# FMCAlkali (:hemicals FMC Westvaco Facility

April 11, 

### 2006 David A. Finley, Administrator Wyoming Department of Environmental Quality Air Quality Division 122 West**25~** 

### Street Cheyenne,VVY 

### 82002 FMC Corporation PO Box 872 Green River, WY 82935
307.875.2580 phone www.fmc.com



### Dear Mr. Finley: Please find enclosed five (5) 

### copies ofAddendum 1 ofthe Best Available Retrofit Technology (BART) analysis for sources subject to BART located at FMC's Westvaco facility near Green River, Wyoming, One copy ofthe addendum has also been sent to Tony Hoyt at DEQ's Lander district office. An electronic copy of the addendum (in PDF format) was transmitted earliervia email. Please note 1hat 1he electronicvisibility modeling files associated with the addendum are being provided to the Division directly by FMC's consultant Sage Environmental. Please contact me at 

### 307-872-2257 ifyou have any questions, Sincerely,

Otto C. Schnauber Environmental Team Leader

cc: Tony fioyt, District Engineer Wyoming Department of Environmental Quality Air Quality Division 

### 510 Meadowview Dr. Lander, WY 

### 82520 

# -FMC, r



# FMC Wyoming Corporation Green River, Wyoming

Best Available Retrofit Technology Analysis for Sources Subject to BART FMC Wyoming Corporation's Westvaco Facility
Addendum 1

## FMC Wyoming Corporation Green River, Wyoming

# ~.".",.,**,.~**



## Best Available Retrofit Technology Analysis for Sources Subject to BART FMC Wyoming Corporation's Westvaco Facility
Addendum 1

Prepared For: Wyoming Department of Environmental Quality Air Quality Division 122 West 25th Street Cheyenne, Wyoming 82002


### Prepared By: FMC Wyoming Corporation Otto Schnauber 

### Sage Environmental Jim Zapert

April 11, 2008

### Table of Contents Section 1.0 Introduction 2.0 Visibility Assessment Methodology 2.1 Modeling Methodology 2.2 Meteorological Model 2.3 Dispersion Model 2.4 Model Post-processing 2.5 Modeled Sources 2.6 Baseline Analyses 3.0 Best Available Retrofit Technology Analysis - Sulfur Oxides (SOx) 3.1 ImpactAnaiysis 3.2 sax BART VisibilityAnalyses 4.0 BestAvailable RetrofitTechnology Analysis - Nitrogen Oxides (NOx) 4.1 Control Technology Effectiveness 4.2 Impact Analysis 4.3 NOx BART VisibilityAnalyses 5.0 Selection of BART for FMC Westvaco Sources 5.1 Combined Application of BART for SOx and NOx Emissions 5.2 BART Proposal
Tables 2-1 Source Parameters 2-2 Baseline Emission Rates 2-3 Baseline Visibility Modeling Results 3-1 sax Control: Economic and Environmental Impacts for Each Coal-fired Boiler (NS-1A, NS-1 B) 3-2 Emission Rates for sax Control Alternatives 3-3 Visibility Modeling Results
- SOx Control Option 1 3-4 Visibility Modeling Results
- SOx Control Option 2 4-1 NOx BART Effectiveness for NS-1A and NS-1 B 4-2 NOx Control: Economic and Environmental Impacts for Each Coal-fired Boiler (NS-1A, NS-1 B) 4-3 Emission Rates for NOx Control Alternatives 4-4 Visibility Modeling Resuits
- NOx Control Option 1 4-5 Visibility Modeling Results
- NOx Control Option 2 4-6 Visibility Modeling Results
- NOx Control Option 3 5-1 Source Parameters forVisibilityAnalysis: Combined sax and NOx Control 5-2 Visibility Modeling Results
- Combined sax and NOx Control

ii**~.~**Appendices 

### 1 Cost Effectiveness Analyses Detail
- 

### sax and 

### NOx Control Alternatives

iii

### 1.0 Introduction
FMC submitted a BestAvailable Retrofit Technology (BART) analysis in March, 2007 that addressed the FMC Green River emission sources thatwere subject to BART. The analysis focused on retrofit options forthe site's two coal-fired boilers: units NS-1A and NS-1B.
Information that has become available since the original submittal has resulted in the need to update the conclusions reached in that analysis with regard to NOx control on the two boilers. Additionally, the analyses presented in this addendum for both NOx and SOx visibility impacts address emission units on an individual basis as required by the BART modeling protocol.

### 2.0 Visibility Assessment Methodology
The additional visibility modeling performed for this submittal employed the same techniques that were described in Section 3 ofthe March 2007 analysis. Those techniques are repeated here for ease of reference. Baseline modeling results now showthe visibility impacts in the wilderness areas of each ofthe BART eligible emission units.

2.1 Modeling Methodology
The protocol indicates that visibility assessments are to be conducted using the CALPUFF modeling system, and three years of meteorological data, years 2001 through 2003. The modeling system is comprised ofthe CALMET meteorological model, the CALPUFF dispersion model, and the CALPOST post processor. Forthis analysis CALMET (version 5.53a, level 040716), CALPUFF (version 5.711a, level 040716), and CALPOST (version 5.51, level 030709) were used. The modeling domain specified in the WDEQ protocol as applicable for southwest Wyoming was used since the PSD Class I areas of interest include the Bridger and Fitzpatrick PSD Class I Wilderness Areas.

2.2 Meteorological Model
The CALMET meteorological model was used to determine hourlywindfields for years 2001 through 2003. Mesoscale model meteorological data (MM5) at 12- km grid resolution, surface and upper air meteorological observation data, precipitation data, and geophysical data as provided by the Wyoming DEQ were used. The modeling domain was processed to a uniform horizontal grid using 4- 1m resolution, based on a Lambert Conformal Projection defined with a central longitude/latitude at (-108.55',42.55') and first and second latitude parallels at 30' and 60'. Ten vertical layers were used with heights of 20,40, 100, 140,320, 580,1020,1480,2220, and 3400 meters. The height used forthe top layer (3400 meters) differed slightly from what was specified in the WDEQ protocol (3500 meters) since the upper airdata provided by the WDEQ was not sufficientto support a 3500 meter layer height. All other CALMET input switch settings and input control values were determined following the WDEQ protocol.

