## Appendix O

Holcim-Clarksville BART Analysis
June 12, 2008

## BART F IVE 

## F ACTOR 

## A NALYSIS 

##  H OLCIM 

## (US) I NC 

## C LARKSVILLE 

## , M ISSOURI

Prepared by:

T RINITY C ONSULTANTS 9777 Ridge Drive Suite 380 Lenexa, Kansas 66219 (913) 894-4500

June 12, 2008

Project 081701.0004Holcim (US) Inc. i Trinity Consultants BART Analysis 

## T ABLE OF 

## C ONTENTS



### 1. E XECUTIVE 

### S UMMARY 

### ........................................................................................ 1-1

2. I NTRODUCTION AND 

### B ACKGROUND 

### .................................................................... 2-1

3. BART A PPLICABILITY 

### D ETERMINATION 

### ........................................................... 3-1

4. SO 2 

### BART E VALUATION 

### .................................................................................... 4-1 4.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES 

### .......... 4-1 4.2 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### SO 2 

### C ONTROL 

### T ECHNOLOGIES 

### ................ 4-2
4.2.1 F UEL S UBSTITUTION ...........................................................................................4-2 4.2.2 R AW M ATERIAL S UBSTITUTION / S ELECTIVE M INING .......................................4-4 4.2.3 D RY L IME I NJECTION /D RY L IME S CRUBBING ....................................................4-5 4.2.4 W ET L IME S CRUBBING .......................................................................................4-6 

### 4.3 R ANK OF 

### T ECHNICALLY 

### F EASIBLE 

### SO 2 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### .. 4-7 4.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### SO 2 

### C ONTROLS 

### ..................................... 4-7
4.4.1 W ET L IME S CRUBBING .......................................................................................4-8 4.4.2 F UEL S UBSTITUTION .........................................................................................4-10 4.4.3 D RY L IME S CRUBBING ......................................................................................4-12 

### 4.5 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### SO 2 

### C ONTROLS 

### .................... 4-13 4.6 P ROPOSED 

### B ART FOR 

### SO 2 

### ................................................................................... 4-15

5. NO X 

### BART E VALUATION 

### ................................................................................... 5-1 5.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### ......... 5-1 5.2 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### ............... 5-2 5.2.1 L OW -NO X B URNER IN THE R OTARY K ILN .........................................................5-2
5.2.2 F LUE G AS R ECIRCULATION ................................................................................5-2 5.2.3 C EMENT K ILN D UST I NSUFFLATION ...................................................................5-3 5.2.4 M ID -K ILN F IRING OF S OLID F UEL WITH M IXING A IR F AN .................................5-3 5.2.5 S ELECTIVE N ONCATALYTIC R EDUCTION ............................................................5-5 5.2.6 S ELECTIVE C ATALYTIC R EDUCTION ...................................................................5-8 

### 5.3 R ANK OF 

### T ECHNICALLY FEASIBLE 

### NO X 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### .. 5-9 5.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### NO X 

### C ONTROLS 

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

### 5.5 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### NO X 

### C ONTROLS 

### ................... 5-10 5.6 P ROPOSED 

### B ART FOR 

### NO X 

### .................................................................................. 5-11

6. BART S UMMARY 

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

### A PPENDIX 

### A. C OAL 

### C OMPOSITION 

### D ATA



### A PPENDIX 

### B. R EVIEW OF THE 

### P OTENTIAL FOR 

### P LUME 

### O PACITY 

### E XCEEDANCES 

### R ESULTING FROM THE 

### U SE OF A 

### W ET 

### S CRUBBER



### A PPENDIX 

### C. S ELECTIVE 

### M INING



### – Q UARRY 

### S CHEDULING 

### O PTIMIZATION 

### D ISCUSSION



### A PPENDIX 

### D. BART C ONTROL 

### C OST 

### T ABLESHolcim (US) Inc. iii Trinity Consultants BART Analysis 

## L IST OF 

## T ABLES

T ABLE 1-1. V ISIBILITY I MPAIRMENT I MPROVEMENT ..........................................................................1-2

T ABLE 3-1. M ODELED 24-H OUR E MISSIONS (A S AN H OURLY E QUIVALENT )....................................3-1

T ABLE 3-2. S UMMARY OF S TACK P ARAMETERS ................................................................................3-1

T ABLE 3-3. S UMMARY OF 98 TH P ERCENTILE V ISIBILITY I MPACTS AND N UMBER OF D AYS WITH V ISIBILITY I MPACT G REATER THAN 0.5 Δ DV .........................................................................3-2

T ABLE 3-4. B REAKDOWN OF P OLLUTANT S PECIFIC C ONTRIBUTIONS TO V ISIBILITY FOR THE 98 TH
P ERCENTILE D AY . ..................................................................................................................3-2

T ABLE 4-1. E XISTING A CTUAL M AXIMUM 24-H OUR SO 2 E MISSION R ATES ......................................4-1

TABLE 4-2. A VAILABLE SO 2 C ONTROL T ECHNOLOGIES .....................................................................4-1

T ABLE 4-3. R ANKING OF T ECHNICALLY F EASIBLE K ILN SO 2 C ONTROL T ECHNOLOGIES BY E FFECTIVENESS ......................................................................................................................4-7

T ABLE 4-4. C OST A NALYSIS S UMMARY FOR W ET L IME S CRUBBING ................................................4-9

T ABLE 4-5. C OST A NALYSIS S UMMARY FOR F UEL S UBSTITUTION ..................................................4-11

T ABLE 4-6. C OST A NALYSIS S UMMARY FOR D RY L IME S CRUBBING ..............................................4-13

T ABLE 4-7. S UMMARY OF E MISSION R ATES M ODELED I N SO 2 C ONTROL V ISIBILITY I MPACT A NALYSIS .............................................................................................................................4- 14

T ABLE 4-8. S UMMARY OF M ODELED I MPACTS FROM SO 2 C ONTROL V ISIBILITY I MPACT A NALYSIS 4-14

T ABLE 4-9. S UMMARY OF C OST E FFECTIVENESS OF SO 2 C ONTROL O PTIONS .................................4-16

T ABLE 5-1. E XISTING A CTUAL M AXIMUM 24-H OUR NO X E MISSION R ATES .....................................5-1

T ABLE 5-2. P OSSIBLE NO X C ONTROL T ECHNOLOGIES ......................................................................5-2

T ABLE 5-3. R ANKING OF T ECHNICALLY F EASIBLE K ILN NO X C ONTROL T ECHNOLOGIES BY E FFECTIVENESS ....................................................................................................................5-10

T ABLE 5-4. S UMMARY OF E MISSION R ATES M ODELED I N NO X C ONTROL V ISIBILITY I MPACT A NALYSIS .............................................................................................................................5- 11

T ABLE 5-5. NO X C ONTROL V ISIBILITY I MPACT A NALYSIS ...............................................................5-11

T ABLE 6-1. V ISIBILITY I MPAIRMENT I MPROVEMENT ..........................................................................6-1Holcim (US) Inc. 1-1 Trinity Consultants BART Analysis 

## 1. E XECUTIVE 

## S UMMARY

This report documents the determination of th e Best Available Retrofit Technology (BART) as proposed by Holcim (US) Inc. (Holcim) for th e Portland cement manufacturing plant located in Clarksville, Missouri (Clarksville plant). This analys is 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 uni ts, 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) guidelines 2 in 40 CFR Part 51 to determine BART for the kiln. Specifically, Holcim conducted a five-step analysis to determine BART for SO 2 , NOX, and PM 10 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:

• PM 10 – Holcim has determined that the existing electrostatic precipitator constitutes BART. This control device is effective for controlling PM 10 from a wet kiln.

• NO X – 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 NO X emission rate of 73,185 lbs that was used for visibility impact modeling.

• SO 2 – 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 SO 2 emission rate of 117,345 lbs that was used for visibility impact modeling.

The proposed BART control strategies will result in re ductions 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 emissi on rates is provided in Table 1-1.

