blend solid fuels for a precise 

distribution to control sulfur and chlorine inputs and not disrupt production due to fuel 

quality swings, an additional solid fuel equipment handling system would have to be 

installed. At a minimum, for each additional solid fuel used a system consisting of feed 

chutes, transfer conveyors, a storage silo, and a weigh belt would be required. It was 

conservatively estimated that the cost would be similar to the cost of a new mill and thus 

increase the cost well above the 3.0% sulfur coal option. 

Energy Impacts 

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

difficult to estimate. The regional coal option also relies that a reliable source of tire 

derived fuel (TDF) and Hazardous Waste Derived Fuel (HWDF) is available to supplement 

23% of the thermal requirements for clinker production 

Non Air-Quality Impacts 

None. 

Remaining Useful Life 
Holcim (US) Inc. 4-14 Trinity Consultants 

BART Analysis 

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. 

4.4.3 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 
Holcim (US) Inc. 4-15 Trinity Consultants 

BART Analysis 

Table 4-7 provides a summary of the cost effectiveness analysis related to DLS. The 

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

obtained from the EPA’s Control Cost Manual, 6th Edition. 

TABLE 4-7. 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% $14,725,124 11,481 2,181 $6,750 $12 

DLS – PA 30% $14,725,124 11,481 3,272 $4,500 $12 

DLS – PTE 20% $16,756,579 13,298 2,527 $6,632 $14 

DLS – PTE 30% $16,756,579 13,298 3,790 $4,421 $14 

*

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 4-7, 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 23 percent, and 25 percent respectively. 

The emission rates are summarized in Table 4-8. 
Holcim (US) Inc. 4-16 Trinity Consultants 

BART Analysis 

TABLE 4-8. 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 

Fuel Substitution – 23% 3,765 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 4-9. The visibility improvement associated with the 

controls are also shown in Table 4-9; 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 4-9. 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 

(45% Control) Fuel Subs. 98% Impact 

(Δdv) 

0.70 0.58 0.37 

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

(23% Control) Fuel Subs. 98% Impact 

(Δdv) 

0.87 0.72 0.48 

Fuel Subs Improvement 98% Impact (Δdv) 0.14 0.09 0.13 

DLS 98% Impact (Δdv) 0.87 0.70 0.48 

DLS Improvement 98% Impact (Δdv) 0.14 0.11 0.13 
Holcim (US) Inc. 4-17 Trinity Consultants 

BART Analysis 

4.6 PROPOSED 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 4-10 summarizes 

the cost effectiveness for the controls based on the tons of SO2 reduced and the visibility 

improvement in deciviews. 
Holcim (US) Inc. 4-18 Trinity Consultants 

BART Analysis 

TABLE 4-10. 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 $24,385,436 $2,826 $20 

Fuel Sub–PA-40% 11,481 4,592 $27,218,156 $5,927 $22 

Fuel Sub–PA–23% 11,481 2,641 $3,933,016 $1,489 $3 

DLS – PA - 20% 11,481 2,181 $14,725,124 $6,750 $12 

*

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 $46,010,256 

Hercules 0.81 0.31 0.50 61.7 $48,770,872 

Buffalo 0.61 0.21 0.40 65.6 $60,963,590 

Control Type 

Fuel Subs. – 

40%

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 $87,800,502 

Hercules 0.81 0.58 0.23 28.4 $118,339,807 

Buffalo 0.61 0.37 0.24 39.3 $113,408,982 

Control Type 

Fuel Subs. -

23% 

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 $28,092,971 

Hercules 0.81 0.72 0.09 11.1 $43,700,177 

Buffalo 0.61 0.48 0.13 21.3 $30,253,969 

Control Type 

DLS-20% 

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 $105,179,459 

Hercules 0.81 0.70 0.11 13.6 $133,864,766 

Buffalo 0.61 0.48 0.13 21.3 $113,270,187 
Holcim (US) Inc. 4-19 Trinity Consultants 

BART Analysis 

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

compliance associated with WLS, Fuel Substitution with low sulfur CO coal, and DLS is extremely 

high on a $/ton of SO2 removed basis, and especially on a $/DV of improvement basis, and is not 

economically feasible, especially if the cost per ton of clinker produced is taken into account. Fuel 

Substitution with a regional 3.0 percent sulfur coal, resulting in a 23 percent reduction in SO2

emissions, is economically feasible and is being proposed as BART. 

Holcim proposes that BART for SO2 for the Holcim Clarksville Kiln is fuel substitution or equivalent 

technologies that will achieve a 23 percent reduction in the maximum daily SO2 emission rate of 

117,345 lbs. 

Consistent with BART applicability which is determined on a daily basis, Holcim proposes to comply 

with an enforceable limit for SO2 of 90,356 lbs/day which is a 23% reduction in the maximum daily 

SO2 emission rate of 117,345 lbs. 
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 NOx10. 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 NO2.11

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 5-1. 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. 

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

11 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 SCHEMATIC12

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. 

 12 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. 

Tires also have the benefit of a lower sulfur content (the Rubber Manufacturers 

Association reports a value of 1.83 percent) relative to the current coal/coke used as 

accounted for in the Fuel Substitution – Regional 3.0 percent sulfur coal scenario (See 

Section 4.2.1) for SO2 control 

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 
Holcim (US) Inc. 5-6 Trinity Consultants 

BART Analysis 

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 submicron 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.13 

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. 

 13 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 

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 

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. 

NOX reductions from SNCR systems can vary considerably based on site specific 

conditions, most notably being the type of kiln. For example, the NOX reduction at the 

long wet kiln at Lumber is lower at a given ammonia molar ratio than observed at similar 

size preheater/pre-calciner (PH/PC) kilns. Some of the reasons for this lower relative NOX

reduction include: 

• In a long wet kiln, the NH3 is sprayed in the kiln itself, rather than being sprayed in 

the ductworks in a PH/PC kiln. A kiln’s diameter is much larger than the 

ductwork diameter which makes it more difficult for the liquid NH3 to be evenly 

distributed across the entire cross section of the gas stream. 

• Studies have shown that in long kilns, the gas stream can be highly stratified over 

the cross section. The relatively heavy CO2 released from the raw materials tends 

to stay on the top and bottom of the raw material bed, while lighter O2 tends to 

float to the top of the kiln cylinder. This theory has been proven by many actual 

measurements at the plant. In contrast, the ductwork in PH/PC kiln systems are 

mostly vertical and this stratification is not observed, or is much less than in the 
Holcim (US) Inc. 5-8 Trinity Consultants 

BART Analysis 

horizontal kiln system. The combination of stratification in the kiln cylinder, and 

less even distribution of NH3, compound the problem of poor contact between the 

NH3 and NOX. 

• The reaction of NH3 and NOX includes multiple steps that require O2. In the areas 

of the long kiln that are lacking in O2, the reaction rate is significantly lower, and 

thus NOx reduction is significantly lower relative to a well mixed gas stream. 

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.14 

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 

 14 Slip refers to the quantity of unreacted reagent that exits the SCR reactor. 
Holcim (US) Inc. 5-9 Trinity Consultants 

BART Analysis 

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. 

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. 5-10 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 and the potential associated opacity issues due to ammonia slip (see Appendix 

B), 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. Regardless, a cost analysis has been conducted for informational purposes. 

Table 5-4 provides a summary of the cost effectiveness analysis related to MKF. The 

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

obtained from the EPA’s Control Cost Manual, 6th Edition. 

TABLE 5-4. COST ANALYSIS SUMMARY FOR MKF 

Control Case 

Control 

Effectiveness Annual Cost 

Existing Annual 

Emissions 

Pollutant 

Removed 

Cost 

Effectiveness 

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

MKF – PA 20% $594,680 6,414 1,283 $464 

MKF – PTE 20% $594,680 8,462 1,692 $351 
Holcim (US) Inc. 5-11 Trinity Consultants 

BART Analysis 

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. 

5.4.2 SNCR 

Cost of Compliance 

As SNCR would require a pilot test, and the level of control/feasibility is in question, 

Holcim can not prepare a detailed cost analysis. However, an analysis was recently 

conducted for a portland plant with a wet process kiln in Midlothian Texas which reported 

a cost effectiveness of $2200/ton15 which is significantly more than the $351/ton - $464ton 

for MKF. Regardless, as Holcim is accepting the most stringent control option available as 

BART, the cost of compliance is not required to be evaluated. 

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 

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

summarized in Table 5-5. 

TABLE 5-5. 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 5-6. The visibility improvements associated with MKF are also shown in Table 

5-6; this was calculated as the difference between the existing visibility impairment and the visibility 

 15 Assessment of NOx Emissions Reductions Strategies for Cement Kilns – Ellis County, Texas, Final Report. 

TCEQ Contract No. 582-04-65589, Work Order No.05-06. July 14, 2006. Page 1-12. 
Holcim (US) Inc. 5-12 Trinity Consultants 

BART Analysis 

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

impact. 