3.3 Dispersion Model
The CALPUFF dispersion model was used to model emissions of nitrogen oxides (NOx ), sulfur dioxide (S02). primary sulfate (S04) and particulate matter (PM). S04 emissions were determined from sulfuric acid mist (H2 S04 ) emissions using the ratio ofthe molecularweights ofthe two compounds. All particulate matter was assumed to be PM2
. s. CALPUFF was run using the control file switch settings and values as provided in the WDEQ protocol. Model receptors determined for the Bridger and Fitzpatrick Wilderness Areas were provided bythe WDEQ. Chemical transformations were modeled based on the MESOPUFF II chemistry mechanism for conversion of S02 to S04 and NOxto nitric acid (HNOs ) and nitrate (NOs). A background ammonia (NHs ) concentration value of 2.0 parts per billion (ppb) was specified. Background hourly ozone concentration data from monitoring sites throughout the modeling domain were provided by the WDEQ for each modeled year.
2.4 Model Post-processing
The CALPUFF model results were post-processed using the CALPOST processorto estimate visibility impacts at the Bridger and Fitzpatrick Wilderness Areas. Visibility impacts were determined using CALPOST method 6. Method 6 calculates visibility impacts from CALPUFF predicted concentration data, relative humidity factors, and aerosol components. Relative humidity factors and background concentrations of aerosol components forthe 20 percent best days applicable to the Bridgerand FitzpatrickWilderness Areas and all CALPOST switch settings were provided from the WDEQ protocol.
CALPOST was used to determine both the 98th percentile,or 8th highest, 24-hour visibility impacts for each year and the maximum numberof days peryear above 0.5 deita deciviews (Mv).2.5 Modeled Sources
The source parameters for the FMC Westvaco BART eligible emission units are summarized below: Table 2-1 Source Parameters

#6 coal-fired NS-1A boiler 599377.25 4607953.88 6305.12 #7 coal-fired NS-1B boiler 599381.06 4607953.88 6305.12 #4 gas-fired PH-3 boiler 598665.05 4608318.92 6229.33
2.6 Baseline Analyses 300 11.5 300 11.5 70 7.5

2.6.1 Baseline Emission Rates
The baseline emission rates for the FMC Westvaco BART eligible emission units are summarized below:
Table 2-2 Baseline Emission Rates

#6 coalNS-1A fired boiler 287 359.000 45.0 1064.4 620.9 13.4 #7 coalNS-1B fired boiler 287 359,900 45.0 1064.4 620.9 13.4 #4 gas-fired PH-3 boiler 250 72,500 2.5 0 76.7 0

The baseline emission rates represent the maximum potential to emitvaiues for each pollutant for each ofthe BART eligible sources. Particulate matter is assumed to be PM2.5.2.6.2 Baseline Modeling Results
The baseline modeling results for the FMC Westvaco BART eligible sources for each modeled year are shown below in Table 2-3.
The average predicted light extinction, given in units of inverse megameters (Mm'1) for each day and receptorwhere the predicted visibility Impact was at or above a 5 percent change in extinction (approximately equal to 0.5 I1dv), was calculated. Results are provided for each ofthe FMC Westvaco BART eligible sources as average extinction and percent ofthe total extinction. The number of days above 0.5 I1dv and the 98th percentile values are also provided.
Table 2-3 Baseline Visibility Modeling Results

NS-1A: Extinction, Mm", NS-1 B: Extinction, Mm'

PH-3: Extinction Mm' NS-1A: # da s> 0.5l1dv 10 5 11 4 2 1 NS-1 B: # da s > 0.5l1dv 10 5 11 4 2 1

PH-3: # da s > 0,5l1dv 0 

# ° ° ° ° 0 NS-1A: 98 ercentile lIdv 0.566 0.429 0,536 0,327 0,311 0.263 NS-1B: 98 ercentile lIdv 0.566 0.429 0.536 0,327 0,312 0.263

PH-3: 98 ercentlle lIdv 0.041 0.032 0.047 0,017 0,020 0,017 Conclusions from the baseline modeling results are:

• Contributions to visibility impacts from sources NS-1A and NS-1 Bare virtually identical. The visibility impact from each ofthese sources is above the 0.5 dv guideline value in the BridgerWilderness in two ofthe three years modeled, and each sources' impact in the Fitzpatrick Wilderness is less than the gUideline impact value in all three years.

• The visibility impact from source PH-3 is significantly less than the 0.5 dv gUideline value In all cases which means that this source is not subject to BART.

### 3.0 Best Available Retrofit Technology Analysis - Sulfur Oxides (SOx)


### The BestAvailable Retrofit TechnologyAnalysis for Sulfur Oxides (SOx) was fUlly described in Section 5 of the March, 2007 submittal.
3.1 Impact Analysis
Table 3-1 is asummaryofthe economicand environmental impacts associated with SOx control effectiveness and reflects impacts on an individual boilerbasis.



# .-a
...**~~**Table 3-1 SOx Control: Economic and 

### Environmental Impacts for Each Coal-fired Boiler (NS-1A, NS-1B)

S02 CONTROL LEVEL, Ib/mmBTU 1.2 0.45 0,30 ECONOMIC IMPACTS: Control Equipment Capital Costs $0 $2,330105 $4403381 Capital Recovery Factor 

### N/A 0.1098 0.1098 Annual Capital Recovery Costs $0 $255,846 $443,963 Annual O&M Costs $0 $277,645 $1,312556 Annual Cost of Control $0 $533491 $1,756,519 ENVIRONMENTAL IMPACTS: Tons perYear SOx Emissions 4662.1 1748.3 1165.5 Tons perYear SOx Reduction 0 2913.8 3496,6 Highest modeled 98'h percentile deciview dv vaiues 0.566 0.404 0,384

Deciview reduction 0 0.162 0.182 COST EFFECTIVENESS': Dollars perton reduced 

### N/A $183 $502 Incremental dollars parton reduced 

### N/A $183 $2099 Dollars perdv reduced 

### N/A $3,293154 $9,651205 Incremental dollars perdv reduced 

### N/A $3,293154 $61151421

, Cost effectiveness values are underestimated because the annual powercosts and annualized capital costs associated with downtime for control installation have not been estimated or included in the calculation ofthese values.
Control equipment capital costs are estimated based on budgetary quotes from equipment vendors. 