1 Holcim submitted an inventory of all of the BART-elig ible emission sources to th e MDNR. Based on a review of this information, the M DNR concluded that the contributions from pa rticulate matter from the non-kiln sources to visibility impairment is negligible and further analysis of th ese smaller particulat e 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) DeterminationsHolcim (US) Inc. 1-2 Trinity Consultants BART Analysis T ABLE 1-1. V ISIBILITY I MPAIRMENT I MPROVEMENT

Mingo National Wildlife Refuge Hercules Glades Wilderness Area Upper Buffalo Wilderness Area Existing 98% Impact ( Δ dv) 1.01 0.81 0.61 BART 98% Impact ( Δ dv) 0.79 0.64 0.48 Improvement 98% Impact ( Δ dv) 22% 21% 22%Holcim (US) Inc. 2-1 Trinity Consultants BART Analysis 

## 2. I NTRODUCTION AND 

## B ACKGROUND

On July 1, 1999, the U.S. EPA published the fina l Regional Haze Rule (RHR). The objective of the RHR is to improve visibility in 156 specific area s across with United States, known as Class I areas. The Clean Air Act defines Class I areas as certain na tional 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 th e 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 98 th 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 vi sibility regulations define BART as follows:

“...an emission limitation based on the deg ree of reduction achievable through the application of the best system of continu ous emission reduction for each pollutant which is emitted by...[a BART-eligible sou rce]. The emission limitation must be established on a case-by-case basis, taking in to consideration the technology available, the cost of compliance, the energy and n on 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 controlsHolcim (US) Inc. 2-2 Trinity Consultants BART Analysis Further, the BART rule indicates that the fi ve 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 visi bility affecting pollutant (VAP) by following the five steps listed above for each VAP.

BART applicability was determined for the Clarks ville 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. Th e 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 NO
x , SO 2 , and particulate matter with a mass mean diameter smaller than ten microns (PM 10 ) of various forms (filterable coarse particulate matter [PM c ], filterable fine particle matter [PM f ], elemental carbon [EC], inorganic condensable particulate matter [IOR CPM] as sulfates [SO 4 ], and organic condensable particulate matter [OR CPM] also referred to as secondary organic aerosols [SOA]). The BART determinations for SO 2 and NO X can be found in Sections 4 and 5 respectively.Holcim (US) Inc. 3-1 Trinity Consultants BART Analysis 

## 3. BART A PPLICABILITY 

## D ETERMINATION

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 impa irment in any federal mandated Class I area.” EPA has determined that a source is reasonably anticipated to contribute to visibility impairment if the 98 th 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 Cl arksville 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 98 th percentile of the visibility impacts attributable to the kiln are greater than 0.5 Δ dv 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 orig inal modeling. Table 3-1 summarizes the emission rates that were modeled for SO 2 , NO X , and PM 10 3 . The SO 2 and NO
x emission rates are the highest actual 24-hour emission rates based on 2003-2007 con tinuous emissions monitoring system (CEMS) data. The PM 10 emission rates are based on data included in Holcim’s BART survey.

T ABLE 3-1. M ODELED 24-H OUR E MISSIONS (A S AN H OURLY E QUIVALENT )

SO 2 NO X Total PM 10 (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.

T ABLE 3-2. S UMMARY OF S TACK P ARAMETERS

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 98 th percentile of the visibility impacts are greater than 0.5 Δ dv when compared against a natural background. Since the visibility impacts are greater than 0.5 Δ dv, the kiln is subject to BART. The results of the modeling are summarized in Table 3-3.

3 The non-kiln PM 10 emissions were included in the model as part of the kiln PM 10 emissions.Holcim (US) Inc. 3-2 Trinity Consultants BART Analysis

T ABLE 3-3. S UMMARY OF 98 TH P ERCENTILE V ISIBILITY I MPACTS AND N UMBER OF D AYS WITH V ISIBILITY I MPACT G REATER THAN 0.5 Δ DV

Visibility Impairment

Class I Area 98th % Δ dv Days > 0.5 Δ dv 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 (98 th 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).

T ABLE 3-4. B REAKDOWN OF P OLLUTANT S PECIFIC C ONTRIBUTIONS TO V ISIBILITY
FOR THE 98 TH P ERCENTILE D AY

.

Visibility Impairment Attributable

to SO 4 Visibility Impairment Attributable

to NO 3 Visibility Impairment Attributable

to SOA Visibility Impairment Attributable to EC Visibility Impairment Attributable

to PM c Visibility Impairment Attributable

to PM f Total Visibility Impairment

Class I Area (%) (%) (%) (%) (%) (%) ( Δ dv ) 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 (SO 4 ) and nitrates (NO 3 ). The SO 4 contribution is from the chemical conversion of SO 2 emitted by the kiln to SO 4 . The NO 3 contribution is entirely from the chemical conversion of NO X emitted from the kiln. The contribution of PM 10 to the total visibility impairme nt can be estimated as the sum of the contributions from SOA, EC, PMc, and PMf. The PM 10 contribution is much smaller (<1%) than the contribution from SO 2 and NO X .Holcim (US) Inc. 4-1 Trinity Consultants BART Analysis 

## 4. SO 2 

## BART E VALUATION

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 materi als, and in-process materials, such as the alkali metals (sodium and potassium), calcium carbonate, and calcium oxide react with SO 2 formed in the pyroprocess and much of the sulfur leaves the pro cess in the principle product of the kiln system called clinker.

The kiln is the only BART source which emits SO 2 , thus an SO 2 BART evaluation was performed only for the kiln. The maximum actual 24-hour kiln SO 2 emission rate that was modeled for the BART applicability determination is summarized in Table 4-1.

T ABLE 4-1. E XISTING A CTUAL M AXIMUM 24-H OUR SO 2 E MISSION R ATES

SO 2 24-Hour Emission Rate SO 2 Hourly Equivalent Emission Rate ton/24-hr lb/hr
Kiln 58.67 4889.38



## 4.1 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## SO 2 

## C ONTROL 

## T ECHNOLOGIES

Step 1 of the BART determination is the identification of all available retrofit SO 2 control technologies. A list of control technologies was obtained by reviewing the U.S. EPA’s Clean Air Technology Center, publicly-availabl e air permits, applications, and technical literature published by the U.S. EPA, state agencies, and Regional Planning Organizations (RPOs).

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

TABLE 4-2. A VAILABLE SO 2 C ONTROL T ECHNOLOGIES

SO 2 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 Dioxi de from the Portland Cement Industry”, Proceedings of the Air and Wa ste Management Association , June 18-22, 2000.Holcim (US) Inc. 4-2 Trinity Consultants BART Analysis 

## 4.2 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## SO 2 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible SO 2 control technologies that were identified in Step 1.



### 4.2.1 F UEL 

### S UBSTITUTION
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 syst em is such that some of the SO 2 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 SO 2 emissions from the kiln would be expected. Holcim contacted fuel suppliers and found a low sulfur PRB 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 reject ed for high chlorine content. For example, a 1.0 percent sulfur source was found but the chlo rine content was 1.3 percent (the mine has recently shut down as well), another mine had co al 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 repor ted as having a chlorine content of 0.05 percent which is preferable (Note that the 2007 aver age 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 ve ry likely cause visible plumes/opacity issues as further described in Appendix B.

Determining the specific reduction in SO 2 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 materi als (pyrites) and the sulfur exits the kiln system in the product (clinker), the cement kiln dust (CKD), and out the stack as SO 2
. Further, although the sulfur in the clinker is small on a percentage basis, the magnitude of the clinker production is extremely large (g reater than 1 million tons per year). Consequently, small changes in the amount of sulfur absorbed in the product can dramatically change the amount of SO 2 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 ch anges in kiln operating parameters, such as kiln burning temperature, kiln excess Oxyge n, etc. These changes can have a strong impact on the sulfur absorbed in the clinker and CKD and hence on SO 2 emissions. These operating conditions can also strongly change how the fuel sulfur affects SO 2 emissions. Reviewing the data yields that there is no linear correlation between fuel sulfur and SO 2Holcim (US) Inc. 4-3 Trinity Consultants BART Analysis emissions. Although these parameters were continuously monitored and controlled, to calculate an SO 2 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 SO 2 in the stack.

Low Sulfur PRB Coal – 0.7 percent sulfur Based on the 2007 data, if all of the current co al 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. Following is a summary of the sulfur input reduction from the use of low sulfur coal. The low sulfur PRB 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 PRB coal is needed than coke reduced.

Current – 2007 Average Coke Usage: 160,915 metric tons Low Heat Content 32.510 Gj/Mt Sulfur Content: 5.72 % Sulfur Input from Coke: 9,204 metric tons

Current Coal Usage: 9,432 metric tons Low Heat Content 22.177 Gj/Mt Sulfur Content: 3.45 % Sulfur Input from Coal: 325 metric tons

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

Low Sulfur PRB 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 metr ic tons = 8,070 metric tons = 8,893 tons

The SO 2 reduction calculation, based on the calculated sulfur reduction, is very complicated. The pyrite sulfur from the ra w materials can volatilize at relatively low temperatures in the kiln, in an area where the su lfur comes in contact with the kiln feed that has only minimally been calcined into CaO. C onsequently, less of this sulfur reacts with the CaO and thus is emitted. Again, if th e sulfur reacted with the CaO, it would be absorbed into the clinker and CKD. The fuel sulfur, on the other hand, enters the kiln inHolcim (US) Inc. 4-4 Trinity Consultants BART Analysis 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 SO 2 emissions that can be used to confidently calculate an SO 2 reduction.