TABLE 5-6. 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 5-6, 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. Economic, energy and environmental impacts were assessed for this 

technology and the visibility improvements were evaluated against existing conditions. 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 Holcim Clarksville Kiln is the installation and operation of 

a Mid Kiln Firing (MKF) system or equivalent that will achieve a 20 percent reduction in the 

maximum daily NOX emission rate of 73,185 lbs. 

Consistent with BART applicability, which is determined on a daily basis, Holcim proposes to 

comply with an enforceable limit for NOx of 58,548 lbs/day which is a 20% reduction in the 

maximum daily NOX emission rate of 73,185 lbs. 

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. 
Holcim (US) Inc. 6-1 Trinity Consultants 

BART Analysis 

6. BART SUMMARY

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 or equivalent that will achieve a 20 percent 

reduction in the maximum daily NOX emission rate of 73,185 lbs. 

• SO2 – Holcim proposes that BART for the Holcim Clarksville Kiln is fuel substitution or 

equivalent that will achieve a 23 percent reduction in the maximum daily SO2 emission rate 

of 117,345 lbs. 

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 6-1. 

TABLE 6-1. 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) 0.79 0.64 0.48 

Improvement 98% Impact (Δdv) 22% 21% 22% 

Holcim proposes to implement BART on or before 5 years after EPA approval of Missouri’s 

Regional Haze Rule State Implementation Plan as per 40 CFR 51 Appendix Y. Because the actual 

implementation date is at least 5 years from the date of this document, Holcim requests that it not be 

bound to the technologies reviewed during this analysis, but to the daily limits stated in the report. 

Changes in technology may offer opportunities to obtain even better reductions with lower cost 

impact. 

Consistent with BART applicability which is determined on a daily basis, Holcim proposes to comply 

with an enforceable limit for SO2 of 90,356 lbs/day which is a 23% reduction in the maximum daily 

SO2 emission rate of 117,345 lbs.and a NOx limit of 58,548 lbs/day which is a 20% reduction in the 

maximum daily NOX emission rate of 73,185 lbs..
APPENDIX A. COAL COMPOSITION DATA 
Appendix A. Coal Composition Data - Holcim Clarksville BART Analysis Op

Regional Coals CO Coal

Area Illinois Illinois Colorado

Company Peabody COALSALES LL

C Knighthawk COALSALES LL

C

Mine name Gateway Mine KHC Mines, primarily Pairie Eagle Mine Twentymile Mine

FOB Lone Eagle (KHC Dock, Mile post 105)

Rail: Energy, CO to 

Cora, IL via UP RailBarge: Cora, IL to Clarksville

Transportation Mode Barge Truck & Barge 0.7% Sulfur CoalSulfur % 2.83% 3.00% 0.70% Sulfur %Ash 

% 8.60% 8.50% 10.00%

Ash 

%

Volatiles % 35.50% 37.00% 34.40%

Volatiles %

Moisture % 13.50% 12.50% 10.00% Moisture %Hydrogen % 5.00% 5.20% 5.00% Hydrogen 

HGI 52 55 45 HGI

Chlorine % 0.12% 0.05% 0.01% Chlorine %

mmbtu/lb 11,000 11,100 11,300 mmbtu/lb

HHV MJ/MT 25,582 25,814 26,279 HHV MJ/MT

LHV MJ/MT 25,567 25,800 26,266 LHV MJ/MT

Ultimate (Dry) Ultimate (DAsh % 9.90% 9.00% 11.00% Ash %

Hydrogen 5.00% 5.20% 5.00% Hydrogen

Total Carbon 71.40% 72.00% 69.60% Total Carbo

Nitrogen 1.30% 1.40% 1.70% Nitrogen

Sulfur 3.28% 3.10% 0.54% Sulfur

Chlorine 0.12% 0.04% 0.01% Chlorine

Oxygen 9.00% 9.40% 10.75% Oxygen

Ash Mineral (Dry) Ash Minera

Silicon Dioxide 51.40% 50.70% 60.00% Silicon Diox

Aluminum Oxide 19.70% 20.50% 25.10% Aluminum O

Titamium Dioxide 1.00% 1.00% 0.90% Titamium D

Calcium Oxide 4.20% 3.50% 4.00% Calcium Ox

Iron Oxide 16.30% 15.80% 3.10% Iron Oxide

Magnesium Oxide 1.00% 1.00% 1.40% Magnesium 

Potassium Oxide 2.20% 2.20% 1.30% Potassium 

Sodium Oxide 1.30% 0.70% 1.20% Sodium Ox

Sulfur Trioxide 2.60% 2.70% 1.50% Sulfur Triox

Phos Pentoxide 0.20% 0.20% 0.90% Phos Pento

Strontium Oxide 0.10% 0.20% Strontium O

Barium Oxide 0.10% 0.40% Barium Oxi

Manganese Oxide 0.10% 0.10% 0.10% Manganese 

Vanadim PentroxideNickel OxideUndetermined 1.80%
APPENDIX B. REVIEW OF THE POTENTIAL FOR PLUME OPACITY 

EXCEEDANCES RESULTING FROM THE USE OF A WET SCRUBBER
Appendix B. Review of the Potential for Plume Opacity 

Exceedances Resulting from the Use of a Wet Scrubber. 

Nianzhi Wang, MPC-E 

In the BART analysis for Holcim’s Clarksville (CV) facility, a wet scrubber has been 

evaluated as a BART control option for SO2. Although, a scrubber was shown to be 

technically feasible, it was also determined that reheating of the exhaust gas would be 

necessary to avoid a detached/attached plume. Following is an analysis of the gas 

stream to determine the specific temperature needed for the plume reheating 

requirement. The kiln system is currently controlled by an ESP and currently has an 

outlet gas temperature of approximately 380 deg F. 

Background - The plume problem in cement manufacturing process

To evaluate the reheating requirement, we have to briefly introduce the plume problem 

in cement plants and potential risk of a visible plume after the scrubber. 

The following figure shows the chemical reactions for most common types of plume in 

the cement manufacturing process, Although SO3 and Total Hydrocarbons (THC) may 

also contribute to the plume, they have not been considered. 

SO2

Visible Particulate Visible Particulate

H2 SO4

NH3

H2O

NH4Cl

SO2 NH3

H2 O

Condensation Condensation

Cooling

Hot Gases with Hot Gases with 

Various Gaseous Various Gaseous 

Species

SO2

Visible Particulate Visible Particulate

H2 SO4

NH3

H2O

NH4Cl

SO2 NH3

H2 O

Condensation Condensation

Cooling

Hot Gases with Hot Gases with 

Various Gaseous Various Gaseous 

Species

Secondary Plume

T = Stack Temperature, RH = Ambient Relative Humidity, Ta = Ambient 

Temperature 

NH4Cl (NH4)2SO4

T HCl NH3 SO2 T

Secondary Plume

sub-micron aerosol

H2O

Ta, RH

NH4Cl (NH4)2SO4

T HCl NH3 SO2 T

sub-micron aerosol

Ta, RH

H2O

 B-1 6/12/2008 
Some of the key points relevant to the diagram include: 

 Both (NH4)2SO4 and NH4Cl are sub-micron aerosols that form at relatively low 

stack temperatures. (NH4)2SO4 formation needs condensed moisture to occur. 

Whereas NH4Cl solid can quickly form directly from the gas phase of NH3 and HCl 

although with condensed moisture the reaction rate will be much faster. 

 Sub-micron aerosols are similar in size to the wave length of light and thus 

strongly scatter the light and block light transmission through the stack gas. 

Figure 1 provides an example of relative light extinction versus particle size. For 

example, a PM0.5 particle has an extinction efficiency approximately an order of 

magnitude greater than that of PM10. 

Figure 1. Extinction Efficiency Factor Verses Particle Diameter.

• The particle light extinction efficiency factor indicates the total light flux scattered and 

absorbed by a particle. Aerosols in the 0.2 - 1.0 μm diameter range are particularly 

effective in scattering visible light (wavelength: about 0.4 - 0.7 μm) on a unit mass basis, 

with a peak attenuation at 0.5 μm. 

• The particles of either very large (>5 μm) or very small (<0.1 μm) diameter are much 

less effective in light attenuation.

 Plume aerosols usually form outside of the stack when the gas temperature is 

quickly cooled down and moisture is condensed, but the precursors have not had 

sufficient time to be diluted with ambient air. This situation is most dominant in 

occurrence on cold, calm and humid days. 

Supplement A, at the end of this document, contains examples of historical visible 

plume problems in the cement industry and related studies. 