### The capital recovery factor of 10.98 percent of capital costs is based on a 7 percent annual interest rate and a contrellife of 15 years as outlined In U.S. EPA's Control Cost Manual (6th Edition
- January 2002). Annual operating and maintenance costs reflect current FMC costs for labor and other services. 

### The highest modeled deciviewvalues reflect the maximum 98th percentile value obtained from modeling the visibility impact ofthe specific SOx control option (see Section 3.2). Cost effectiveness values (dollars perton reduced and dollars perdeciview reduced) vary dueto differences in capital investment requirements and operating costs associated with each option. The incremental cost effectiveness data are the cost ofthe control alternative compared to the next most stringent control alternative.
3.2 SOx BART Visibility Analyses The visibility impacts to the Bridger and Fitzpatrick Wilderness areas resuiting from application ofthe SOx control alternatives were evaluated using the visibiiity assessment methodology described in Section 2 ofthis document. Boilersource parameters, baseline emission rates, and baseline visibility modeling results can be found in Section 2.6. Model input data for each ofthe SOx control alternatives are listed in Table 3-2.
Table 3·2 Emission Rates for SOx Control Alternatives

NS-1A NS-1B #6 coalfired boiler

#7 coalfired boiler 170 170 359,000 359.900 399.15 399.15 10.3 10.3 266.10 266.10 9.6 9.6 Visibility modeling results associated with the application of each option are listed in Tables 3-3 and 3-4. These resuits depict the improvement in visibility over baseline conditions from implementation of SOx controls.
Table 3-3 Visibility Modeling Results
- SOx Control Option 1

NS-1A: # da s > 0.511dv NS-1 B: # da s> 0.511dv NS-1A: 98 ercentile lIdv NS-1 B: 98 ercentile lIdv 0.404 0.404 0.358 0.357 0.386 0.385 0.241 0.234 0.241 0.235 0.187 0.187Table 3·4 Visibility Modeling Results - SOx Control Option 2

NS-1A: 98 ercentlle lIdv NS-1 B: 98 ercentile lIdv 0,384 0,384 0,339 0,339 0,348 0,215 0,219 0,349 0,216 0,219 0,169 0,169 

### Conclusions from sax control option modeling:

• Visibility modeling indicates that application ofeither ofthe sax control options to an individual boiler, even without any changes to otherexisting pollution control equipment, results in visibility impacts from that unit that are below the Division's 0.5 dv guideline value fordetermining that asource contributes to visibility impairment in any Class 1 area.

• Since there would be no perceptibie difference in visibility improvement as a result ofapplication ofa particularcontrol option, FMC proposes control option 1 (scrubber upgrade) as BARTfor sax. Impiementation ofsax control in conjunction with NOx control is discussed in Section 5.

### 4.0 Best Available Retrofit Technology Analysis - Nitrogen Oxides (NOx)


### The Best Available Retrofit TechnologyAnalysis for Nitrogen Oxides (NOx) was fUlly described in Section 6 ofthe March, 2007 submittal.


### In August 2007 low NOx burners with Overfire Airwere retro-fitted in boiler NS-1A. Computational Fluid Dynamic modeiing ofthese units, priorto their installation, indicated that it would be possible to achieve an emission rate of0.26 Ibs NOxlMMBTU. While the 0.26 Ib/MMBTU emission rate has been demonstrated when the boiler is operated at full load, it has not been possibie to sustain this rate at other boiler loads.
Boilers NS-1A and NS-1B are used to supply steam to the industrial process of manufacturing soda ash. Uniike utiiity boilers, these two units are not base-loaded
-they react to the variable steam demands ofthe production process. The performance history of boiler NS-1A, since installation ofthe retrofitted burners, indicates that the boiler can achieve average emission rates approaching 0.33 Ibs NOxlMMBTU. Consequently, the NOx BART effectiveness, economic and environmental impact analyses for boilers NS-1A and NS-1 B have been revised to reflect a maximum emission iimit of 0.35 Ibs NOxlMMBTU (310.4/bs/hr).
4.1 Control Technology Effectiveness
Boilers' NS-1A and NS-1 Boriginal NOX controls were designed to achieve a NewSource Performance Standard limit ofO.lO 

### Ib/MMBtu (40 CFR 60 Subpart D). Table 4-1 presents the NOx BARTeffectiveness summary.Table 4-1 NOx BART Effectiveness for NS-1A and NS1-B

Replace existing burners, modify OFA ports, lNBs, OFA, SCR instaH SCR s stem lNBs, OFA, Replace existing burners, modify OFA ports, SNCR instaH SNCR s stem lNBs w. OFA Re iace existln burners and modi OFA arts 0.35(bl Existin Control Baseline 0.70(01

, Data from: "Proposal For Burner Modifications and Overfire Air System Upgrades; Performance

Guarantee;" Prepared by Advanced Combustion Technology, Inc. 1106 Hooksett Rd. Hooksett, NH. October 31,2006 (blBased on demonstrated ability of retro-fitted equipment and boiler heat Input capacity (887 MMBtu/hr) (OIBased on original permit limit and boiler heat input capacity (887 MMBtu/hr) 

### 4.2 ImpactAnalysis
Table 4-2 

### summarizes the revised economic and environmental impacts associated with the NOx control effectiveness. Table 4-2 NOx Control: Economic and 