The fuel sulfur reduction of 8,893 tons corr esponds 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 SO 2 , while SO 2 emitted from the pyrite in the raw materials has less of a chance of being absorb ed, so there is not a directly proportional reduction in SO 2 with the sulfur reduction from the fuels, nor with the total sulfur reduction. Holcim estimates that based on the year 2007 data, the actual SO 2 reduction is about 40% - 50%.

Regional Coal – 3.0 percent. Using calculation methods similar to the low su lfur PRB coal case, a scenario that included replacing the current coal/coke with a 3.0 percen t coal was evaluated. This scenario results in a sulfur input reduction of approximately 28 percent. Holcim estimates that the actual SO 2 reduction from this fuel switch would be approximately 20 - 25 percent.

These reductions are the maximum reductions in tons of SO 2 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 SO 2 for 3.0 percent sulfur coal would be 20-25 percent and for low sulfur PRB coal would be in the range of 40 percent to 50 percent.

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



### 4.2.2 R AW 

### M ATERIAL 

### S UBSTITUTION 

### / S ELECTIVE 

### M INING
In a long wet kiln, not only the pyritic sulfur, but total sulfur in the raw materials will have an impact on SO 2 emissions.

Part of the pyritic sulfur reacts with oxygen and forms SO 2 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 SO 2 is volatized. Some of this SO 2 will pass the length of the kiln without bei ng absorbed and will thus be emitted to the stack.

Using raw materials with lower sulfur content can reduce the potential for SO 2 emissions from a wet kiln system. The limestone, shal e, and other raw materials used at the Clarksville plant contain pyrites and total sulf ur in varying concentrations. If zones or layers in the on-site quarry could be identifie d and mined selectively such that lower sulfur content materials are used, the emission rate of SO 2 could theoretically be reduced.

The Clarksville Quarry Scheduling Optimization (QSO) Model was created specifically for predicting relevant mineralogical parameters related to cli nker 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 co mponents was never inte nded to be adequateHolcim (US) Inc. 4-5 Trinity Consultants BART Analysis for the accurate prediction of minor components, such as sulfur and sulfur compounds (See Appendix C for additional discussions on selec tive mining limitations based on Holcim’s QSO (Quarry Scheduling Optimization) computer model).

Based on the lack of available data to predic t if selective mining would be feasible, Holcim has concluded that selective mining is not considered a technically feasible SO 2 control technology for the kiln.



### 4.2.3 D RY 

### L IME 

### I NJECTION 

### /D RY 

### L IME 

### S CRUBBING

Dry Lime Injection, or Dry Lime Scrubbing (D LS), consists of injecting hydrated lime, Ca(OH) 2 , into the flue gas. The Ca(OH) 2 reacts with SO 2 in the flue gas stream to create fine particles of CaSO 3 or CaSO 4 . 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 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. C onsequently, very little data exists to directly quantify the feasibility or benefit (emission reduction) of such a system. Regardless, Holcim is considering the technol ogy 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 locati on, 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 th e 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 SO 2 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 approxi mately 30 percent, which is the lowest reduction level over the temperature range presented.Holcim (US) Inc. 4-6 Trinity Consultants BART Analysis



### F IGURE 

### 4-1. SO 2 

### R EDUCTION VERSUS 

### R EACTION 

### T EMPERATURE FOR 

### H YDRATED 

### L IME

The molar ratio of lime (calcium source) to SO 2 is much higher than in a typical coal fired boiler due to a number of factors, some of which include the higher CO 2 and dust levels in the cement kiln system exhaust. The CO 2 competes with SO 2 ,in the reaction with the lime, and the higher dust loading reduces the even dist ribution of the lime in the gas. Based on a communication with the Obourg plant in Belg ium, a molar ratio of between 4:1 and 6:1 has been used. The larger size of the Clarksv ille 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 tec hnically feasible and will consider it further.



### 4.2.4 W ET 

### L IME 

### S CRUBBING

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 CaCO 3 (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. U se of the cement kiln dust as a scrubbing reagent was not considered as a viable opti on 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 SO 2 reacts with the scrubbing reagent to form CaSO 3 .H 2 0 or gypsum that is collected and retained as aqueous sludge. The sludge is either dewatered and disposed of or used as synthetic gypsum.Holcim (US) Inc. 4-7 Trinity Consultants BART Analysis The scrubbing efficiency of WLS can vary from an estimated 80 percent to 95 percent of the SO 2 in the flue gas treated by the scrubber 5 . Further, WLS is a high maintenance process with high rates of downtime expected fro m 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. Fu rther, 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 R ANK OF 

## T ECHNICALLY 

## F EASIBLE 

## SO 2 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to effectiveness. Table 4-3 provides the effectiven ess of each technology in the form of an annual average efficiency.

T ABLE 4-3. R ANKING OF T ECHNICALLY F EASIBLE K ILN SO 2 C ONTROL T ECHNOLOGIES BY E FFECTIVENESS

Control Technology Effectiveness SO 2 Reduction (Percent Reduction – Annual Basis)

Wet Lime Scrubbing 80-95%
Fuel Substitution 20-50% Dry Lime Scrubbing 20-30%



## 4.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## SO 2 

## C ONTROLS

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 SO 2 control options.

5 Assessment of Control Technology Options for BART -Eligible Sources Steam Elec tric 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 Uni on, March 2005, Page 4-21, Tabl e IV-4. Range of Removal Efficiencies of Wet SO2 Scrubbers for Long Wet Kilns.Holcim (US) Inc. 4-8 Trinity Consultants BART Analysis 

### 4.4.1 W ET 

### L IME 

### S CRUBBING

Cost of Compliance Holcim utilized a recent WLS vendor bid, scaled to 2012 dollars 6 , as the basis for the economic analysis to determine the annuali zed cost for WLS. Holcim divided the annualized cost of WLS by the annual tons of SO 2 reduced to determine the cost effectiveness for WLS. The “annual tons re duced” 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 SO 2 emissions provided to the MDNR in the recent Mid Kiln Firing (MKF) permit application was 11,481 tons/year 7 . The PTE listed in the MKF permit is 13,298 tons/year. The estimated controlled annual emissions were calculated by applying an 80 percent to 95 percent control efficiency and a 95 percent control device uptime, to the projected actual annual and PTE emissions. Table 4-4 provides a summary of the cost effectiveness an alysis related to WLS. The detailed cost analysis table is provided in Appendix D.

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, 6 th 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 NH 3 , HCl, and SO 2 , sub-micron aerosols of NH 4 Cl and (NH 4 )2SO 4 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 d ilution 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

6 The most recent U.S. De partment 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. 7 The projected actual annual em ission 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. 4-9 Trinity Consultants BART Analysis condition is nearly assured. The sub-micron NH 4 Cl 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 temp erature 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 e xhaust 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 likel y be achieved using natural gas combustion. The natural gas combustion would lead to a 97 ton/year increase in NO
x emissions that would negatively impact visibility gains from the SO 2 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 l ooked at the corresponding cost of building an onsite landfill for disposal, but based on in formation provided by MDNR, the time and resources required to obtain a permit, and the additional liability associ ated with an onsite landfill, Holcim decided not to pursue that option.

WLS may also lead to an increase in PM em issions because some particles of limestone or CaSO 3 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

T ABLE 4-4. C OST A NALYSIS S UMMARY FOR W ET L IME S CRUBBING

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.

8 Innovations in Portland Cement Manufacturing, Portland Cement Association, 2004, pg. 660 & 669Holcim (US) Inc. 4-10 Trinity Consultants BART Analysis The significant increases in cost per ton of clinker produced from using WLS, as shown in Table 4-4, would likely eliminate any profit margin currently realized by the plant. Thus, it would not be economically feasible to operate the plant with WLS.

Energy Impacts A wet scrubber requires an additional fan of c onsiderable horsepower to move the flue gas through the scrubber. The exhaust gas re heat requirement will utilize approximately 1,000,000 MMcf/year of natural gas, which w ill 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 genera te over 50,000 tons per year of waste (sludge) that will require disposal in a landfill.

Remaining Useful Life The remaining useful life of the kiln does not impact the annualized cost of WLS because the useful life is anticipated to be at least as long as the capital cost recovery period, which is 15 years.