 B-2 6/12/2008 
Problems Associated with Using a Wet Scrubber on the Clarksville Kiln 

Exhaust Gas (in-stack)

 If a wet scrubber is installed after the Clarksville kiln, the kiln gas will need to be 

quenched and cooled down to the dew point temperature at the inlet of the 

scrubber (a similar condition of gas cooling in the presence of high humidity that 

can occur at the exit of a stack). If the gas has NH3 and HCl, they can quickly 

react to form aerosols (fine particulate matter). These very fine particulates are 

controlled with a much lower efficiency than larger PM and thus can increase PM 

levels of the form of PM that leads to the highest plume visibility. 

 In addition, the scrubber can not remove all NH3 or SO2 in the gas stream. The 

typical SO2 reduction in a scrubber is about 90%. The NH3 removal is governed 

by the equilibrium between the gas and the scrubber slurry liquid. Figure 2 

provides the NH3 gas-liquid equilibrium graph at a pH of 6. The NH3 remaining in 

the effluent can be up to 10 ppm depending on the type of scrubber, the pH set 

point in the scrubber, and the scrubber influent NH3 concentration. The 

remaining SO2 and NH3 in the scrubber effluent could react with the NH4Cl 

aerosols already present in the gas and further increase plume visibility. 

0 .0

0 .5

1 .0

1 .5

2 .0

2 .5

0 5 10 15 20 25 30 35

H N 3 C o n c e n tra tio n in G a s (p p m v )

Concentration of NH 4

+ in solution , (g / l)

pH = 6

 

 

Figure 2. Concentration of NH4

+

 versus HN3 Concentration in Gas 

 The gas temperature after the scrubber is much lower than the kiln gas 

temperature. Besides the aerosols formed at the inlet of the scrubber, more 

aerosols may also form in the cold and wet stack, and therefore, increase opacity. 

Several scrubber vendors have confirmed the above phenomena with scrubber use: 

 As an example, a vendor evaluated building a wet scrubber for one of Holcim’s 

PH/PC plants. A PH/PC kiln system typically has two gas effluent streams, one 

contains high NH3 (main stack) and the other contains high HCl (by-pass stack). 

Usually, both streams are introduced to a control device at the same inlet, 

 B-3 6/12/2008 
However, in this situation, the vendor provided the following concerns/comments 

in doing so as part of a feasibility study for the plant1

: 

“Mixing the NH3 and HCl streams at the inlet will indeed produce an NH4Cl 

salt that will be submicron in size”. 

“This will result in opacity, I am sure it will be greater than 20%. Once this 

salt is formed, it will be very difficult to remove. Therefore, the preferred 

treatment would be to absorb the gases before they have a chance to 

react”. 

“As we discussed, the two separate gas streams can be treated with 

individual scrubbers. However, it would be less expensive to perform the 

scrubbing in a single, large vessel with two separate inlet barrel” 

The scrubber system was ultimately built by Monsanto. And, even though the 

problem was acknowledged, and the system was designed to prevent the visible 

plume problem, the plant still has challenges with plume formation during the winter. 

Kiln gas emission concentrations and opacity

 Holcim, as well as other companies, have found that at about 5ppm NH4Cl or 

10ppm (NH4)2SO4, detached plumes can form outside of the stack if the stack 

gas is not hot enough to allow for significant dilution prior to condensation or if it 

is a very cold day in winter. Both aerosols will form quickly when the stack gas is 

cooled down by very cold ambient air. 

 Stack temperatures for wet kilns are typically about 350 F. PH/PC kilns have 

similar stack temperatures when their in-line raw mills are not running. During 

these periods, PH/PC kilns have also observed a higher frequency of visible 

plumes as the precursors, NH3, HCl and SO2, are not absorbed in the in-line raw 

mill. 

Some specific examples of plants with visible plumes caused by constituents with 

concentrations similar to those in the Clarksville plant include: 

 The CEMEX plant at Cementos Guadalajara, a 4 stage PH/PC kiln, had a highly 

visible plume caused by NH4Cl. To resolve the problem, the plant added two 

additional stages that increased pollutant adsorption (HCl emissions were 

reduced to 5 ppm) and the plume disappeared. The reported stack temperature 

is 260 C (500 deg. F) which is much hotter than that of Holcim’s Clarksville plant. 

Further, Clarksville’s long wet kiln does not have the benefit of the stages in the 

PH/PC kiln for enhanced adsorption. 

 1 Steven Meyer, product Manager of Monsanto Company. Letter to Holcim for feasibility study of 

wet scrubber project, 10/29/1998

 B-4 6/12/2008 
 Holcim’s Mississauga plant had a highly visible plume during the winter until they 

eliminated condensed moisture formation by heating the gas and reducing the 

HCl concentrations to less than 3-5 ppm. Holcim’s Clarksville kiln can have HCl 

concentrations much higher than 5 ppm as will be discussed in a following 

section. 

 Holcim’s Untervaz plant in Switzerland has a wet scrubber as well as high levels 

of HCl and NH3 in the kiln gas, and they have reported visible plumes during the 

winter especially when the in-line raw mill is down and the pollutant 

concentrations are higher. 

Impact of Temperature on Visibility – Reaction Rate Based Equations

Solid NH4Cl aerosols can form directly from the gas phase through the following 

reversible chemical reaction when the temperature drops: 

NH4Cl (s) = HCl (g) + NH3 (g) 

The thermodynamic criteria for the reaction to occur is determined by the 

equilibrium constant Kp, which can be expressed by the following equation2

ln Kp = 34.266 –21196/T 

where T is the temperature (K). The chemical reaction takes place if the product of 

partial pressures of HCl and NH3 in gas is greater than Kp, i.e. (pHCl · pNH3) > Kp 

(pHCl & pNH3 are both in atm). This reaction can keep going to form NH4Cl until the 

partial pressures of NH3 and HCl have dropped to a level such that their product is 

less than Kp. 

If the CV plant utilized a wet scrubber, and we assume the scrubber inlet 

temperature after quenching is 170 deg F or 76.6 deg C, the Kp would be 3.6 E-12. 

In the kiln gas, concentrations as low as 1-2 ppm (1.0 E-06 - 2.0 E-6) NH3 and HCl 

will make the (pHCl · pNH3) > Kp, and the reaction will not stop until both gas phases 

drop down to 1-2 ppm. Thus, almost all NH3 and HCl with a concentration higher 

than 1-2 ppm in the kiln gas will form NH4Cl aerosols in the scrubber. 

Reheating the stack gas after the scrubber has two purposes: 

1) Dissociate the newly formed NH4Cl solid 

2) Prevent the formation of aerosols from NH3 and HCl from forming again in the 

stack or near the stack. The higher the reheating temperature, the longer the 

 

2 P. Goldfinger, G. Verhaegen, “Stability of the Gaseous Ammonium Chloride Molecule”, The 

Journal of chemical Physics, 50(1), 1467-1471 (1969)

 B-5 6/12/2008 
gas has to disperse and be diluted with ambient air, so that the product of 

both NH3 and HCl concentrations would not be higher than Kp, and no 

aerosol formation would occur. 

An example of how reheating temperature affects the opacity in a power plant is 

depicted in Figure 33

. The precursor of the visible plume in this case is SO3, (as 

opposed to NH4Cl). 

Figure 3. Gas Temperature Effect on Opacity Verses Time (t*) 

Although reheating the stack gas to a temperature above the acid gas dew point 

may help to reduce corrosion problems and in-stack opacity, it may not be enough to 

avoid a plume outside of the stack. When the gas exits the stack, the temperature 

will quickly drop to below the acid dew point. Acid gas may be condensed, and acid 

water droplets may occur that will speed up other reactions in the liquid phase. 

Figure 4 shows an example for stack gas containing SO3. The gas temperature in 

the stack is much higher than the acid dew point, but once it goes out of the stack it 

takes only one second for the plume temperature TP to drop below the dew point 

temperature TDP and cause higher opacity levels. 

 

3

 J. J. Martin Hughes, “Fine Particle Model for Detached Plume Opacity”, Virginia State University, 16th Annual 

Meeting of the Fine Particle Society, April, 1985. 

 B-6 6/12/2008 
Figure 4. Stack gas temperature vs. Acid Dew Point and Time 

Besides pollutant concentrations, other factors such as the stack gas temperature 

and moisture, the ambient air temperature and humidity, wind speed, sunlight and 

sky clarity, stack size and height effect plume visibility. Therefore, it is almost 

impossible to predict the exact reheating temperature required. Regardless, a 

mathematical model has been established to provide a simplified simulation of 

NH4Cl formation outside of the stack based on the actual conditions at the CV plant. 

Estimating the Reheat Temperature for CV based on Plant Data

The NH3 and HCl emission concentration will control the plume formation as SO2

concentrations are likely to be sufficiently high as to not be limiting in any equations. 

Table 1 summarizes the CV annual stack testing for 2002 - 2007. Although HCl was 

relatively low in 2007, it can and has varied significantly over the last five years. 

Table 1. HCl and NH3 Stack Test Data for Clarksville – 2002 thru 2007. 