### Environmental Impacts for Each Coal·fired Boiler (NS-1A, NS-1B)

NOx CONTROL lEVEL, Ib/mmBTU 0.7 0.35 0.21 0.1 ECONOMIC IMPACTS: Control Equipment Capital Costs $0 $1,723,091 $3,160,918 $44,719,163 Capital Recovery Factor N/A 0.1098 0.1098 0.1098 Annual Capital Recovery Costs $0 $188976 $347,069 $4910,164 Annual O&M Costs $0 $224,169 $934,782 $3,231,013 Annual Cost of Control $0 $413145 $1,281,851 $8,141,177 ENViRONMENTAL IMPACTS: Tons perYear NOx Emissions 2719.5 1359.8 815.9 388.5 Tons perYear NOx Reduction 0 1359.7 1903.7 2331.0 Highest modeled 98th percentile declview dv values 0.566 0.432 0.368 0.321

Deciview reduction 0 0.134 0.198 0.245



# ...COST EFFECTIVENESS': Dollars perton reduced N/A $304 $673 $3493 Incremental dollars perton reduced N/A $304 $1,597 $16051 Dollars perdv reduced N/A $3,083172 $6,473 995 $33,229,294 Incremental dollars per dv reduced N/A $3,083172 $13,573,531 $145943,106

, Cost effectiveness values are underestimated because the annual power costs and annualized capital costs associated with downtime for control installation have not been estimated or included in the caiculation ofthese values. Control equipment capital costs are estimated based on budgetary quotes from equipment vendors. The capital recovery factor of 10.98 percent of capital cost is based on a 7 percent annual interest rate and a control life of 15 years as outlined in U.S. EPA's Control Cost Manual (6th Edition
- January 2002). Annual operating and maintenance costs reflect current FMC costs for labor and other services. The highest modeled deciview values reflect the maximum 98th percentile value obtained from modeling the visibility impact ofthe specific NOx control option (see Section 4.3). Cost effectiveness values (dollars perton reduced and dollars per deciview reduced) vary due to differences in capital investment requirements and operating costs associated with each option. The incremental cost effectiveness data are the cost ofthe control alternative compared to the next most stringent control alternative.

4.3 NOx BARTVisibility Analyses
The visibility impacts to the Bridger and Fitzpatrick Wilderness areas resulting from application ofthe NOx control alternatives were evaluated using the visibility assessment methodology described in Section 2 ofthis addendum. Boilersource parameters, baseline emission rates, and baseline visibility modeling results can be found in Section 2.6. Model input data for each ofthe NOx control alternatives are listed in Table 4-3

.



# ....... ' .Table 4-3 Emission Rates for NOx Control Alternatives

NS-1A NS-1B #6 coalfired boiler

#7 coalfired boiler 170 170 359000 359,900 310.44 310.44 186.27 186.27 88.7 88.7


### Visibility modeling results associated with the application ofeach option are listed in Tables 4-4 thru 4-6. These resuits depict the improvement in visibility over baseline conditions from use of NOx controls alone.
Table 4-4 Visibility Modeling Results - NOx Control Option 1

NS-1 A: 98 ercentile lldv NS-1 B: 98 ercentile lldv 0.432 0.432 0.302 0.303 0.393 0.252 0.247 0.394 0.252 0.248 0.206 0.206
Table 4-5 Visibility Modeling Results - NOx Control Option 2

NS-1A: 98 ercentile lldv NS-1 B: 98 ercentile lldv 0.368 0.368 0.256 0.256 0.340 0.221 0.203 0.340 0.221 0.204 0.181 0.181 Table 4-6 Visibility Modeling Results - NOx Control Option 3

NS-1 A: 98 ercentile lldv NS-1 B: 98 ercentile lldv 0.321 0.321 0.225 0.224 0.295 0.194 0.191 0.295 0.193 0.192 0.161 0.162

### Conclusions from NOx control option modeling:

• Visibility modeling indicates that application of either ofthe NOx control options to an individual boiler, even without any changes to otherexisting pollution control equipment, results in visibility impacts from that unit that are belowthe Division's 0.5 dv guideline value fordetermining that asource contributes to visibility impairment in any Class 1 area.

• Since there would be no perceptible difference in visibility Improvement as a result ofapplication ofa particular control 0

### ption, FMC proposes control option 1 (low NOx burners with overfire air) as BARTfor NOx. Implementation of NOx controls in conjunction with SOx controls is discussed in Section 

### 5.



# AUUlliIJ

..···**.~~**

### 5.0 Selection of BART 

### for FMC Westvaco Sources
5.1 Combined Application of BARTforsax and NOx Emissions BARTanalysesforcontrol ofsaxand NOxemissionswere presented in Section 3and Section 4 respectively. Thevisibility modeling results forthe exclusive application ofany of the saxor NOx control options on an individual boiler, even without any accompanying changes to the othercontrol eqUipment, indicated thatvisibility impacts to the wilderness areas from that unitwere reduced to levels lessthan 0.5 dv. The combined implementation ofboth saxand NOxcontrois will result in even lowervisibility impacts. Table 5-1 summarizes the source parametersfor installation ofthe combined controls.
Table 5-1 Source Parameters forVisibilityAnalyses Combined SOxand NOxControl

Exhaust Rale, ACFM Stack Tem de. F S02 ibs/mmBTU Ibs/hr I H2S04Ibs/mmBTU Ibs/hr I NOx Ibs/mmBTU Ibs/hr t 359,000 170 0.45 399.15 1748.3 1.16E-02

10.3 45.1 0.35 310.45 1359.8 359,000 170 0.45 399.15 1748.3 1.16E-02

10.3 45.1 0.35 310.45 1359.8 

### The modeled impacts on visibility in the two wilderness areasthat resultfrom the simultaneous retrofit ofsax and NOxcontrols on each boilerare shown in Table 5-2. Table 5-2 Visibility Modeling Results
- Combined SOx and NOx Control