### 4.4.2 F UEL 

### S UBSTITUTION

Cost of Compliance

Low sulfur PRB coal The increased cost of using low sulfur PRB co al (0.7 percent sulfur) includes the relative increase in fuel cost as well as the cost of a ne w coal mill system. Low sulfur PRB coal is harder than the current coal/coke utilized a nd 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 dollars 9

,

Regional 3.0 percent sulfur coal The increased cost of using a regional 3.0 percent sulfur coal 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

9 The most recent U.S. De partment 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. 4-11 Trinity Consultants BART Analysis change the coal mill primary air fan and associ ated 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 SO 2
. Consequently, Holcim has chosen to not spend additional time a nd effort documenting these costs.

Table 4-5 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 P RB coal that may be required.

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

T ABLE 4-5. C OST A NALYSIS S UMMARY FOR F UEL S UBSTITUTION

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 per cent control as the average) is cost effective and will be considered further.

The low sulfur PRB coal option (40 to 50 percent control) is not cost effective and results in significant increases in cost per ton of c linker 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 PRB 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 orde r 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 equi pment 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, a nd 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.Holcim (US) Inc. 4-12 Trinity Consultants BART Analysis Energy Impacts The low sulfur PRB coal will require additional energy for grinding. The actual increase is difficult to estimate. The regional coal optio n 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 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 D RY 

### L IME 

### S CRUBBING

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 SO 2 is 11,481 tons

A molar ratio of 6:1, Ca(OH) 2 to SO 2 , is required. The Ca(OH) 2 required is calculated by multiplying by the ratio of molecular weights:

6 x 11,481 tons SO 2 x (74 ton Ca(OH) 2 / 64 SO 2 ) = 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 SO 2 is 13,298 tonsHolcim (US) Inc. 4-13 Trinity Consultants BART Analysis A molar ratio of 6:1, Ca(OH) 2 to SO 2 , is required. The Ca(OH) 2 required is calculated by multiplying by the ratio of molecular weights:

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

The estimated purity of the hydrated lime is 96.8 percent Ca(OH) 2 . Consequently, the amount required is scaled as follows:

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

Table 4-6 provides a summary of the cost eff ectiveness 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, 6 th Edition.

T ABLE 4-6. C OST A NALYSIS S UMMARY FOR D RY L IME S CRUBBING

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 4-6, would likely eliminate any profit margin currently realized by the plant. Thus, it would not be economically feasible to operate the plant with DLS.

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

Non Air-Quality Impacts Utilizing DLS could also increase the amount of CKD sent to the landfill.

Remaining Useful Life The remaining useful life of the kiln does not impact the annualized cost because the useful life is anticipated to be at least as long as the capital cost recovery period, which is 15

years.



## 4.5 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## SO 2 

## C ONTROLS

A final impact analysis was conducted to assess th e 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 cont rols, were modeled using CALPUFF. The existing emission rate is the same rate that was mode led for the BART applicability analysis. The SO 2Holcim (US) Inc. 4-14 Trinity Consultants BART Analysis emission rate associated with WLS, Fuel Substituti on, and DLS is the existing emission rates less the average anticipated control of 87.5 percent, 45 pe rcent and 23 percent, and 25 percent respectively. The emission rates are summarized in Table 4-7.

T ABLE 4-7. S UMMARY OF E MISSION R ATES M ODELED I N SO 2 C ONTROL V ISIBILITY I MPACT A NALYSIS

Emission Rate Scenario Emission Rate

SO 2 NO X PM 10 (lb/hr) (l b/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 4-8. The visibility improvement associated with the controls are also shown in Table 4-8; this value was calculated as the difference between the existing visibility impairment and the visibility impairment for the controlled emission rates as measured by the 98 th percentile modeled visibility impact.

T ABLE 4-8. S UMMARY OF M ODELED I MPACTS FROM SO 2 C ONTROL V ISIBILITY I MPACT A NALYSIS

Mingo National Wildlife Refuge Hercules Glades Wilderness Area Upper Buffalo Wilderness Area Existing 98% Impact ( Δ dv) 1.01 0.81 0.61

WLS 98% Impact ( Δ dv) 0.48 0.31 0.21 WLS Improvement 98% Impact ( Δ dv) 0.53 0.50 0.40

(45% Control) Fuel Subs. 98% Impact ( Δ dv) 0.70 0.58 0.37

Fuel Subs Improvement 98% Impact ( Δ dv) 0.31 0.23 0.24

(23% Control) Fuel Subs. 98% Impact ( Δ dv) 0.87 0.72 0.48

Fuel Subs Improvement 98% Impact ( Δ dv) 0.14 0.09 0.13

DLS 98% Impact ( Δ dv) 0.87 0.70 0.48 DLS Improvement 98% Impact ( Δ dv) 0.14 0.11 0.13Holcim (US) Inc. 4-15 Trinity Consultants BART Analysis 

## 4.6 P ROPOSED 

## B ART FOR 

## SO 2
Holcim reviewed each control optio n’s availability, as well as its cost of compliance, energy impacts, and non-air quality impacts, as well as the remaining useful life of the kiln. Table 4-9 summarizes the cost effectiveness for the controls based on the tons of SO 2 reduced and the visibility improvement in deciviews.Holcim (US) Inc. 4-16 Trinity Consultants BART Analysis T ABLE 4-9. S UMMARY OF C OST E FFECTIVENESS OF SO 2 C ONTROL O PTIONS

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 e ffectiveness perspective is provided.

** Includes 97 tons of NOx generated for WLS

Control Type WLS–PA–80% Base 98th
Percentile

Impact Controlled 98 th

Percentile

Impact 98 th Percentile Improvement 98 th

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 98 th

Percentile

Impact 98 th Percentile Improvement 98 th

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 98 th

Percentile

Impact 98 th Percentile Improvement 98 th

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 98 th

Percentile

Impact 98 th Percentile Improvement 98 th

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 $113,270,187Holcim (US) Inc. 4-17 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 PRB coal, and DLS is extremely high on a $/ton of SO 2 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 SO 2 emissions, is economically feasible and is being proposed as BART.

Holcim proposes that BART for SO 2 for the Holcim Clarksville Kiln is fuel substitution or equivalent technologies that will achieve a 23 percent reduction in the maximum daily SO 2 emission rate of 117,345 lbs.

To comply with this determination, Holcim is pr oposing an enforceable limit of 23% reduction in the maximum daily SO 2 emission rate of 117,345 lbs used for modeling visibility impairment. As documented throughout this report, fluctuations in daily kiln operations and inputs, and the uncertainty in predicting the daily absorption of sulfur in the clinker, Holcim proposes that the enforcement of the reduction be based on a 30 day rolling average.Holcim (US) Inc. 5-1 Trinity Consultants BART Analysis 

## 5. NO X 

## BART E VALUATION

In Portland cement kilns, the NO x that is generated is primarily classified into one of two categories, i.e., thermal NO x or fuel NO x 10 . Thermal NO x occurs as a result of the high-temperature oxidation of molecular nitrogen present in the combustion air. Fuel NO x 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 NO x referred to as feed NO x .

Due to the high flame temperature in the burning zone of the rotary kiln (3400 o F), NO x emissions from the kiln tend to be mainly comprised of thermal NO x . Although NO x emissions from cement kilns include both nitrogen oxide (NO) and nitrogen dioxide (NO 2 ), typically, less than 10% of the
total NO x in the flue gas is NO 2. 11

The kiln is the only BART source which emits NO
x , thus a NO
x BART evaluation was performed only for the kiln. The maximum actual 24-hour kiln NO
x emission rate that was modeled for the BART applicability determination is summarized in Table 4-1. The NO
x 24-hour maximum actual emission rate was determined from anal yzer data for November 24, 2007.

T ABLE 5-1. E XISTING A CTUAL M AXIMUM 24-H OUR NO X E MISSION R ATES

NO x 24-Hour Emission Rate NO x Hourly Equivalent Emission Rate ton/24-hr lb/hr
Kiln 36.59 (73,185 lbs) 3,049



## 5.1 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Step 1 of the BART determination is the identification of all available retrofit NO X 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 publis hed by the U.S. EPA and the RPOs.

The available retrofit NO X control technologies are summarized in Table 5-2.

10 NO x Formation and Variability in Portland Cement Kiln Systems, Penta En gineering, December 1998.
11 IBID.Holcim (US) Inc. 5-2 Trinity Consultants BART Analysis T ABLE 5-2. P OSSIBLE NO X C ONTROL T ECHNOLOGIES

Kiln Control Technologies

Low NO x Burner Flue Gas Recirculation CKD Insufflation Mid-Kiln Firing of Tires Selective Noncatalytic Reduction Selective Catalytic Reduction



## 5.2 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NO X control technologies that were identified in Step 1.



### 5.2.1 L OW 

### -NO X 

### B URNER IN THE 

### R OTARY 

### K ILN

Low NO x burners (LNBs) reduce the amount of NO
x 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 a pplied to the rotary cement kiln, the low-NO x burner creates primary and secondary combustion zones at the end of the main burner pipe to reduce the amount of NO
x 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. Th e oxygen-deficient condition at the primary combustion site minimizes thermal and fuel NO x formation and produces free radicals that chemically reduce some of the NO x that is being generated in the flame.