CV Emission HCl NH3

ppmd ppmd

Average

ppmw ppmw

2002 12.8 9.1 36.2 25.7

2003 30.3 21.5 20.6 14.6

2004 26.9 19.1 27.1 19.2

2005 14.4 10.3 16.0 11.5

2006 8.0 5.6 22.5 15.7

2007 2.7 1.9 24.9 17.6

15.9 11.2 24.6 17.4

 B-7 6/12/2008 
Please note that this data is from once per year stack testing not a Continuous 

Emission Monitor (CEM) and thus the annual and daily emission levels may vary 

considerably from these values. Further, the peak annual emission may be much 

higher than the test average. For example, during the three hours of stack tests in 

2004, the maximum hourly HCl concentration was 70% higher than the minimum 

and 23% higher than the average. 

Further, under current operations in 2007, the plant found that during some cold 

days, the plume outside of the stack was visible, but it did not reach 20% opacity. 

The current stack temperature is about 350 F, and the temperature at the outlet of 

the ESP is about 380 F. The lower temperature in the stack is due to heat loss in 

the ductworks and the I.D. fan. Therefore, a reheating temperature of 380 F is 

proposed to maintain the current stack temperature of 350 F and eliminate the 

plume formation after the scrubber. 

Using the 2007 stack test data (2 ppm HCl and 18 ppm NH3), a reheat temperature 

of 380 F, or 350 F stack temperature, might not be necessary since based on our 

modeling result, the total HCl and NH3 as aerosols after the scrubber should not be 

higher than in the original kiln gas. 

However, HCl concentrations in the prior years have been as much as 10 times 

higher than 2007, reaching over 20 ppm in 2003 and 2004, while the NH3

concentrations were nearly 20 ppm. These levels are considered to be highly 

probable of causing a visible plume at the current exhaust temperatures. Reviewing 

historical data, it was found that stack temperatures during these time periods were 

much higher than current temperatures. For example, the stack temperature was 

maintained at approximately 700 deg. F in 2003 and approximately 450 deg F (480 

deg F at the outlet of the ESP) in 2004 (100 F higher than the proposed reheating 

temperature). The higher temperatures likely prevented significant visible plumes 

from occurring. 

Regarding the use of a wet scrubber, even if some reduction in HCl occurred (such 

as 20%), the total HCl concentration after the scrubber would still be significantly 

higher than that in the kiln gas in 2007. Under this scenario, reheating to an ESP 

outlet of 380 F, or 350 F stack temperature, would likely not be sufficient to assure a 

stack opacity below 20% and additional re-heating would likely be required. 

Consequently, the proposed 380 F reheating temperature should be considered as 

an average for the year. That is, if the HCl and NH3 concentrations reach 20 ppm in 

the kiln gas, the reheat temperature may need to be 480 deg F or higher in the 

winter, while if the HCl and NH3 concentrations drop to 2007 levels or below, a 

reheat temperature of less than 380 deg F may be sufficient in the summer. 

Therefore, considering the variation in the HCl and NH3 concentrations, an annual 

average reheat temperature of 380 deg F may be sufficient. 

 B-8 6/12/2008 
Is scrubbing half of the exhaust stream, and using the unscrubbed half for 

reheat, a viable option? 

A scenario in which half or the exhaust gas stream is scrubbed, and the other half is 

not, followed by recombining the gas streams, was also considered. If feasible, this 

scenario would result in the unscrubbed gas providing the heat source to re-heat the 

scrubbed gas up to a temperature midway between the scrubbed gas temperature of 

approximately 170 deg F and the unscrubbed gas temperature of approximately 380 

deg F, resulting in a mid-range temperature gas stream of approximately 275 deg F. 

Unfortunately, as discussed previously, the variability in precursor pollutant (HCl and 

NH3) concentrations would most certainly lead to a visible plume at this low 

temperature and re-heating would continue to be required up to the originally 

identified average temperature of 380 deg F. This option was one of the scenarios 

evaluated in the modeling exercise discussed in the following sections. 

Mathematical analysis of the impact of reheating temperature on CV visible 

plume

Using the equation described previously, 

ln Kp = 34.266 –21196/T 

a mathematical model was established to simulate NH4Cl formation outside of the 

stack. Based on Holcim’s experience with visible plumes at multiple plants, an 

NH4Cl aerosol concentration of 5ppm in the atmosphere is used as the criteria for a 

highly visible plume outside of the stack. In reality, some of Holcim’s plants control 

their NH4Cl aerosol concentrations to less than 1-3 ppm to avoid visible plume 

formation. 

This model only considers the gas temperature reduction due to mixing with ambient 

air and does not consider any reduction due to radiation. Thus, the actual condition 

will be worse than what the model predicts. 

NH4Cl formation was simulated for the following scenarios: 

• Scenario 1. Maximum stack testing NH3 and HCl concentrations for the last 4 

years, reheating to 380F and Winter Condition 

• Scenario 2. Maximum stack testing NH3 and HCl concentrations for the last 4 

years, reheating to 380F and Summer Condition 

• Scenario 3. Maximum stack testing NH3 and HCl concentrations for the last 4 

years, reheating of 50% kiln gas (300F) and Winter Condition 

• Scenario 4. Maximum stack testing NH3 and HCl concentrations for the last 

4 years, reheating of 50% kiln gas (300F) and winter Condition 

• Scenario 5. Average of the NH3 and HCl concentrations for the last 4 years, 

reheating of 50% kiln gas (300F) and winter Condition 

 B-9 6/12/2008 
• Scenario 6. Average of the NH3 and HCl concentrations for the last 4 years, 

reheating of 50% kiln gas (300F) and summer Condition 

• Scenario 7. Average of the NH3 and HCl concentrations for the last 4 years, 

reheating of 380 F and summer Condition 

• Scenario 8. Maximum stack testing NH3 and HCl concentrations for the last 4 

years, reheating to 480F and Winter Condition 

Additional Model Assumptions/Calculations: 

The model assumes that in each interval 50% of the original stack gas volume will 

be diluted with ambient air. Based on this dilution, and with respect to the ambient 

and stack gas specific heat, the temperature of the mixture will be calculated. Next, 

the Kp line which represents the equilibrium condition is drawn by inserting the 

temperature in the above formula. The corresponding concentration of HCl and NH3

of the gas mixture is calculated at each interval, converted to partial pressures and 

multiplied with each other to find the Mixing Path value (Km). The Mixing Path (Km) 

at the corresponding temperature represents the calculated gas conditions at that 

interval. Then the Km+5 line which corresponds to the concentration of NH3 and HCl 

that will result in the formation of at least 5 ppm of aerosols is drawn,. At any point 

that the Mixing Path and Km+5 lines cross each other at least 5 ppm of aerosols has 

been formed. 

 B-10 6/12/2008 
Scenario 1 (Figure 5) represents the 380°F reheating temperature and stack 

temperature of 350°F, an ambient temperature of 14°F (representing a typical winter 

temperature), and the five year maximum NH3 and HCl concentrations of 27 ppmv, 

dry. Furthermore, it shows that the Km and Mixing path lines cross at around 85°F 

and will form more than 5 ppm of aerosol NH4Cl. Thus, a visible plume would be 

predicted. 

Formation of NH4Cl Plume

1.0E-21

1.0E-19

1.0E-17

1.0E-15

1.0E-13

1.0E-11

1.0E-09

1.0E-07

1.0E-05

1.0E-03

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

Line for 5ppm Aerosol formed

HCl(g) + NH3(g)

(no plume formation)

Conditions ° F ° C 

Ambient Air Temperature 14 -10 

Reheating Temperature 380 193 

Stack Temperature 350 177 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 5

 B-11 6/12/2008 
Figure 6 has the same ambient and stack temperatures as well as pollutant 

concentrations as Scenario 1, but provides more detail (zoomed in view) where the 

Km and Mixing Path lines cross. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

Line for 5ppm Aerosol formed

HCl(g) + NH3(g)

(no plume formation)

Conditions °F °C 

Ambient Air Temperature 14 -10 

Reheating Temperature 380 193 

Stack Temperature 350 177 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 6

 B-12 6/12/2008 
Scenario 2 (Figure 7) represents the situation in Figures 5 & 6 (380 F reheating and 

350 F stack temperature) but at a typical spring/summer temperature of 68°F. At 

these conditions, the Mixing Path barely misses the line representing 5 ppm aerosol 

NH4Cl formation. Thus, a visible plume formation is not anticipated. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

Line for 5ppm Aerosol formed

HCl(g) + NH3(g)

(no plume formation)

Conditions °F °C 

Ambient Air Temperature 68 20 

Reheating Temperature 380 193 

Stack Temperature 350 177 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 7

 B-13 6/12/2008 
Scenario 3 (Figure 8) provides a reheating gas temperature of 300 °F corresponding 

to a stack temperature of 270 °F and the maximum 5 year pollutant concentration of 