NS-1A: 98 ercenille Lldv NS-1 B: 98 ercentile Lldv 0.275 0.275 0.179 0.179 0.260 0.260 0.143 0.123 0.143 0.123 0.128 0.129

### The data in table 5-2 indicatethat application of both SOxand NOxcontrols on each boiler produces modeled visibility impacts foreach unitthat are significantly lessthan the Division's guideline value of0.5 dvfordetermining that asource contributes to visibility impairment in Class 1 areas.
5.2 BART Proposal The analyses presented in this addendum demonstratethatthe application ofSOxand NOx control options, individually, but particularly in combination, result in significant improvement in visibility impacts in the Class 1 wilderness areas. It has also been shown that the capital investment and annualized cost ofachieving additional fractional (but imperceptible) improvements in visibilityare extremely high. Consequently, FMC proposes the application of SOx scrubber upgrades and low NOx burnerswith overfire airas BARTfor coal-fired boilers NS-1 Aand NS-1 B.
FMC requests pound perhour(Ibs/hr) emission limitsforS02 and NOx based on a30-day rolling averageforeach parameterthat is calculated by BART Ibs/mmBTU xmax heat input. The proposed emission limitsforeach boilerwould be:
S02: 0.45lbs/mmBTU x 887 mmBTU/hr= 399.151bs/hr 

### NOx: 0.35lbs/mmBTU x887 mmBTU/hr=310.451bslhr


### The FMC Westvaco coal-fired boilers supply steam to the soda ash production process. Consequentlythe boilers are routinely subjectto load swings based on production conditions and associated steam requirements. Establishing the emission limits in Ibs/hrwill not unduly penalize boileroperations in circumstances where these ioad swings result in higherrate emissions (Ibs/mmBTU), but lowermass emissions (Ibs/hr).

### Appendix 1

Cost Effectiveness Analyses Detail •

SOx and NOx Control AlternativesGost EffectivenessAnalysIs. S02 Control Alteratives

Demlsters+ Scrubber ScrubberTop + mods + Stack Control 0 tlon 8asellne Stellc Mixers Reheet EmIssion Rate, Ib/MMBTU 1.20 0.45 0,' Emission Rate, lonsiyr 4662.1 1748.3 1165,5 Emission Rate Reduction, tonslyr 2913.8 3496.8 %Reducllon 62.5% 75.0% Ib/hr 1064.4 399.1 266.1 capital CostsDlreot Costs Purchased EqulpmentCosts New Bypass Ductlng 

# • 75,000 

# • 75,D00 ExpansionJoints 

# • 24,000 

# • 24,000

Scrubber RoOf 

# • 77,700 

# • 162,900 Scrubber demlster 

# • 162,900 

# • 77,700 Wash & purge lines 

# • 12,000 

# • 12,000 Scrubber Instrumenlallon 

# • 20,000 

# • 20,000

Flue gas reheat system 

# • 697,700 Sales Tax (5.5%) 

# • 20,438 

# • 53,465

Freight (4%) 

# • 14,684 

# • 42,772 Subtotal (PEC) 

# • 406,902 

# • 1,165,537 DIrect Installation Costs Labor 

# • 858,700 

# • 1,133,600 OutsIde Engineering Support 

# • 230,750 

# • 346,125 Demolish existing ductlng & roof 

# • 36,600 

# • 36,600 Rental crane for roof 

# • 50,000 

# • 65,000 Subtotal 

# • 1,176,050 

# • 1,581,325 Total DirectCosts (TDC) $ 1,582,952 $ 2,746,862 Indirect Costs Indirect Installation Costs Engineering (15%TDC) $237,443 $412,029 Escalation (12% ofTOC) $169,954 $329,623 Slartup and Perf. Tests (1 %ofTOC) $15,830 $27,469 Total IndirectCosts $443,227 $759,121 TOC + TIC $2,026,179 $3,515,983 Contlngenc:y(15%) $303,927 $527,398

Annual Direct Annual costs DirectLebor (@$48/hr) I 52,560 

# • 78,840 Malnt. Labor (@$5D/hr) $ 50,000 I 75,000 Replacement Parts (5% of PEG) 

# • 20,345 

# • 58,277 Steam generation cost 

# • 846,400 Total DirectAnnualCosts I 122,905 

# • 1,058,517 Indirect Mnual costs Ovemead( (60% OfJabor) 

# • 61,536 

# • 92,304 PropertyTax (1% ofTCI) 

# • 23,301 

# • 40,434

Insuranoe (1% orrcr) 

# • 23,301 $ 40,434 Administration (2% ofTCI) 

# • 46,602 

# • 80,868 Tota/lndlrec:tAnnualCosts 

# • 154,740 

# • 254,039

Control carital recovery costs Tolal Annualized Cost

Demrsters Scrubber mods +Stack Reheat Demisters +ScrubberTop +Static Mixers Baseline 255,846 

# • 443,963 

# , 633,491 

# • 1,756,519
DeclYlew Total Tolal Average Incremental Reduollon Capital Annualized Cost eo" Emissions 98th Percentile over baseline Investment Cost

0,' 0.384 0.182 

# • 4,043,381 $1,756,519 

# • 9,651,205 $ 61,151,421 0,46 0.404 0.162 

# • 2,330,105 

# • 633,491 3,293,154 

# • 3,293,154 1,2 0,566
Note: In the lable above, the capital Investment costs and annUalized costs reflect the cosls to modify each coal-fired boiler. Cosl effectiveness values are underestimated beoausa the annual powercosts and annualized capital cosls associated with downllme 10rcontrollnslallalion have not been estimated or Inoluded In the calculation ofthesevaluesControl Option Emission Rate, IbfMMBTU Emission Rate, tonslyr Emission Rate Reduction, tons/yr % Reduction Ibfhr Baseline 0.7 2719,5
620.9 Cost EffecllYeness Analysis
- NOx Control A1lernatiYes