In the secondary zone, combustion is complete d in an oxygen-rich environment. The temperature in the secondary combustion zone is much lower than in the first; therefore, lower NO x 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-NO x burners are considered to be a technically feasible option for NO X control. As Holcim already has a LNB, the technol ogy will not be considered further.



### 5.2.2 F LUE 

### G AS 

### R ECIRCULATION

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 signifi cant 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 NO x 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 mate rials. 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 c linker 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 genera l 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 demonstra tion on a cement kiln in the United States, FGR is not a technically feasible control option for NO x control at this time.



### 5.2.3 C EMENT 

### K ILN 

### D UST 

### I NSUFFLATION

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 solid s 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 NO x . The insufflation process is somewhat counterintuitive because a basic requirement of a ce ment kiln is a very hot flame to heat the clinkering raw materials to about 2700 o F in as short a time as possible. The Clarksville plant already uses this technology and it is alr eady included in the baseline. Therefore, this option is removed from consideration for BART.



### 5.2.4 M ID 

### -K ILN 

### F IRING OF 

### S OLID 

### F UEL WITH 

### M IXING 

### A IR 

### F AN

Secondary combustion is defined as follows: a portion of the fuel is fired in a location other than the burning zone. This reduces thermal NO
x 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 a nd 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 flex ibility 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 thr ee primary components: (1) a staging arm or “feed fork,” that picks up the fuel modules a nd 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 thatHolcim (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 whic h positions the fuel models so they can be picked up by the feed fork and a mechanism fo r opening the doors so the fuel can enter the kiln. Due to rotation of the kiln, fuel can onl y be injected once per revolution from the top, as shown in Figure 5-1.



### F IGURE 

### 5-1. M ID 

### -K ILN 

### F IRING 

### S CHEMATIC 12

High-pressure air, in the range of a 2-10 percent replacement of the primary combustion air, could be injected through the shell of th e rotary kiln and into the calcining zone to where a mixing air fan mixes the air with the g as 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 NO X 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 NO X formed upstream in the kiln burning zone.

Clarksville has the largest long kiln in the wo rld. The kiln has a 7 meter diameter and a very high thermal capacity. Using whole tir es to replace 10% of total fuel consumption will require four whole tires being fed to the mi d-kiln door per kiln revolution, 12% fuel replacement would require 5 tires per revolut ion. 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 numbe r 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 overa ll reduction in NOx than anticipated.

12 NO X 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 uncerta inties, 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 w ould 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 larg e 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. However, without conducting testing, it is unknown if utilizing tires at the mid-kiln location will result in the same reduction in SO 2 emissions predicted for reductions in fuel sulfur. Consequently, a reduction in SO 2 emissions from the use of tires was not considered further.

MKF is considered to be a technically feasibl e option for NOx control. Further, Holcim has already received a construction permit th at would allow the installation of MKF, whereas other technologies would require a ne w construction permit application process, the result of which is unknown.



### 5.2.5 S ELECTIVE 

### N ONCATALYTIC 

### R EDUCTION
In the relatively narrow temperature window of 1600 to 1995°F, ammonia (NH 3 ) reacts with NO x without the need for a catalyst to form water and molecular nitrogen in accordance with the following simplified reactions.

4NO + 4NH 3 + O 2 Æ 4N 2 + 6H 2 O
2NO 2 + 4NH 3 + O 2 Æ 3N 2 + 6H 2 O

As applied to NO x control from cement kilns and other combustion sources, this technology is called selective noncatalytic reduction (SNCR). Above this temperature range, the NH 3 is oxidized to NO x thereby increasing NO x emissions. Below this temperature range, the reaction rate is too slow for completion and unreacted NH 3 may beHolcim (US) Inc. 5-6 Trinity Consultants BART Analysis emitted from the pyroprocess. This temperature window generally is available at some location within the rotary kiln. The NH 3 could be delivered to the kiln shell through the use of anhydrous NH 3 , or an aqueous solution of NH 3 (ammonium hydroxide) or urea.

A concern about application of SNCR tec hnology is the breakthrough of unreacted NH 3 as “ammonia slip” and its subsequent reaction in the atmosphere with SO 2 , sulfur trioxide (SO 3 ), hydrogen chloride (HCl) and/or chlorine (Cl 2 ) to form a detached plume of submicron particles. As NH 3 or Urea injection rates are increased, to attempt to achieve higher levels of reduction, NH 3 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 st arted, no data is available to verify this reduction is being achieved or on what averag ing 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 NH 3 slip increases as the urea injection rate increases especially when the molar ratio is more than 1.0 (i.e. the NH 3 added is more than needed for the reaction). At this level, significant amounts of NH 3 are unreacted. The plant reports achieving 20 percent NOx reduction at a 1.0 molar ratio of NH 3 /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 Comp any Montana City, Montana. Dated June 2007. Page 5-9.Holcim (US) Inc. 5-7 Trinity Consultants BART Analysis 

### F IGURE 

### 5-2. NO X 

### R EDUCTION 

### V ERSUS 

### NH3 M OLAR 

### R ATIO 

### O BSERVED AT 

### H OLCIM 

### L UMBRES 

### P LANT



### .

However, at 20 percent NOx reduction, the NH 3 slip is reported to be 10 mg/m3, while at 40 percent reduction, the NH 3 slip can be 20 – 30 mg/m 3 (a 50 percent to 100 percent increase). Based on experiences at many cement plants with SO 2 and HCl in the exhaust gas, which is also the case for the Clarksville plant, a 20 mg/Nm3 NH 3 increase would cause a severe increase in plume visibility. The Lumbres plant is also smaller than Clarksville, having a diameter of only 3.3 mete rs 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 re duce the effectiveness to an unknown degree.

NO X reductions from SNCR systems can vary considerably based on site specific conditions, most notably being the type of kiln. For example, the NO X 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 NO X reduction include:

• In a long wet kiln, the NH 3 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 NH 3 to be evenly distributed across the entire cross section of the gas stream.

• Studies have shown that in long kilns, th e gas stream can be highly stratified over the cross section. The relatively heavy CO 2 released from the raw materials tends to stay on the top and bottom of the raw material bed, while lighter O 2 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 theHolcim (US) Inc. 5-8 Trinity Consultants BART Analysis horizontal kiln system. The combination of stratification in the kiln cylinder, and less even distribution of NH 3 , compound the problem of poor contact between the
NH 3 and NO X .

• The reaction of NH 3 and NO X includes multiple steps that require O 2 . In the areas of the long kiln that are lacking in O 2 , the reaction rate is significantly lower, and thus NOx reduction is significantly lowe r relative to a well mixed gas stream.

Based on the concerns with NH 3 slip at high molar ratios, and the uncertainty regarding the level of effectiveness of the reagent in Clarks ville’s large diameter kiln, Holcim anticipates that at a molar ratio of about 1.0, an averag e annual control efficiency of 20 percent could likely be achieved without excessive NH 3 slip. However, a pilot study would need to be conducted to verify this. Regardless, SNCR is considered to be a technically feasible option for NO X control.



### 5.2.6 S ELECTIVE 

### C ATALYTIC 

### R EDUCTION

Selective Catalytic Reduction (SCR) is an a dd-on control technology for the control of emissions of the oxides of nitrogen (NO
x ) from a combustion process. SCR has been successfully employed in the electric power indus try. 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 (NH 3 ) slip. 14
The NH 3 reacts with NO x compounds (i.e., NO and NO 2 ) on the surface of the catalyst in equal molar amounts (i.e., one molecule of NH 3 reacts with one molecule of NO x ). Common reagents include aqueous NH 3 , anhydrous NH 3 and urea [(NH 2 ) 2 CO]. In the presence of the catalyst, the injected ammonia is converted by OH - radicals to ammonia radicals (i.e., NH 2 - ), which, in turn, react with NO x to form N 2 and H 2 O. 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 (TiO 2 ), one or more metal oxide catalysts are deposited in various concentrati ons. In SCR applications, the active catalyst material typically consists of vanadium pentoxide (V 2 O 5 ), tungsten trioxide (WO 3 ), and molybdenum trioxide (MoO 3 ) 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 unreacte d 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 (SO 2 ), the catalysts used in SCR have a propensity to oxidize sulfur dioxide (SO 2 ) in the flue gas to sulfur trioxide (SO 3 ), a more undesirable pollutant.