27 ppmv, dry at winter ambient conditions. At this stack temperature, the Mixing 

Path crosses the 5 ppm aerosol NH4Cl formation line and nearly crosses a 10 ppm 

aerosol NH4Cl line. This scenario has a very high risk of a visible plume problem 

with >20% opacity. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas

Mixing Path Km, 5ppm Aerosols Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

Line for 10ppm Aerosol formed

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 14 -10 

Reheating Temperature 300 149 

Stack Temperature 270 132 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 8 

 B-14 6/12/2008 
Scenario 4 (Figure 9) provides a reheating gas temperature of 300 °F corresponding 

to a stack temperature of 270 °F and the maximum 5 year pollutant concentration of 

27 ppmv, dry (same as Scenario 3) but at typical spring/summer ambient 

temperatures. At this stack temperature, the Mixing Path still crosses the 5 ppm 

aerosol NH4Cl formation line. This scenario also has a high risk of a visible plume 

problem. However, it is not predicted to be as severe as the previous scenario. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas

Mixing Path Km, 5ppm Aerosols Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

Line for 10ppm Aerosol formed

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 68 20 

Reheating Temperature 300 149 

Stack Temperature 270 132 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 9

 B-15 6/12/2008 
Scenarios 5 and 6 (Figure 10 and Figure 11). Under these temperatures, the 

average 5 year concentration of NH3 (25 ppmv, dry) and HCl (16 ppmv, dry) is 

predicted to form more than 5 ppm of aerosol NH4Cl at an average winter 

temperature (Figure 10) and close to 5 ppm at an average summer (Figure 11) 

ambient temperature. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 14 -10 

Reheating Temperature 300 149 

Stack Temperature 270 132 

HCl Concentration (ppmv, dry) 16 

NH3 Concentration (ppmv, dry) 25 

Figure 10

 B-16 6/12/2008 
Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 68 20 

Reheating Temperature 300 149 

Stack Temperature 270 132 

HCl Concentration (ppmv, dry) 16 

NH3 Concentration (ppmv, dry) 25 

Figure 11

 B-17 6/12/2008 
Scenario 7 (Figure 12) represents the actual 2007 condition of the Clarksville plant 

at a typical winter temperature. It is apparent that the Mixing Path line and Km are 

not crossing since the total HCl concentration is only 3 ppm. Note that the HCl 

concentration in 2007 was the lowest of the 5 years and could vary to more than 30 

ppm as found in 2003. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 14 -10 

Reheating Temperature 380 193 

Stack Temperature 350 177 

HCl Concentration (ppmv, dry) 3 

NH3 Concentration (ppmv, dry) 25 

Figure 12 

 B-18 6/12/2008 
Scenario 8 (Figure 13) shows the actual 2004 conditions of the plant at a typical 

winter ambient condition. Although the HCl and NH3 concentrations are relatively 

high, the high stack temperature (480 deg F) allows for dilution and the Mixing Path 

line does not cross the Km line and therefore less than a 5 ppm aerosol NH4Cl 

concentration is predicted. 

Formation of NH4Cl Plume

1.0E-12

1.0E-10

1.0E-08

-20 0 20 40 60 80 100 120 140 160 180

Temperature (oC)

Kp = PHCl ·PNH3 (atm x atm)

Saturation Line Ambient Air Stack Gas Mixing Path Km, 5ppm Aerosols

HCl(g) + NH3(g) = NH4Cl(s)

(plume formation)

HCl(g) + NH3(g)

(no plume formation)

Line for 5ppm Aerosol formed

Conditions °F °C 

Ambient Air Temperature 14 -10 

Reheating Temperature 480 249 

Stack Temperature 450 232 

HCl Concentration (ppmv, dry) 27 

NH3 Concentration (ppmv, dry) 27 

Figure 13

 B-19 6/12/2008 
Conclusion

In conclusion, the stack temperature needed to prevent a visible plume from 

occurring is highly dependent on the ambient temperature, the concentrations of 

HCl and NH3 in the gas stream, as well as other factors. Due to the normal 

variability in HCl and NH3 concentrations, it is virtually assured that the 

combination of higher HCl and NH3 concentrations and lowering the stack gas 

temperature below current levels (380 deg F at the exit of ESP and 350 deg F at 

stack) would lead to a visible plume condition. 

 B-20 6/12/2008 
 B-21 6/12/2008 

Supplement A: Some Examples of plume problems in cement 

Industry 

The first regulatory action concerning secondary plumes in the cement industry 

occurred in 1979 at Glens Falls Cement, Glens Falls, New York, USA. Plume 

studies were conducted by EPA and stack test contractors by sampling the plume 

using a tethered balloon. 

The secondary plume was observed to have an average opacity of ~85% while the 

in-stack opacity was only 10%. The tests revealed that the particulate matter 

recovered from the plume was mainly crystals of ammonium sulphate. The tests 

indicated that the primary components of the stack effluent were (NH4)2SO4 (4.5 

ppm), SO2 (200 ppm), NH3 (170 ppm), moisture (20%). The ammonium sulphate in 

the stack gas was responsible for the 10% in-stack opacity. 

The secondary plume was also observed at Lehigh Cement in Leeds, Alabama, 

USA. Testing conducted in 1981 indicated that the major species responsible for the 

plume was ammonium chloride, NH4Cl. 

Similar tests were conducted in 1987 at Kaiser Cement in Permamenti, California, 

USA. The results revealed that NH4Cl was also responsible for the visible 

secondary plume. The secondary plume tests conducted in 1987 at Southwestern 

Portland Cement in Victorville, California, USA, also revealed that NH4Cl was 

responsible for the visible secondary plume. 

In 1986, EPA conducted a source and process sampling program at the South 

Dakota Cement Company, Rapid City, South Dakota, USA. The samples collected 

from the secondary plume contain up to 67% NH4Cl. Further tests indicated that the 

NH3 exists mainly in the shale that accounts for about 20% of raw mix. The plant 

has a dry process with a 4-stage preheater, vertical roller mill for raw grinding and a 

main baghouse for dedusting. A severe ammonia recirculation was observed, with 

an average NH3 content in shale being 6.2 ppm while up to 159 ppm NH3 was found 

in the baghouse dust. It was also observed that the NH3 content in the baghouse 

dust was reduced substantially when gas temperature increased from 170 deg C 

(compound operation) to 250 deg C (direction operation). 

The secondary plumes in cement plants are not limited to the USA. They have also 

been reported by a Mexican cement company which determined through plant 

measurements that NH4Cl was responsible for the visible plume. 

Other examples include the Lone Star Industries’ Cape Girardeau Cement Plant, 

MO, USA and the Inland Cement, Edmonton, AB, Canada. Both plants experienced 

secondary plumes due to formation of ammonium sulphate. 
APPENDIX C. SELECTIVE MINING – QUARRY SCHEDULING OPTIMIZATION 

DISCUSSION
Appendix C. Selective Mining – Quarry Scheduling 

Optimization Discussion 

Holcim (US) Inc. evaluated 

the Clarksville Quarry 

Scheduling Optimization 

(QSO) model for sulfur 

emissions. 

The model is based on 

statistical and spatial 

analysis of data obtained 

through drill core sub 

sampling. Validation of 

relevant data is insured 

through the analysis of 

varagrams and histograms. 

This validation insures that correlation between samples is relevant. 

The Clarksville QSO Model was created specifically for predicting relevant mineralogical 

parameters related to clinker production. Major oxides (Ca, Mg, Si, and Fe) are the 

primary focus of this predictive model. The sampling protocol and data analysis 

required for major oxide components was never intended to be adequate for the 

accurate prediction of minor components, such as sulfur and sulfur compounds. 

When placed under scrutiny, existing data was found to be inadequate for accurate 

prediction of S content in the potentially quarried shale. Spatial relationships between 

core samples were found to be inappropriate for the sensitivity needed to make 

accurate predictions. The reason for this is the geologic nature of the Maquiketa Shale 

and Kimmswick Limestone, of which the primary sulfur mineral is pyrite (FeS). 

North 

One of the most important chemical processes in organic-rich marine sediments, such 

as Maquiketa shale, is decomposition of organic matter (OM)in bacterial sulphate 

reduction. Bacterial sulphate reduction produces 

bisulphide. Bisulphite can be partially oxidized or can 

react with OM and reactive metal species. All these 

reactions may be bacterially mediated. The reaction of 

reduced sulfur with reactive dissolved iron and iron 

minerals, if available, results in the formation of iron 

sulphides. The most common iron sulphide in pyrite. 

The amount of pyrite formation in marine sediments is 

largely determined by the availability of sulphate, 

reactive iron and reactive OM during the formation of 

 C-1 
 C-2 

the sediments. The locations of the reactive iron and sulphate are a random occurrence, 

usually along planes of weakness or channels of solubility during rock forming 

(induration). The pyrite is formed as nodules or clusters of mineralization and is not 

evenly distributed spatially throughout the shale and limestone. 