burnersw. burnersw. w. OFA, SCR, u raded OFA OF SNCR ba house 0.35 0.21 0.1 1359.8 815.9 388.5 1359.7 1903.6 2331.0 50.0% 70.0% 85,7% 310.44 186.27 86.69 Capllal Costs Direct Costs PurohasedEqulpmentCosfs Low NOx Burners Enlarge oYerflre air ports Indlllldual OFA port dampers Class 1 Igniters New burner elbows

instrumentation Pumps & Piping SNCR SCR Taxes (5%) Freight (4%) Subtolotal(PEC) Direct Installation Costs Labor Outside Engineering Support Matertals Subtotal I I I I 235,000 $ 100,000 $ 40,000 $ 31,800 $ 88,000 $ 136,000 $ I I I 30;530 $ 24,424 $ 665,554 $
258,500 $ 230,750 $ I 489,250 $ 235,000 $ 100,000 $ 40,000 $ 40,000 $ 68,000 $ 200,000 $ 372,500 $ 50,000 $ I 55,275 $ 44,220 $ 1,204,995 $

631,000 $ 230,750 $ I 861,750 $ 235,000 100,000 40,000 40,000 68,000 200,000 50,000 8,790,927

478,196 380,957 10;381,081
7,550,373 1,707,430

397,600 9,655,403 Total DIrectCosts (TDC) $ 1,154,804 $ 2,066,745 $ 20,036,483 Indirect Costs Indirect Installation Costs EngIneering (15% of TOC)

Escalation (12% ofTOC) hJx. gas costs Startup and Perf. Tests Total Indlrsct Cosls TOC +TIC Contingency(15%) $173,221 $206,675 $138.576 $310,012 I I $30,000 $50,667 $341,797 $567,354 $1,496,601 $2,634,099

$224,490 $526,820 $2,003,648 $3,005,473 $12,000,000

$220,365 $17,229,486 $37,265,969 $7,453,194

Annual Costs Direct Annual costs DIrect Labor (@$481hr) Main!. Labor (@$5OIhr) Replacement Parts (5% of PEC) Reagent Replacement Catalyst Replacement Total DIrectAnnualCosls Indireot Annual costs OYerhead( (60% of labor) Propoerty Tax(1% ofTCI) Insurance (1% efTCI) Administration (2% of TCI) Total IndIrectAnnualCosls $ I $
$ 

# • $ $ $ I 26,280 $ 50,000 $ 33,278 $ I 109,558 $
45,768 $ 17,211 $ 17,211 $ 34,422 $ 114,612 $ 52,560 75,000 60,250 544,000 731;810
76,536 31,609 31,609 63,218 202,973 105,120 90,000 519,054 311,000 300,000 1,325,174

117,072 447,192 447,192 894,383 1,905,839

Control capital recoYery costs Total Annualized Cost 347,069 413,145 $ 1,281,851
Daclview Reduction oYer baseline 4,910,164 8,141,177
Total Capital Investment Total Annualized

Ccst Incremental eo,( EffeCtiveness $/declview reducllon

..**,:~** Lcw NOx burnersw. OFA, SCR, baghouse Low NOx burnersw. OFA, SNCR Low NOxburnersw. upgraded OFA Baseline 0.1 0.21 0.35 0.7 0.321 0.368 0.432 0.566 0.245 0.198 0.134 44,719,163 3;160,918 1,721,091 8,141,177 $ 1,281,851 $

413,145 $ 33,229,294 $ 6,473,995 $ 3,083,172 $ 145,943,106 13,573,531 3,083,172

Note: In the table aboYe, the capltallnvastment costs and annualized costs reflect the costs to modify each coal-fired boiler. Ccst effecllYeness values are underestimated because the annual powercosts and annualized capital costs associated wUh downtime for ccntrollnstellallon haYe not been esl1mated or Included In the calculatlcn of these valuesCostEffectivenessAna!;'sls. NO)!

ControlO 

### '" aaseline EmlsslonRate, IbIMMBTU 0,7 Emlsslon Rale, lonslyr 2719.5 Emission Rate ReducUon, Ionslyr %RodueUon 

# '''''' 620.9 CapilalCosts 

### 1O'\1 1819

### 20"" PurchasedEqulpmlJrllCosts f<J "l 1", LowNOxBurners 

# , 235,000 

# , 235,000 

# , 235,000

### ~"l 

## .1}**~'ii>** Enlargeoverfiroairporls 

# , 100,000 

# , 100,000 

# , 100,000 IndlYldualOFAportdampers 

# , 40,000 

# , 40,000 

# , 40,000 

# r: R C1858 1111nilers 

# , 31,600 

# , 40,000 

# , 40,000

### ~lrC£/v, Newburnerelbows 

# , 6a,000 

# , 69,000 

# , 613,000 

### iY 

# cD i"

InslfUmenleUon 

# , 136,000 

# , 200,000 

# , 200,000


### ... FEB (,\1 Pumps &Plplng 

# , , 372,500 

# , 50,000 

### .' 200. '" SNCR 

# , , 50,000 

# , A/RQUAl! 

### '8 

### f{} seR 

# , , $ 0,790,927 Texell(6%J 

# , 30,530 

# , 55,275 

# , 476,196 

### f)/ViSIOf'{

# rr FreIght(-1%) 

# , 24,424 

# , 44,220 

# , 3eO,957 SrtIJfololal(PEC} 

# , 665,554 $ 1,204,995 

# , 10,361,081 <:"9 DirectInslallallonCOllis 

### -9t>S-

### <'L

__"

... Labor 

# , 258,500 

# , 631,000 

# , 7,550,373 Outslcle E:nglooorlngSupport 

# • 230,750 

# , 230,760 

# • 1,707,430 Materials 

# , , , 397,600 Sublo/el $ 489,250 

# , 681,760 $ 9,655,403 TotalDirectCosls (TOC} S 1,154,804 $ 2,066,745 S 20,036,483 lodjfQGICQils IndirectInslallatlonCosls EngIneering(15%ofTOC) $173,221 $206,675 $2,003,648 EscalaUon(12%01 TOC) S136,576 $310,012 $3,005,473 Aux.. gas cosls 