Because the reaction rate of NH 3 and NO x is temperature dependent, the temperature of the flue gas stream to be controlled is the mo st important consideration in applying SCR technology to any combustion source. The optimum temperature range for SCR application is about 300o C (570o F) to 45 0o 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 technol ogy is considered "available" if it can be obtained by the applicant through commercial cha nnels 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: con cept 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 e xpected 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 availabl e. 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 NO
x control at the Clarksville plant.

.



## 5.3 R ANK OF 

## T ECHNICALLY FEASIBLE 

## NO X 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to effectiveness. Table 5-3 presents potential NO x technically feasible control technologies by effectiveness.Holcim (US) Inc. 5-10 Trinity Consultants BART Analysis T ABLE 5-3. R ANKING OF T ECHNICALLY F EASIBLE K ILN NO X C ONTROL T ECHNOLOGIES BY E FFECTIVENESS

Control Technology Effectiveness NO X Emissions Level (%)

MKF 20%
SNCR 20% LNB, CKD Insufflation, and Synfuel Already utilized at Clarksville



## 5.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## NO X 

## C ONTROLS

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.

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 CO 2 emissions (a Green House Gas) and reduces fossil fuel use.

Remaining Useful Life The remaining useful life of the kiln does not impact the annualized costs of MKF because the useful life is anticipated to be at least as long as the capital cost recovery period, which would be 15 years.



## 5.5 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## NO X 

## C ONTROLS

The final impact analysis was conducted to assess the visibility improvement for existing emission rates when compared to the emission rate with MK F. 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 NO
x emission rate associated with MKFHolcim (US) Inc. 5-11 Trinity Consultants BART Analysis was the existing emission rate less an average reduction of 20 percent. The emission rate is summarized in Table 5-4.

T ABLE 5-4. S UMMARY OF E MISSION R ATES M ODELED I N NO X C ONTROL V ISIBILITY I MPACT A NALYSIS

Emission Rate

SO 2 NO X PM 10 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 98 th percentile existing visibility impacts and the visibility impacts based on MKF are provided in Table 5-5. The visibility improveme nt associated with MKF are also shown in Table 5-5; this was calculated as the difference between the existing visibility impairment and the visibility impairment for the remaining control options as measured by the 98 th percentile modeled visibility impact.

T ABLE 5-5. NO X C ONTROL V ISIBILITY I MPACT A NALYSIS

Existing 98% Impact ( Δ dv) MKF 98% Impact ( Δ dv) Improvement Mingo 1.01 0.92 8.9%
Hercules 0.81 0.72 11.1% Upper Buffalo 0.61 0.60 1.6%

As seen in Tables 5-5, the MKF option results in a visibility improvement of up to 11.1 percent in the Hercules Glades Class I area.



## 5.6 P ROPOSED 

## B ART FOR 

## NO X
Based on the five step analysis outlined by EPA, MKF was identified as the highest ranking feasible add-on control technology. Energy and environmen tal impacts were assessed for this technology and the visibility improvements were evaluated agains t existing conditions. Consistent with EPA guidance, economic impacts were not assessed as Holcim was willing to utilize the highest ranked control technology. The visibility impact analysis demonstrates that the utilization of MKF to achieve a 2,440 lb/hr NO
x 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 Cl arksville 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 NO X emission rate of 73,185 lbs.

To comply with this determination, Holcim is proposing an enforceable limit of a 20% reduction in the maximum daily NO X emission rate of 73,185 lbs used for modeling visibility impairment. As documented in this report, the dynamics in daily kiln operations and inputs and the lack ofHolcim (US) Inc. 5-12 Trinity Consultants BART Analysis information on predicting short term actual reductions from MKF, Holcim proposes that the enforcement of the reduction be based on a 30 day rolling average.

Based on the lack of site specific, or significant i ndustry data, for the use of this technology on wet cement kilns, it is possible that Holcim will furt her evaluate the MKF system and determine that MKF results in limited or no add itional 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 pl ace, including LNB, insufflation, and the use of alternative fuels as available.Holcim (US) Inc. 6-1 Trinity Consultants BART Analysis 

## 6. BART S UMMARY

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

Kiln:

• PM 10 – Holcim has determined that the existing electrostatic precipitator constitutes BART. This control device is effective for controlling PM 10 from a wet kiln.

• NO X – 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 NO X emission rate of 73,185 lbs.

• SO 2 – Holcim proposes that BART for the Holcim Clarksville Kiln is fuel substitution or equivalent that will achieve a 23 per cent reduction in the maximum daily SO 2 emission rate of 117,345 lbs.

The proposed BART control strategies will result in re ductions 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 emissi on rates is provided in Table 6-1.

T ABLE 6-1. V ISIBILITY I MPAIRMENT I MPROVEMENT

Mingo National Wildlife Refuge Hercules Glades Wilderness Area Upper Buffalo Wilderness Area Existing 98% Impact ( Δ dv) 1.01 0.81 0.61 BART 98% Impact ( Δ dv) 0.79 0.64 0.48 Improvement 98% Impact ( Δ dv) 22% 21% 22%

Holcim proposes to implement BART on or befo re 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 percent reductions stated in the report. Changes in technology may offer opportun ities to obtain even better reductions with lower cost impact.

Due to the variability in kiln operation and inputs as referenced in the report, Holcim proposes to comply with an enforceable limit of 23% reduc tion in SO2 emissions and 20% reduction in NOx emissions from the daily maximum emission rates, as modeled, on a 30 day rolling average.

## A PPENDIX 

## A. C OAL 

## C OMPOSITION 

## D ATAAppendix A. Coal Composition Data - Holcim Clarksville BART Analysis Options:Regional CoalsPRB CoalAreaIllinoisIllinoisColoradoCompanyPeabody COALSALES LLCKnighthawkCOALSALES LLCMine nameGateway MineKHC Mines, primarily Pairie Eagle MineTwentymile MineFOB Lone Eagle (KHC Dock, Mile post 105)Rail:Energy,COtoCora, IL via UP RailBarge:Cora, IL toClarksvilleTransportation ModeBargeTruck & Barge0.7% 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 %HGI525545HGIChlorine %0.12%0.05%0.01%Chlorine %mmbtu/lb11,00011,10011,300mmbtu/lbHHV MJ/MT25,58225,81426,279HHV MJ/MTLHV MJ/MT25,56725,80026,266LHV MJ/MTUltimate (Dry)Ultimate (Dry)Ash %9.90%9.00%11.00%Ash %Hydrogen5.00%5.20%5.00%HydrogenTotal Carbon71.40%72.00%69.60%Total CarbonNitrogen1.30%1.40%1.70%NitrogenSulfur3.28%3.10%0.54%SulfurChlorine0.12%0.04%0.01%ChlorineOxygen9.00%9.40%10.75%OxygenAsh Mineral (Dry)Ash Mineral (Dry)Silicon Dioxide51.40%50.70%60.00%Silicon DioxideAluminum Oxide19.70%20.50%25.10%Aluminum OxideTitamium Dioxide1.00%1.00%0.90%Titamium DioxideCalcium Oxide4.20%3.50%4.00%Calcium OxideIron Oxide16.30%15.80%3.10%Iron OxideMagnesium Oxide1.00%1.00%1.40%Magnesium OxidePotassium Oxide2.20%2.20%1.30%Potassium OxideSodium Oxide1.30%0.70%1.20%Sodium OxideSulfur Trioxide2.60%2.70%1.50%Sulfur TrioxidePhos Pentoxide0.20%0.20%0.90%Phos PentoxideStrontium Oxide0.10%0.20%Strontium OxideBarium Oxide0.10%0.40%Barium OxideManganese Oxide0.10%0.10%0.10%Manganese OxideVanadim PentroxideNickel OxideUndetermined1.80%

## A PPENDIX 

## B. R EVIEW OF THE 

## P OTENTIAL FOR 

## P LUME 

## O PACITY



## E XCEEDANCES 

## R ESULTING FROM THE 

## U SE OF A 

## W ET 

## S CRUBBER

## 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 SO 2 

### . 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 plum e. Following is an analysis of the gas stream to determine the specific te mperature needed for t he 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 ha ve 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 reac tions for most common types of plume in the cement manufacturing process, Although SO 3 

### and Total Hydrocarbons (THC) may also contribute to the plume, they have not been considered.

SO 2 Visible Particulate Visible Particulate

H 2 SO 4

NH 3

H 2 O

NH 4 Cl SO 2 NH 3

H 2 O Condensation Condensation

Cooling

Hot Gases with Hot Gases with Various Gaseous Various Gaseous Species SO 2 Visible Particulate Visible Particulate

H 2 SO 4

NH 3

H 2 O

NH 4 Cl SO 2 NH 3

H 2 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 

### NH 4 

### Cl (NH 4 

### ) 2 

### SO 4



### T HCl NH 3 

### T SO 2 

### Secondary Plume

sub-micron aerosol



### H 2 

### O T a, RH 

### NH 4 

### Cl (NH 4 

### ) 2 

### SO 4



### T HCl NH 3 

### T SO 2 sub-micron aerosol

T a, RH



### H 2 

### O

B-1 6/12/2008

### Some of the key points relevant to the diagram include:

 Both (NH4) 2 

### SO4 and NH 4 

### Cl are sub-micron aerosols that form at relatively low stack temperatures. (NH4) 2 

### SO4 formation needs condensed moisture to occur. Whereas NH 4 

### Cl solid can quickly form direct ly from the gas phase of NH 3 

### 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 li ght transmission through the stack gas. Figure 1 provides an example of relative li ght extinction versus particle size. For example, a PM 0.5 

### particle has an extinction effi ciency approximately an order of magnitude greater th an that of PM 10



### .

Figure 1. Extinction Efficiency Fa ctor 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 μ m diameter range are particularly effective in scattering visible light (wavelength: about 0.4 - 0.7 μ m) on a unit mass basis, with a peak attenuation at 0.5 μ m.