Therefore the chance of intercepting a pyrite cluster of mineralization by core drilling is 

known as a ‘nugget’ effect. Intercepting a pyrite cluster will give artificially high sulfur 

values in the model and, conversely, not intercepting pyrite mineralization can give low 

values. 

In the planned mining area only 5 core holes were drilled (DH-2, DH-3, DH-4 and DH-7). 

While the spacing of the drill holes are adequate for predicting major oxides, they are 

too far apart and too few to accurately predict clustered mineralogy such as pyrite. 
APPENDIX D. BART CONTROL COST TABLES
Table D-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, inflated to 2012 dollars $17,317,574

Instrumentation (10% of EC) $1,731,757

Freight (5% of EC) $865,879

Subtotal, Purchased Equipment Cost (PEC) $19,915,210

Direct Installation Costs

Foundation (6% of PEC) $1,194,913

Supports (6% of PEC) $1,194,913

Handling and Erection (40% of PEC) $7,966,084

Electrical (1% of PEC) $199,152

Piping (30% of PEC) $5,974,563

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

Insulation for Ductwork (1% of PEC) $199,152

Painting (1% of PEC) $199,152

Subtotal, Direct Installation Cost $17,427,929

Site Preparation N/A

Buildings N/A

Total Direct Cost $37,343,139

Indirect Costs

Engineering (10% of PEC) $1,991,521

Construction and Field Expense (10% of PEC) $1,991,521

Contractor Fees (10% of PEC) $1,991,521

Start-up (1% of PEC) $199,152

Performance Test (1% of PEC) $199,152

Contingencies (3% of PEC) $597,456

Total Indirect Cost $6,970,324

Total Capital Investment (TCI) $44,313,462

Direct Annual Costs

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

Operating Labor

Operator 2 x 3,573 hours/year, $50/hr) $357,300

Supervisor (15% of operator) $53,595

Subtotal, Operating Labor $410,895

Maintenance

Labor (2 x 820 hours/year, $50/hr) $82,000

Material (5% of Total Direct Cost) 1,867,157 $ 

Subtotal, Maintenance $1,949,157

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, Limestone $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 $16,331,486

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $1,416,031

Administrative (2% TCI) $886,269

Property Tax (1% TCI) $443,135

Insurance (1% TCI) $443,135

Capital Recovery (15 year life, 7 percent interest) $4,865,380

Total Indirect Annual Cost $8,053,950

Conclusion

Total Annualized Cost $24,385,436

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 $2,826
Table D-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, inflated to 2012 dollars $17,317,574

Instrumentation (10% of EC) $1,731,757

Freight (5% of EC) $865,879

Subtotal, Purchased Equipment Cost (PEC) $19,915,210

Direct Installation Costs

Foundation (6% of PEC) $1,194,913

Supports (6% of PEC) $1,194,913

Handling and Erection (40% of PEC) $7,966,084

Electrical (1% of PEC) $199,152

Piping (30% of PEC) $5,974,563

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

Insulation for Ductwork (1% of PEC) $199,152

Painting (1% of PEC) $199,152

Subtotal, Direct Installation Cost $17,427,929

Site Preparation N/A

Buildings N/A

Total Direct Cost $37,343,139

Indirect Costs

Engineering (10% of PEC) $1,991,521

Construction and Field Expense (10% of PEC) $1,991,521

Contractor Fees (10% of PEC) $1,991,521

Start-up (1% of PEC) $199,152

Performance Test (1% of PEC) $199,152

Contingencies (3% of PEC) $597,456

Total Indirect Cost $6,970,324

Total Capital Investment (TCI) $44,313,462

Direct Annual Costs

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

Operating Labor

Operator 2 x 3,573 hours/year, $50/hr) $357,300

Supervisor (15% of operator) $53,595

Subtotal, Operating Labor $410,895

Maintenance

Labor (2 x 820 hours/year, $50/hr) $82,000

Material (5% of Total Direct Cost) 1,867,157 $ 

Subtotal, Maintenance $1,949,157

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 $16,871,053

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $1,416,031

Administrative (2% TCI) $886,269

Property Tax (1% TCI) $443,135

Insurance (1% TCI) $443,135

Capital Recovery (15 year life, 7 percent interest) $4,865,380

Total Indirect Annual Cost $8,053,950

Conclusion

Total Annualized Cost $24,925,003

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 $2,428
Table D-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, inflated to 2012 dollars $17,317,574

Instrumentation (10% of EC) $1,731,757

Freight (5% of EC) $865,879

Subtotal, Purchased Equipment Cost (PEC) $19,915,210

Direct Installation Costs

Foundation (6% of PEC) $1,194,913

Supports (6% of PEC) $1,194,913

Handling and Erection (40% of PEC) $7,966,084

Electrical (1% of PEC) $199,152

Piping (30% of PEC) $5,974,563

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

Insulation for Ductwork (1% of PEC) $199,152

Painting (1% of PEC) $199,152

Subtotal, Direct Installation Cost $17,427,929

Site Preparation N/A

Buildings N/A

Total Direct Cost $37,343,139

Indirect Costs

Engineering (10% of PEC) $1,991,521

Construction and Field Expense (10% of PEC) $1,991,521

Contractor Fees (10% of PEC) $1,991,521

Start-up (1% of PEC) $199,152

Performance Test (1% of PEC) $199,152

Contingencies (3% of PEC) $597,456

Total Indirect Cost $6,970,324

Total Capital Investment (TCI) $44,313,462

Direct Annual Costs

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

Operating Labor

Operator 2 x 3,573 hours/year, $50/hr) $357,300

Supervisor (15% of operator) $53,595

Subtotal, Operating Labor $410,895

Maintenance

Labor (2 x 820 hours/year, $50/hr) $82,000

Material (5% of Total Direct Cost) 1,867,157 $ 

Subtotal, Maintenance $1,949,157

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 $16,786,914

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $1,416,031

Administrative (2% TCI) $886,269

Property Tax (1% TCI) $443,135

Insurance (1% TCI) $443,135

Capital Recovery (15 year life, 7 percent interest) $4,865,380

Total Indirect Annual Cost $8,053,950

Conclusion

Total Annualized Cost $24,840,863

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 $2,482
Table D-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, inflated to 2012 dollars $17,317,574

Instrumentation (10% of EC) $1,731,757

Freight (5% of EC) $865,879

Subtotal, Purchased Equipment Cost (PEC) $19,915,210

Direct Installation Costs

Foundation (6% of PEC) $1,194,913

Supports (6% of PEC) $1,194,913

Handling and Erection (40% of PEC) $7,966,084

Electrical (1% of PEC) $199,152

Piping (30% of PEC) $5,974,563

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

Insulation for Ductwork (1% of PEC) $199,152

Painting (1% of PEC) $199,152

Subtotal, Direct Installation Cost $17,427,929

Site Preparation N/A

Buildings N/A

Total Direct Cost $37,343,139

Indirect Costs

Engineering (10% of PEC) $1,991,521

Construction and Field Expense (10% of PEC) $1,991,521

Contractor Fees (10% of PEC) $1,991,521

Start-up (1% of PEC) $199,152

Performance Test (1% of PEC) $199,152

Contingencies (3% of PEC) $597,456

Total Indirect Cost $6,970,324

Total Capital Investment (TCI) $44,313,462

Direct Annual Costs

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

Operating Labor

Operator 2 x 3,573 hours/year, $50/hr) $357,300

Supervisor (15% of operator) $53,595

Subtotal, Operating Labor $410,895

Maintenance

Labor (2 x 820 hours/year, $50/hr) $82,000

Material (5% of Total Direct Cost) 1,867,157 $ 

Subtotal, Maintenance $1,949,157

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 $17,411,873

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $1,416,031

Administrative (2% TCI) $886,269

Property Tax (1% TCI) $443,135

Insurance (1% TCI) $443,135

Capital Recovery (15 year life, 7 percent interest) $4,865,380

Total Indirect Annual Cost $8,053,950

Conclusion

Total Annualized Cost $25,465,823

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 $2,139
Table D-5. Fuel Substitution Control Cost Analysis Based on Projected Actual Emissions and 23% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill I.D. Fan and associated equipment $2,000,000

Instrumentation (10% of EC) $200,000

Freight (5% of EC) $100,000

Subtotal, Purchased Equipment Cost (PEC) $2,300,000

Direct Installation Costs

Foundation (6% of PEC) $138,000

Supports (6% of PEC) $138,000

Handling and Erection (40% of PEC) $920,000

Electrical (1% of PEC) $23,000

Piping (30% of PEC) $690,000

Insulation for Ductwork (1% of PEC) $1,000

Painting (1% of PEC) $23,000

Subtotal, Direct Installation Cost $1,933,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $4,233,000