# , $12,000,000 SlartupandPerf. Tesls $30,000 $50,667 $220,365

Tofal/ndfrectCosts $341,797 $567,354 $17,229,486 TDC +TfC Sf,496,601 $2,634,099 $37,265,969 ConUngem:y(I6%' $224,490 $526,920 $7,453,194 Tolal**Cup~all~all~rIt** (TCI) 

## -' 1,721,091 .$**.~,1t?Q,{l18** 

# , 1 4,7.!.l),ti33 AMualCos!s DlleC! AnnUAl**GQ~!s** OJrecILabor(@$46Ihr) 

# , 26,280 

# • 52,560 $ 105,120 Mulf'ltLabor(@$5GAn) S 50,000 $ 75,000 

# • 90,000 ReplacomantParis (5% orPECl $ 33,278 

# , 60,260 S 519,054 ReegentReplacement 

# , 544,000 

# , 311,000 CalalyslReplacolll9nt 

# , 300,000 rotelDlI'6c1AnnuillCosl$ 

# , 109,558 731,610 $ 1,325,174 IndiraclAnnual eelsls OV8rheatS( (60% 01 raoor) 

# , 45,768 $ 76,536 $ 117,072 PropoeflyTaK**(n~** 01 TCI) S 17,211 

# , 31,609 

# , 447,192 Insurance (1% oITCI) $ 17,211 

# , 31,809 

# • 447,192 AdmlnlstraUon (2% 01 TCI) S 34,422 $ 83,218 

# , 694,363 Totallndil'6clAnnuelCosts S 114,612 

# , 202,973 $ 1,905,839

TotalAooualO&M CoslS 224.169 

# ,**{l34,.~!,~** 

# ,**3,~31,01a,** 

### , Conltolcapilalrecoverycosls 

# , 169,976 

# • 347,069 $ 4,910,164 TotalAnMa&zadCost 

# , 413,146 S 1,281,851 

# , 8,141,177

Deelvlaw TOlal Tota! Averaga Incremantal ReducUon Capillil Annuaized Cosl Cosl Emissions 96th PelcenUle overbassgne Investment C051 Effectiveness ElfecQvaness Conlrol Alternative**.1~5IMMBTU** dvValua 

## " 

# , $lyr S!cte?lviawraducllon <$/daClvlnwradoollon 

# .. - . LowNOxburnarsw. OFA, SCR, baghouse 0.1 0.663 0.461 

# , 89A36,328 $ 16,282,354 

# , 35,319,640 S 161,395,906 LowNOxburnersw. OFA, SNCR 0.21 0.748 0.376 

# , 8,321,637 

# , 2,563,702 

# , 6,616,356 S 31,025,214 LewNOx!lorlltlrsw. upgradedOFA 0.26 0,604 0,320 

# • 3,442,182 

# , 626,290 

# , 2,562,156 $ 2,582,158 Baseline 0.7 1-124 Nole; In this labla, Ilia copltallnvaslillantcOsls andaMualizadcosts ranecllhecO$ls 10 modifyboth coal-tiredboilers. Tills**r~** conslstenll'oilhthe**v1slbt~ty** ana!;'sls daclviewdataWhichreflect Implemenlationofcontrolsonbothboilers.CoslErrecllvenl)ss Analysis

-Partlculale

By-pass Control Dollon Basellna Pollshfnll Filler WeIESP FabricFilter EmIssIon Rale, Ib/MMBTU 0.0507 0.040 0.019 0.015 EmissIon Rale,lbJ1lr 

# •• 35.5 16,9 13.3 Emission Rale, lonslyr 197.0 155.4 73.8 58.3 Emission RaleReducllon, lonslyr 41.6 123.2 138,7 % Reducllon 21.1% 62,5% 70.4% CepUslCosls Dlrec! Coals Purchased aqulpmentCos!s BasIc&AwcEquip!. Costs 5 2,673,119 S 6,321,500 S 6,040,927 SIr'\lctllralSupport(10%) 5 267,312 S 632,150 S 604,093 DuctworkS'x9' S 05,ZOO S $ Ductwork9'x 15' $ 5 S 268,600 Ductwork 10'x 13' 5 S 128,800 5 128,800 SalesTax(5.5%) S 166,980 S 389,535 S 387,344

FreIght(4%) 5 121,425 5 283,200 $ 281,705 Subtotoal(PEC) 5 3,324,018 5 7,755,263 $ 7,711,669 DirectlostallononCosis labor 5 2,537,397 S 5,163,080 S 6,600,373 Adjust. forRelrofilCondllions S 986,561 S 2,023,931 S 2,364,944 Malarlals 5 Subtotal $ 3,525,958 5 7,186,991 $ 9,165,316 TottilDirect00'($(TOC) S 6,849,974 S 14,942,274 $ 16,876,985 IndIrect Costs IndIrectloslallallonCosts Engineering (15% ofPEC) $491),602 $1,163,292 $1,156,750

EscaloUon (12% ofTOC) $821,997 $1,793,073 $2,025,236 AUK. gas cosls 50 $0 50 Sler1up andPerf. Tests $78,500 $159,423 $178,770 TotarindirectCosls $1,399,099 $3,116,788 $3,360,758 TDC+TIC $6,249,073 $18,058,062 $20,237,743 Connngency(16% ofTOC) $1,237,361 $2,708,709 $3,036,682 I,o,l!1'**9~~I~ll:'!t:'~~,s,~.e~t, (r~!)**  ,.**_t!,~~~,~** 

### s .29

..**?~~,n~.** 5 23;273,405

.**:'~'>--"'::""~"-:':** '."'.,'.,:\,--:

. 