• The particles of either very large (>5 μ m) or very small (<0.1 μ m) 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 condens ed, but the precursors have not had sufficient time to be diluted with ambient ai r. This situation is most dominant in occurrence on cold, calm and humid days.

Supplement A, at the end of this documen t, 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 Clar ksville 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 cooli ng in the presence of high humidity that can occur at the exit of a stack). If the gas has NH 3 

### and HCl, they can quickly react to form aerosols (fine particulate ma tter). These very fine particulates are controlled with a much lower efficiency t han larger PM and t hus can increase PM levels of the form of PM that leads to the highest plume visibility.

 In addition, the scrubber can not remove all NH 3 

### or SO 2 

### in the gas stream. The typical SO 2 

### reduction in a scrubber is about 90%. The NH 3 

### removal is governed by the equilibrium between the gas and t he scrubber slurry liquid. Figure 2 provides the NH 3 

### gas-liquid equilibrium graph at a pH of 6. The NH 3 

### 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 NH 3 

### concentration. The remaining SO 2 

### and NH 3 

### in the scrubber effluent could react with the NH 4 

### Cl 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 NH4+in solution , (g / l) pH = 6



### Figure 2. Concentration of NH 4 + 

### versus HN3 Concentration in Gas

 The gas temperature after the scrubber is much lower than the kiln gas temperature. Besides the aerosols form ed 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 build ing a wet scrubber for one of Holcim’s PH/PC plants. A PH/PC kiln system typi cally has two gas effluent streams, one contains high NH 3 

### (main stack) and the other cont ains 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 f easibility study for the plant 1 

### :

“Mixing the NH 3 

### and HCl streams at the in let will indeed produce an NH 4 

### Cl 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 w ould 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. A nd, even though the problem was acknowledged, and the system was designed to prevent the visible plume problem, the plant still has challen ges with plume formation during the winter.

Kiln gas emission concentrations and opacity

 Holcim, as well as other compani es, have found that at about 5ppm NH 4 

### Cl or 10ppm (NH4) 2 

### SO4, detached plumes can form outsi de 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 aer osols 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, NH 3 

### , 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 Clarksvill e plant include:

 The CEMEX plant at Cementos Guadalaj ara, a 4 stage PH/PC kiln, had a highly visible plume caused by NH 4 

### Cl. To resolve the problem, the plant added two additional stages that increased pollut ant adsorption (HCl emissions were reduced to 5 ppm) and the plume disappear ed. 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 vi sible 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 NH 3 

### 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 Visibili ty – Reaction Rate Based Equations

Solid NH 4 

### Cl aerosols can form directly from the gas phase through the following reversible chemical reaction when the temperature drops:

NH 4 

### Cl (s) = HCl (g) + NH 3 

### (g)

The thermodynamic criteria for the r eaction to occur is determined by the equilibrium constant Kp, which can be expressed by the following equation 2



### ln Kp = 34.266 –21196/T

where T is the temperature (K). The chemic al reaction takes place if the product of partial pressures of HCl and NH 3 

### in gas is greater than Kp, i.e. (pHCl · pNH 3 

### ) > Kp (pHCl & pNH 3 

### are both in atm). This reaction can keep going to form NH 4 

### Cl until the partial pressures of NH 3 

### 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) NH 3 

### and HCl will make the (pHCl · pNH 3 

### ) > Kp, and the reaction will not stop until both gas phases drop down to 1-2 ppm. Thus, almost all NH 3 

### and HCl with a concentration higher than 1-2 ppm in the kiln gas will form NH 4 

### Cl 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 NH 3 

### and HCl from forming again in the stack or near the stack. The higher t he 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 t hat the product of both NH 3 

### and HCl concentrations would not be higher than Kp, and no aerosol formation would occur.

An example of how reheating temperature affects the opac ity in a power plant is depicted in Figure 3 3 

### . The precursor of the visibl e plume in this case is SO 3 

### , (as opposed to NH 4 

### Cl).

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

Although reheating the stack gas to a te mperature 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 poi nt. 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 SO 3 

### . 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 T P 

### to drop below the dew point temperature T DP 

### and cause higher opacity levels.

3 J. J. Martin Hughes, “Fine Particle Model for De tached Plume Opacity”, Virginia State University, 16 th 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 fact ors 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 plum e visibility. Theref ore, it is almost impossible to predict the exact reheating temperature required. Regardless, a mathematical model has been established to provide a simplified simulation of NH 4 

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

Estimating the Reheat Temperat ure for CV based on Plant Data

The NH 3 

### and HCl emission concentration will c ontrol the plume formation as SO 2 

### concentrations are likely to be sufficiently hi gh as to not be limiting in any equations. Table 1 summarizes the CV annual stack te sting for 2002 - 2007. Although HCl was relatively low in 2007, it can and has varied si gnificantly over the last five years.

Table 1. HCl and NH 3 

### 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 testi ng not a Continuous Emission Monitor (CEM) and thus the annual and daily emission levels may vary considerably from these values. Furt her, the peak annual emission may be much higher than the test average. For example, during the th ree 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 operat ions in 2007, the plant found that during some cold days, the plume outside of the stack was visi ble, but it did not reach 20% opacity.

The current stack temperatur e is about 350 F, and the temp erature at the outlet of the ESP is about 380 F. The lower temperat ure in the stack is due to heat loss in the ductworks and the I.D. fan. Therefore, a reheating temperat ure 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 NH 3 

### ), a reheat temperature of 380 F, or 350 F stack temperature, mi ght not be necessary since based on our modeling result, the total HCl and NH 3 

### as aerosols after the scrubber should not be higher than in the original kiln gas.

However, HCl concentrations in the pr ior years have been as much as 10 times higher than 2007, reaching over 20 ppm in 2003 and 2004, while the NH 3 

### concentrations were nearly 20 ppm. T hese 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 te mperatures during these time periods were much higher than current temperatures. For example, the st ack 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 afte r the scrubber would st ill 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 NH 3 

### concentrations reach 20 ppm in the kiln gas, the reheat te mperature may need to be 480 deg F or higher in the winter, while if the HCl and NH 3 

### concentrations drop to 2007 levels or below, a reheat temperature of le ss than 380 deg F may be sufficient in the summer. Therefore, considering t he variation in the HCl and NH 3 

### 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 pr oviding 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 t he unscrubbed gas temperatur e 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 NH 3 

### ) 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 temperatur e of 380 deg F. This optio n 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 NH 4 

### Cl formation outside of the stack. Based on Holcim’s experience with visible plumes at multiple plants, an NH 4 

### Cl aerosol concentration of 5ppm in the at mosphere is used as the criteria for a highly visible plume outside of the stack. In reality, some of Holcim’s plants control their NH 4 

### Cl aerosol concentrations to less t han 1-3 ppm to avoid visible plume formation.

This model only considers the gas temperat ure 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.