Indirect Costs

Engineering (10% of PEC) $230,000

Construction and Field Expense (10% of PEC) $230,000

Contractor Fees (10% of PEC) $230,000

Start-up (1% of PEC) $23,000

Performance Test (1% of PEC) $23,000

Contingencies (3% of PEC) $69,000

Total Indirect Cost $805,000

Total Capital Investment (TCI) $5,038,000

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) 198,736 

Changes in Synfuel and Tires have not been considered due to the

 highly variable nature of their cost

Cost of low sulfur coal ($/Mt) $72.76

Subtotal, increase in Low Sulfur Coal cost $14,459,211

Total Direct Annual Cost (increase) $3,178,351

Indirect Annual Costs

Administrative (2% TCI) $100,760

Property Tax (1% TCI) $50,380

Insurance (1% TCI) $50,380

Capital Recovery (15 year life, 7 percent interest) $553,145

Total Indirect Annual Cost $754,665

Conclusion

Total Annualized Cost $3,933,016

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

Pollutant Removed (tons SO2/yr) - 23% 2,641

Cost Per Ton of Pollutant Removed $1,489
Table D-6. Fuel Substitution Control Cost Analysis Based on Projected Actual Emissions and 40% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $5,374,302

Instrumentation (10% of EC) $537,430

Freight (5% of EC) $268,715

Subtotal, Purchased Equipment Cost (PEC) $6,180,447

Direct Installation Costs

Foundation (6% of PEC) $370,827

Supports (6% of PEC) $370,827

Handling and Erection (40% of PEC) $2,472,179

Electrical (1% of PEC) $61,804

Piping (30% of PEC) $1,854,134

Insulation for Ductwork (1% of PEC) $2,687

Painting (1% of PEC) $61,804

Subtotal, Direct Installation Cost $5,194,263

Site Preparation N/A

Buildings N/A

Total Direct Cost $11,374,710

Indirect Costs

Engineering (10% of PEC) $618,045

Construction and Field Expense (10% of PEC) $618,045

Contractor Fees (10% of PEC) $618,045

Start-up (1% of PEC) $61,804

Performance Test (1% of PEC) $61,804

Contingencies (3% of PEC) $185,413

Total Indirect Cost $2,163,157

Total Capital Investment (TCI) $13,537,867

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) $270,757

Property Tax (1% TCI) $135,379

Insurance (1% TCI) $135,379

Capital Recovery (15 year life, 7 percent interest) $1,486,385

Total Indirect Annual Cost $2,027,900

Conclusion

Total Annualized Cost $27,218,156

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 $5,927
Table D-7. Fuel Substitution Control Cost Analysis Based on Projected Actual Emissions and 50% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $5,374,302

Instrumentation (10% of EC) $537,430

Freight (5% of EC) $268,715

Subtotal, Purchased Equipment Cost (PEC) $6,180,447

Direct Installation Costs

Foundation (6% of PEC) $370,827

Supports (6% of PEC) $370,827

Handling and Erection (40% of PEC) $2,472,179

Electrical (1% of PEC) $61,804

Piping (30% of PEC) $1,854,134

Insulation for Ductwork (1% of PEC) $2,687

Painting (1% of PEC) $61,804

Subtotal, Direct Installation Cost $5,194,263

Site Preparation N/A

Buildings N/A

Total Direct Cost $11,374,710

Indirect Costs

Engineering (10% of PEC) $618,045

Construction and Field Expense (10% of PEC) $618,045

Contractor Fees (10% of PEC) $618,045

Start-up (1% of PEC) $61,804

Performance Test (1% of PEC) $61,804

Contingencies (3% of PEC) $185,413

Total Indirect Cost $2,163,157

Total Capital Investment (TCI) $13,537,867

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) $270,757

Property Tax (1% TCI) $135,379

Insurance (1% TCI) $135,379

Capital Recovery (15 year life, 7 percent interest) $1,486,385

Total Indirect Annual Cost $2,027,900

Conclusion

Total Annualized Cost $27,218,156

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 $4,741
Table D-8. Fuel Substitution Control Cost Analysis Based on PTE and 23% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill I.D. Fan and associated equipment $2,000,000

Instrumentation (10% of EC) $200,000

Freight (5% of EC) $100,000

Subtotal, Purchased Equipment Cost (PEC) $2,300,000

Direct Installation Costs

Foundation (6% of PEC) $138,000

Supports (6% of PEC) $138,000

Handling and Erection (40% of PEC) $920,000

Electrical (1% of PEC) $23,000

Piping (30% of PEC) $690,000

Insulation for Ductwork (1% of PEC) $1,000

Painting (1% of PEC) $23,000

Subtotal, Direct Installation Cost $1,933,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $4,233,000

Indirect Costs

Engineering (10% of PEC) $230,000

Construction and Field Expense (10% of PEC) $230,000

Contractor Fees (10% of PEC) $230,000

Start-up (1% of PEC) $23,000

Performance Test (1% of PEC) $23,000

Contingencies (3% of PEC) $69,000

Total Indirect Cost $805,000

Total Capital Investment (TCI) $5,038,000

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) 198,736 

Changes in Synfuel and Tires have not been considered due to the

 highly variable nature of their cost

Cost of low sulfur coal ($/Mt) $72.76

Subtotal, increase in Low Sulfur Coal cost $14,459,211

Total Direct Annual Cost (increase) $3,178,351

Indirect Annual Costs

Administrative (2% TCI) $100,760

Property Tax (1% TCI) $50,380

Insurance (1% TCI) $50,380

Capital Recovery (15 year life, 7 percent interest) $553,145

Total Indirect Annual Cost $754,665

Conclusion

Total Annualized Cost $3,933,016

Pollutant Emission Rate Prior to Scrubber (tons SO2/yr) 13,298

Pollutant Removed (tons SO2/yr) - 23% 3,059

Cost Per Ton of Pollutant Removed $1,286
Table D-9. Fuel Substitution Control Cost Analysis Based on PTE and 40% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $5,374,302

Instrumentation (10% of EC) $537,430

Freight (5% of EC) $268,715

Subtotal, Purchased Equipment Cost (PEC) $6,180,447

Direct Installation Costs

Foundation (6% of PEC) $370,827

Supports (6% of PEC) $370,827

Handling and Erection (40% of PEC) $2,472,179

Electrical (1% of PEC) $61,804

Piping (30% of PEC) $1,854,134

Insulation for Ductwork (1% of PEC) $2,687

Painting (1% of PEC) $61,804

Subtotal, Direct Installation Cost $5,194,263

Site Preparation N/A

Buildings N/A

Total Direct Cost $11,374,710

Indirect Costs

Engineering (10% of PEC) $618,045

Construction and Field Expense (10% of PEC) $618,045

Contractor Fees (10% of PEC) $618,045

Start-up (1% of PEC) $61,804

Performance Test (1% of PEC) $61,804

Contingencies (3% of PEC) $185,413

Total Indirect Cost $2,163,157

Total Capital Investment (TCI) $13,537,867

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) $270,757

Property Tax (1% TCI) $135,379

Insurance (1% TCI) $135,379

Capital Recovery (15 year life, 7 percent interest) $1,486,385

Total Indirect Annual Cost $2,027,900

Conclusion

Total Annualized Cost $27,218,156

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 $5,117
Table D-10. Fuel Substitution Control Cost Analysis Based on PTE and 50% Control .

Direct Costs

Purchased Equipment Costs

New Coal Mill and associated equipment $5,374,302

Instrumentation (10% of EC) $537,430

Freight (5% of EC) $268,715

Subtotal, Purchased Equipment Cost (PEC) $6,180,447

Direct Installation Costs

Foundation (6% of PEC) $370,827

Supports (6% of PEC) $370,827

Handling and Erection (40% of PEC) $2,472,179

Electrical (1% of PEC) $61,804

Piping (30% of PEC) $1,854,134

Insulation for Ductwork (1% of PEC) $2,687

Painting (1% of PEC) $61,804

Subtotal, Direct Installation Cost $5,194,263

Site Preparation N/A

Buildings N/A

Total Direct Cost $11,374,710

Indirect Costs

Engineering (10% of PEC) $618,045

Construction and Field Expense (10% of PEC) $618,045

Contractor Fees (10% of PEC) $618,045

Start-up (1% of PEC) $61,804

Performance Test (1% of PEC) $61,804

Contingencies (3% of PEC) $185,413

Total Indirect Cost $2,163,157

Total Capital Investment (TCI) $13,537,867

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) $270,757

Property Tax (1% TCI) $135,379

Insurance (1% TCI) $135,379

Capital Recovery (15 year life, 7 percent interest) $1,486,385

Total Indirect Annual Cost $2,027,900

Conclusion

Total Annualized Cost $27,218,156

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 $4,094
Table D -11. 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 (10% of EC) $400,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $4,600,000