### --', AnnualCosis plroc! Annualcos!s DirectLabor(@$461hr) 5 52,560 5 52,560 S 62,660 Malnl.labor (@$50ihr) 5 75,000 S 50,000 S 100,000 ReplacementParts (3·5% ofPEC) 5 166,201 S 232,656 S 365,663 Electricity ($O.04/kw*hr) TotalDIrectAnnua1 Cosls S 293,761 S 335,216 5 538,143 IndirectAnnualcosls Overhead( (60% oflabor) 5 76,536 S 61,536 S 91,536 PropoertyTBX(1% ofTCI) S 94,004 S 207,668 S 232,734 Insurance(1% oITCI) 5 94,664 $ 207,668 S 232,734 Admlnlstrallon (2% ofTCI) 5 169,729 S 415,335 5 465,466 Total(ndfrectAnnualCo.sls S 455,993 S 892,207 5 1,022,472**.rC?l~IAn.rnl.al** O&MCosls S 749,764 S**.1,.~~7~42.5.** 5**1,56.0,61.~.** ',' Controlcapital recoverycosts S 1,041,610 S 2,260,192 5 2,555,420 TolalAnnualized Cosl S 1,791,365 5 3,507,617 S 4,116,036

EmissIons Tolal Tolal Average Incremenlal ReducUon Cepllal Annualized Cost Cost Emissions Emlllslons overbase Inveslmenl Cost Effecllveness EifecUvenes$ Control Altstnatlve**l~s~~~"!:U 1.~n~Iy.~**  , ", lon.sly!,**-~** -. SIy,-**I"·~?n,,** ..**~t.on ;Fabn:~:~I{i~;**  . 0.016 68.3 - 136.7 S 23,273;405' 

### s**4,11'6~O36** 

## lif**:-2t~j.;** S 39,151 WetESP 0,019 73.8 123,2 5 20,766,772 $ 3,607,617 $ 26,481 S 21,036 By-pass PolishIng Filler 0.04 155.4 41.8 5 9,400,434 $ 1,791.365 5 43,003 Baseline 0.0507 197,0Cost EfroolivllMU Ar'Ill!jsIS· 802 COIll/ols

Deffilslers .j. StnlbOOr SCfubber Topt mods +Stack**Conl/olQJl:\I~!L,,** ________, ___" ,[3;a&1l 

### • SloUt**lAix..~!.L.** • Reheat EmissIon Itale, Ib.'MMBTU 1.20 OA' 0.3- Emission Ratartonslyr 46,6,2.1 1746.3 116&.5 Emission Ratti RllducUon, tOIlSfy'1 2b13.0 :?4116,6 % ReducUon 62.6% 75.0% 

# """ 1064.4 399.1 286.1 CapilalCos15 Pllrcllasf!d t::quipmllnICosl&**NQwB~pass** OucllnrJ $ 71>,000 $ 75,000 Expam;lonjolnts 

# • 24,000 

# , 24,000 SCwbber Roof S 77,700 

# , 162,900 SOIl.lbber**den~sh1r** S 162,900 

# , 77,700 Wosh&pu!j)(l'OOS S 12,000 

# , 12,000 Stwb!xlf InslrumonUlUon 

# , 20.000 S 20,000

FillQ gas reheal**s~stom** S 691,100 Sakls Tnx (5.5%) S 20,436 

# , 53,465

Flelglit(4%) 5 \4,864 S <\2,712 Sub/alel/PEW; S 400,902 

# , 1.165,637 Olrl)CllnstaUallOflCosls l.abor 856,700 

# , 1,133,600 Ou1sldG Englnoonog Support 230.700 S 346,125 Damo_sh OOIlsUng dueling &rool 36,600 

# , 36,600 Rllmal crllne lorrool 50;000 S 65,000 Sublolel 1.176,050 

# , 1,561,326 fo/alD/liu,/Cl»ls(rDC) $ 1,582,!}/32 S 2,746,M2 """'lJ&m**Indi~(;\** InstallallOl1 C(lsb F..nglooarlng (15%TDC) $237,443 $412,0211 Escalation (12% OfTOO) $16\1,\164 $329,623 StartupaOO Parf. Tos!s (1% of rDC) $15J130 627,469 To{a/lndlrocl Costs $443;227 $7(;9,121 roc +TIC $2,026,179 $3,515,983 Conlf/IiJa/lcy 116%) $3001,927 $627,398

Annl.lalCosl$ Qlf!l¢! Annualcosls Directtabor (@S4l!!tJr) S 52,560 

# , 78,840 Malnl Labor (@ S5OJlv) S 50,000 

# , 75,000 RaplllO!l1l'\l'lfll Parts (5% of PEC) S 20,345 S 5&,277 Staamgeneration cost S a46,40{1 70lel DI(9I;/Anrlliel Cosis U2,905 

# , 1,058,517**~I.I/ll~** Ovarhead( ((10% ormoor) S 61,536 

# , 1'12,304 ProperlyTax (1% ofTCI) 

# , 23,301 

# , 40,434

In&vrunco (1% crrCl) 

# , 23,301 S 40,434 Adrnlnlal/llUon (2% ofTel) 

# , 46,602 

# , 90,989 Tolal/mHreclAnnualCosls 

# , 154,740 $ 254,039

Control oapltal recov(lry cosls 266,846 443,063 Tollli Armalizod Cosl S33,491 

# , 1,756,519

Deolvlow RocucUPIl**En~$g!ol\$** 96th PefellntllG ol'Olooaatioo**Ibs!M_~!3J~**

Damlalers +ScrubberTop +**S\e~c** Mlxar! BaSE/liM 0.3 0,45 1.2**();70~** 1.023 1.124 Q.421 0.101 l.\0fl6,762 $3,513,039 S $ 4,000,211 $1,066,982 6.344,&10 10,564,176 1,643,928

Nole: IrlltII! tabla, Il1e tapllallnveslmentiio"s"(i"llI'ld**annlJa~lad** OO$lS rBflacfUie"costs to**m~dlfy** bo1l1**c~a~nred** bollars. '"hlsls cor.slsia/lll'>llh tlltl'll$lbMy llnalysls (/(Jclvlawdo!lll'lhich r&flect**Impi(lrtlllnta~oll** ofcontrols 011 bol.h bolklrs.