NH 4 

### Cl formation was simulated for the following scenarios:

• Scenario 1. Maximum stack testing NH 3 

### and HCl concentrations for the last 4 years, reheating to 380F and Winter Condition

• Scenario 2. Maximum stack testing NH 3 

### and HCl concentrations for the last 4 years, reheating to 380F and Summer Condition

• Scenario 3. Maximum stack testing NH 3 

### and HCl concentrations for the last 4 years, reheating of 50% kiln gas (300F) and Winter Condition

• Scenario 4. Maximum stack testing NH 3 

### and HCl concentrations for the last 4 years, reheating of 50% kiln gas (300F) and winter Condition

• Scenario 5. Average of the NH 3 

### 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 NH 3 

### and HCl concentrations for the last 4 years, reheating of 50% kiln gas (300F) and summer Condition

• Scenario 7. Average of the NH 3 

### and HCl concentrations for the last 4 years, reheating of 380 F and summer Condition

• Scenario 8. Maximum stack testing NH 3 

### 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 resp ect to the ambient and stack gas specific heat, t he temperature of the mixtur e will be calculated. Next, the Kp line which represents the equilibriu m condition is drawn by inserting the temperature in the above formula. T he corresponding concentration of HCl and NH 3 

### of the gas mixture is calcul ated at each interval, converted to partial pressures and multiplied with each other to fi nd the Mixing Path value (Km). The Mixing Path (Km) at the corresponding temperat ure represents the calculat ed gas conditions at that interval. Then the Km+5 line which corresponds to the concentration of NH 3 

### 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) repr esents the 380°F reheati ng temperature and stack temperature of 350°F, an ambi ent temperature of 14°F (r epresenting a typical winter temperature), and the five year maximum NH 3 

### 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 NH 4 

### Cl. 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 NH 3 

### 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 NH 3 

### Concentration (ppmv, dry) 27 Figure 6



### B-12 6/12/2008

### Scenario 2 (Figure 7) repres ents the situation in Figur es 5 & 6 (380 F reheating and 350 F stack temperature) but at a ty pical spring/summer temperature of 68 ° F. At these conditions, the Mixing Path barely mi sses the line representing 5 ppm aerosol NH 4 

### Cl formation. Thus, a visible pl ume 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 NH 3 

### 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 tem perature, the Mixing Path crosses the 5 ppm aerosol NH 4 

### Cl formation line and nearly crosses a 10 ppm aerosol NH 4 

### Cl 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 NH 3 

### 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 st ack temperature, the Mixing Path still crosses the 5 ppm aerosol NH 4 

### Cl 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 NH 3 

### 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 NH 3 

### (25 ppmv, dry) and HCl (16 ppmv, dry) is predicted to form more than 5 ppm of aerosol NH 4 

### Cl 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 NH 3 

### Concentration (ppmv, dry) 25 Figure 10



### B-16 6/12/2008Formation 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 NH 3 

### Concentration (ppmv, dry) 25 Figure 11



### B-17 6/12/2008

### Scenario 7 (Figure 12) repres ents 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 concentrati on 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 NH 3 

### Concentration (ppmv, dry) 25 Figure 12



### B-18 6/12/2008

### Scenario 8 (Figure 13) shows the actual 200 4 conditions of the plant at a typical winter ambient condition. Although the HCl and NH 3 

### concentrations are relatively high, the high stack temperat ure (480 deg F) allows for d ilution and the Mixing Path line does not cross the Km line and t herefore less than a 5 ppm aerosol NH 4 

### Cl 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 NH 3 

### 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 NH 3 

### in the gas stream, as well as ot her factors. Due to the normal variability in HCl and NH 3 

### concentrations, it is virtually assured that the combination of higher HCl and NH 3 

### 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 seco ndary 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 te st 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 cr ystals of ammonium sulphate. The tests indicated that the primary components of the stack effluent were (NH4) 2 

### SO4 (4.5 ppm), SO 2 

### (200 ppm), NH 3 

### (170 ppm), moisture (20%). The ammonium sulphate in the stack gas was responsible for the 10% in-stack opacity.

The secondary plume was also observ ed at Lehigh Cement in Leeds, Alabama, USA. Testing conducted in 1981 indicated t hat the major species responsible for the plume was ammonium chloride, NH4Cl.

Similar tests were conducted in 1987 at Kais er Cement in Perma menti, California, USA. The results revealed that NH4Cl was also responsible for the visible secondary plume. The secondary plume te sts conducted in 1987 at Southwestern Portland Cement in Victorville, Californi a, USA, also revealed that NH4Cl was responsible for the visi ble secondary plume.

In 1986, EPA conducted a source and proc ess sampling program at the South Dakota Cement Company, Rapid City, Sout h Dakota, USA. The samples collected from the secondary plum e contain up to 67% NH4Cl. Furt her tests indicated that the NH3 exists mainly in the shale that acc ounts for about 20% of raw mix. The plant has a dry process with a 4-st age preheater, vertical roller mill for raw grinding and a main baghouse for dedusting. A severe a mmonia recirculation was observed, with an average NH3 content in shale being 6.2 ppm while up to 159 ppm NH 3 

### was found in the baghouse dust. It was also obser ved 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 res ponsible for the visible plume.

Other examples include the Lone Star I ndustries’ Cape Girardeau Cement Plant, MO, USA and the Inland Cement, Edmonton, AB, Canada. Both plants experienced secondary plumes due to format ion of ammonium sulphate.

## A PPENDIX 

## C. S ELECTIVE 

## M INING



## – Q UARRY 

## S CHEDULING 

## O PTIMIZATION



## D ISCUSSION

## 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 correla tion between samples is relevant.

The Clarksville QSO Model was cr eated specifically for predict ing relevant mineralogical parameters related to clinke r 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 wa s 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 t he potentially quarried shale. Spatial relationships between core samples were found to be inappropriate for the sensitivity needed to make accurate predictions. The reas on 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 c hemical processes in organic-rich marine sediments, such as Maquiketa shale, is decomposition of organic matter (OM)in bacterial sulphate reduction. Bacterial sul phate 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 reacti ve dissolved iron and iron minerals, if available, resu lts 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 c hannels of solubility during rock forming (induration). The pyrite is formed as nodules or clusters of mineralization and is not evenly distributed spatially throug hout the shale and limestone.

Therefore the chance of intercepting a pyrite cl uster of mineralization by core drilling is known as a ‘nugget’ effect. Intercepting a pyrite cluster will give arti ficially high sulfur values in the model and, conversely, not in tercepting 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 adequat e for predicting major oxides, they are too far apart and too few to accurately predi ct clustered mineralogy such as pyrite.

## A PPENDIX 

## D. BART C ONTROL 

## C OST 

## T ABLESTable 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 Cos t $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 Ca p ital 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 80%, 95% uptime 8,726
Pollutant Generated - NOx tons/ yr 97 Net Pollutant Removed - tons/ y r 8,629
Cost Per Ton of Pollutant Removed $2,826Table 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 Cos t $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 Ca p ital 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 95%, 95% uptime 10,362
Pollutant Generated - NOx tons/ yr 97 Net Pollutant Removed - tons/ y r 10,265
Cost Per Ton of Pollutant Removed $2,428Table 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 Cos t $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 Ca p ital 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 SO 2 /yr) - PTE 13,298 Pollutant Removed (tons SO 2 /yr) - 80%, 95% uptime 10,106
Pollutant Generated - NOx tons/ yr 97 Net Pollutant Removed - tons/ y r 10,009
Cost Per Ton of Pollutant Removed $2,482Table 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 Cos t $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 Ca p ital 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 SO 2 /yr) - PTE 13,298 Pollutant Removed (tons SO 2 /yr) - 95%, 95% uptime 12,001
Pollutant Generated - NOx tons/ yr 97 Net Pollutant Removed - tons/ y r 11,904
Cost Per Ton of Pollutant Removed $2,139Table 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

Cost ($/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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 23% 2,641
Cost Per Ton of Pollutant Removed $1,489Table 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 40% 4,592
Cost Per Ton of Pollutant Removed $5,927Table 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 50% 5,741
Cost Per Ton of Pollutant Removed $4,741Table 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

Cost ($/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 SO 2 /yr) 13,298 Pollutant Removed (tons SO 2 /yr) - 23% 3,059
Cost Per Ton of Pollutant Removed $1,286Table 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 SO 2 /yr) 13,298 Pollutant Removed (tons SO 2 /yr) - 40% 5,319
Cost Per Ton of Pollutant Removed $5,117Table 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 SO 2 /yr) 13,298 Pollutant Removed (tons SO 2 /yr) - 50% 6,649
Cost Per Ton of Pollutant Removed $4,094Table 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 20% removal, 95% uptime 2,181
Cost Per Ton of Pollutant Removed $6,750Table 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 SO 2 /yr) 11,481 Pollutant Removed (tons SO 2 /yr) - 30% removal, 95% uptime 3,272
Cost Per Ton of Pollutant Removed $4,500Table 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 SO 2 /yr) 13,298 Pollutant Removed (tons SO 2 /yr) - 20% removal, 95% uptime 2,527
Cost Per Ton of Pollutant Removed $6,632Table 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 SO 2 /yr) 13,298 Pollutant Removed (tons SO 2 /yr) - 30% removal, 95% uptime 3,790
Cost Per Ton of Pollutant Removed $4,421