Direct Installation Costs

Foundation (6% of PEC) $276,000

Supports (6% of PEC) $276,000

Handling and Erection (40% of PEC) $1,840,000

Electrical (1% of PEC) $46,000

Piping (30% of PEC) $0

Insulation for Ductwork (1% of PEC) $2,000

Painting (1% of PEC) $0

Subtotal, Direct Installation Cost $2,440,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $7,040,000

Indirect Costs

Engineering (10% of PEC) $460,000

Construction and Field Expense (10% of PEC) $460,000

Contractor Fees (10% of PEC) $460,000

Start-up (1% of PEC) $46,000

Performance Test (1% of PEC) $46,000

Contingencies (3% of PEC) $138,000

Total Indirect Cost $1,610,000

Total Capital Investment (TCI) $8,650,000

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. 352,000 $ 

Subtotal, Maintenance $360,760

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 $13,206,900

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $222,500

Administrative (2% TCI) $173,000

Property Tax (1% TCI) $86,500

Insurance (1% TCI) $86,500

Capital Recovery (15 year life, 7 percent interest) $949,724

Total Indirect Annual Cost $1,518,224

Conclusion

Total Annualized Cost $14,725,124

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 $6,750
Table D-12. 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 (10% of EC) $400,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $4,600,000

Direct Installation Costs

Foundation (6% of PEC) $276,000

Supports (6% of PEC) $276,000

Handling and Erection (40% of PEC) $1,840,000

Electrical (1% of PEC) $46,000

Piping (30% of PEC) $0

Insulation for Ductwork (1% of PEC) $2,000

Painting (1% of PEC) $0

Subtotal, Direct Installation Cost $2,440,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $7,040,000

Indirect Costs

Engineering (10% of PEC) $460,000

Construction and Field Expense (10% of PEC) $460,000

Contractor Fees (10% of PEC) $460,000

Start-up (1% of PEC) $46,000

Performance Test (1% of PEC) $46,000

Contingencies (3% of PEC) $138,000

Total Indirect Cost $1,610,000

Total Capital Investment (TCI) $8,650,000

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. 352,000 $ 

Subtotal, Maintenance $360,760

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 $13,206,900

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $222,500

Administrative (2% TCI) $173,000

Property Tax (1% TCI) $86,500

Insurance (1% TCI) $86,500

Capital Recovery (15 year life, 7 percent interest) $949,724

Total Indirect Annual Cost $1,518,224

Conclusion

Total Annualized Cost $14,725,124

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 $4,500
Table D-13. 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 (10% of EC) $400,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $4,600,000

Direct Installation Costs

Foundation (6% of PEC) $276,000

Supports (6% of PEC) $276,000

Handling and Erection (40% of PEC) $1,840,000

Electrical (1% of PEC) $46,000

Piping (30% of PEC) $0

Insulation for Ductwork (1% of PEC) $2,000

Painting (1% of PEC) $0

Subtotal, Direct Installation Cost $2,440,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $7,040,000

Indirect Costs

Engineering (10% of PEC) $460,000

Construction and Field Expense (10% of PEC) $460,000

Contractor Fees (10% of PEC) $460,000

Start-up (1% of PEC) $46,000

Performance Test (1% of PEC) $46,000

Contingencies (3% of PEC) $138,000

Total Indirect Cost $1,610,000

Total Capital Investment (TCI) $8,650,000

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. 352,000 $ 

Subtotal, Maintenance $360,760

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 $15,238,355

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $222,500

Administrative (2% TCI) $173,000

Property Tax (1% TCI) $86,500

Insurance (1% TCI) $86,500

Capital Recovery (15 year life, 7 percent interest) $949,724

Total Indirect Annual Cost $1,518,224

Conclusion

Total Annualized Cost $16,756,579

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 $6,632
Table D-14. 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 (10% of EC) $400,000

Freight (5% of EC) $200,000

Subtotal, Purchased Equipment Cost (PEC) $4,600,000

Direct Installation Costs

Foundation (6% of PEC) $276,000

Supports (6% of PEC) $276,000

Handling and Erection (40% of PEC) $1,840,000

Electrical (1% of PEC) $46,000

Piping (30% of PEC) $0

Insulation for Ductwork (1% of PEC) $2,000

Painting (1% of PEC) $0

Subtotal, Direct Installation Cost $2,440,000

Site Preparation N/A

Buildings N/A

Total Direct Cost $7,040,000

Indirect Costs

Engineering (10% of PEC) $460,000

Construction and Field Expense (10% of PEC) $460,000

Contractor Fees (10% of PEC) $460,000

Start-up (1% of PEC) $46,000

Performance Test (1% of PEC) $46,000

Contingencies (3% of PEC) $138,000

Total Indirect Cost $1,610,000

Total Capital Investment (TCI) $8,650,000

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. 352,000 $ 

Subtotal, Maintenance $360,760

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 $15,238,355

Indirect Annual Costs

Overhead (60% of sum of operating, supervisor, maintenance labor & materials) $222,500

Administrative (2% TCI) $173,000

Property Tax (1% TCI) $86,500

Insurance (1% TCI) $86,500

Capital Recovery (15 year life, 7 percent interest) $949,724

Total Indirect Annual Cost $1,518,224

Conclusion

Total Annualized Cost $16,756,579

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 $4,421
Table D-15. Mid Kiln Firing Control Cost Analysis Based on PA and 20% Control.

Direct Costs

Purchased Equipment Costs

MKF System $1,576,009

Instrumentation (10% of EC) $157,601

Freight (5% of EC) $78,800

Subtotal, Purchased Equipment Cost (PEC) $1,812,410

Direct Installation Costs

Foundation (6% of PEC) $108,745

Supports (6% of PEC) $108,745

Handling and Erection (40% of PEC) $724,964

Electrical (1% of PEC) $18,124

Piping (30% of PEC) $543,723

Insulation for Ductwork (1% of PEC) $788

Painting (1% of PEC) $18,124

Subtotal, Direct Installation Cost $1,523,213

Site Preparation N/A

Buildings N/A

Total Direct Cost $3,335,623

Indirect Costs

Engineering (10% of PEC) $181,241

Construction and Field Expense (10% of PEC) $181,241

Contractor Fees (10% of PEC) $181,241

Start-up (1% of PEC) $18,124

Performance Test (1% of PEC) $18,124

Contingencies (3% of PEC) $54,372

Total Indirect Cost $634,344

Total Capital Investment (TCI) $3,969,967

Direct Annual Costs

Ideally, alternative fuels will cost less than current fuels, such that there is either a reduction in fuel cost or 

no net increase in fuel cost such that the direct annual cost of the system is zero

Indirect Annual Costs

Administrative (2% TCI) $79,399

Property Tax (1% TCI) $39,700

Insurance (1% TCI) $39,700

Capital Recovery (15 year life, 7 percent interest) $435,881

Total Indirect Annual Cost $594,680

Conclusion

Total Annualized Cost $594,680

Pollutant Emission Rate Prior to MKF (tons NOx/yr) 6,414

Pollutant Removed (tons NOx/yr) - 20% 1,283

Cost Per Ton of Pollutant Removed $464
Table D-16. Mid Kiln Firing Control Cost Analysis Based on PTE and 20% Control.

Direct Costs

Purchased Equipment Costs

MKF System $1,576,009

Instrumentation (10% of EC) $157,601

Freight (5% of EC) $78,800

Subtotal, Purchased Equipment Cost (PEC) $1,812,410

Direct Installation Costs

Foundation (6% of PEC) $108,745

Supports (6% of PEC) $108,745

Handling and Erection (40% of PEC) $724,964

Electrical (1% of PEC) $18,124

Piping (30% of PEC) $543,723

Insulation for Ductwork (1% of PEC) $788

Painting (1% of PEC) $18,124

Subtotal, Direct Installation Cost $1,523,213

Site Preparation N/A

Buildings N/A

Total Direct Cost $3,335,623

Indirect Costs

Engineering (10% of PEC) $181,241

Construction and Field Expense (10% of PEC) $181,241

Contractor Fees (10% of PEC) $181,241

Start-up (1% of PEC) $18,124

Performance Test (1% of PEC) $18,124

Contingencies (3% of PEC) $54,372

Total Indirect Cost $634,344

Total Capital Investment (TCI) $3,969,967

Direct Annual Costs

Ideally, alternative fuels will cost less than current fuels, such that there is either a reduction in fuel cost or 

no net increase in fuel cost such that the direct annual cost of the system is zero

Indirect Annual Costs

Administrative (2% TCI) $79,399

Property Tax (1% TCI) $39,700

Insurance (1% TCI) $39,700

Capital Recovery (15 year life, 7 percent interest) $435,881

Total Indirect Annual Cost $594,680

Conclusion

Total Annualized Cost $594,680

Pollutant Emission Rate Prior to MKF (tons NOx/yr) 8,462

Pollutant Removed (tons NOx/yr) - 20% 1,692

Cost Per Ton of Pollutant Removed $351