### P:\PACIFICORP\370414BART2\TECHNICAL_MEMORANDUM_DELI VERABLES\BART_TMS_JIMBRIDGERUNIT3_FINAL.DOC 1 

# TECHNICAL MEMORANDUM



# Addendum to Jim Bridger Unit 3 BART Report

PREPARED FOR: 

# Wyoming Division of Air Quality

PREPARED BY: 

# CH2M HILL

COPIES: 

# Bill Lawson/PacifiCorp

DATE: 

# March 26, 2008



# Introduction

In compliance with the Regional Haze Rule (40 Code of Federal Regulations [CFR] 51), the Wyoming Division of Air Quality (WDAQ) required PacifiCorp Energy to conduct a detailed Best Available Retrofit Technology (BART) review to analyze the effects to visibility in nearby Class I areas from plant emissions, both for ba seline and for reasonable control technology scenarios. PacifiCorp submitte d these evaluations to WDAQ in January 2007. A revised report

was submitted in October 2007.

On January 3, 2008, PacifiCorp Energy personnel met with WDAQ staff to discuss the status of the BART reviews. At that time, the state re quested that additional modeling scenarios for several of the PacifiCorp facilities be performed to aid in their BART review. This memorandum presents the economics analysis for two scenar ios modeled, referred to as Scenario A and

Scenario B and described as follows:

• 

# Scenario A: PacifiCorp committed controls at permitted rates—low nitrogen oxide (NO

x 

# ) burners (LNBs) with over-fire air (OFA), sodium based flue gas desulfurization (FGD),

SO 3 

# injection

• 

# Scenario B: PacifiCorp committed controls and selective catalytic reduction (SCR) at permitted rates

The CALPUFF modeling system (v. 5.711a) was used for this analysis. All technical options and model triggers used in CALMET, CALPUFF, and CALPOST are consistent with those used for the previous BART analyses and described in the BART report submitted in October 2007.



# Stack Parameters, Emissions Information, and Capital Cost

Table 1 summarizes the control equipment for Scenarios A and B as well as the current equipment installed at the plant. The overall capital cost of installing these options is also shown.

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# TABLE 1 

# Control Scenario Summary Jim Bridger Unit 3

Equipment Type Capital Cost

NO
x 

# SO 2 

# PM 10 

# Million dollars

Baseline LNB Wet sodium FGD ESP —

Scenario A LNB with OFA Wet sodium FGD ESP with SO 3 

# injection $40.5

Scenario B LNB with OFA and SCR Wet sodium FGD ESP with SO 3 

# injection $207.0



# Emissions were modeled for the following pollutants:

• 

# Sulfur dioxide (SO 2 

# )

• 

# NO

x



# • 

# Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• 

# Fine particulate (diameter<PM 2.5 

# )

• 

# Sulfates

Table 2 shows stack parameters and emission rate s that were used for the Jim Bridger Unit 3 BART modeling and analysis.

TABLE 2 

# Calpuff Model Inputs Jim Bridger Unit 3

BART Comparison (d)



# Model Input Data Baseline Scenario

A (e) 

# Scenario

B (f)



# Hourly Heat Input (mmBtu/hour) 6,000 6,000 6,000

Sulfur Dioxide (SO 2 

# ) Stack Emissions (lb/hr) 1,602 900 900

Nitrogen Oxide (NO
x 

# ) Stack Emissions (lb/hr) 2,700 1,560 420

PM 10 

# Stack Emissions (lb/hr) 342 180.0 180.0

Coarse Particulate (PM 2.5 

# <diameter< PM 10 

# ) Stack Emissions (lb/hr) (a) 

# 147 77.4 77.4

Fine Particulate (diameter<PM 2.5 

# ) Stack Emissions (lb/hr) (b) 

# 195 102.6 102.6

Sulfuric Acid (H 2 

# SO 4 

# ) Stack Emissions (lb/hr) 55.2 55.2 94.7

Ammonium Sulfate [(NH 4 

# ) 2 

# SO 4 

# ] Stack Emissions (lb/hr) — — 7.0

(NH 4 

# )HSO 4 

# Stack Emissions (lb/hr) — — 12.2

H 2 

# SO 4 

# as Sulfate (SO 4 

# ) Stack Emissions (lb/hr) 54.1 54.1 92.8

(NH 4 

# ) 2 

# SO 4 

# as SO 4 

# Stack Emissions (lb/hr) — — 5.1

(NH 4 

# )HSO 4 

# as SO 4 

# Stack Emissions (lb/hr) — — 10.2

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# TABLE 2 

# Calpuff Model Inputs Jim Bridger Unit 3

BART Comparison (d)



# Model Input Data Baseline Scenario

A (e) 

# Scenario

B (f)



# Total Sulfate (SO 4 

# ) (lb/hr) (c) 

# 54.1 54.1 108.1

Stack Conditions

Stack Height (meters) 152 152 152

Stack Exit Diameter (meters) 7.32 7.32 7.32

Stack Exit Temperature (Kelvin) 333 328 328

Stack Exit Velocity (meters per second) 25.6 24.7 24.7

NOTES:
(a) 

# Based on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM 10 

# . This equates to 43% ESP and 57% Baghouse. PM 10 

# and PM 2.5 

# refer to particulate matter less than 10 and 2.5 micrometers, respectively, in aerodynamic diameter. (b) 

# Based on AP-42, Table 1.1-6, the fine parti culates are counted as a percentage of PM 10 

# . This equates to 57% ESP and 43% Baghouse.
(c) 

# Total Sulfate (SO 4 

# ) (lb/hr) = H 2 

# SO 4 

# as Sulfate (SO 4 

# ) Stack Emissions (lb/hr) + (NH 4 

# ) 2 

# SO 4 

# as SO 4 

# Stack Emissions (lb/hr) + (NH 4 

# )HSO 4 

# as SO 4 

# Stack Emissions (lb/hr)
(d) 

# SO 2 

# , NO
x 

# , and PM rates are expressed in terms of permitted emission rates. Actual emissions will be less than the permitted rates. (e) 

# PacifiCorp Committed Cont rols @ permitted rates : LNB with OFA, Wet FGD, ESP with SO 3 (f) 

# PacifiCorp Committed Controls and SCR @ permitted rates



# Economic Analysis

In completing this additional analysis to supplement the previous BART study, technology alternatives were investigated and potential reductions in NO

x 

# , SO 2 

# , and PM 10 

# emissions rates

were identified.

A comparison of Scenarios A and B on the basis of costs, design control efficiencies, and tons of pollutant removed is summarized in Tables 3 through 5. Capital costs were provided by PacifiCorp. The complete economic analyses for these two scenarios are provided as

Attachment 1.ADDENDUM TO JIM BRIDGER UNIT 3 BART REPORTJMS ES032008003SLC\BART_TMS_JIMBRIDGERUNIT3_FINAL.DOC4TABLE 3Scenario A Control CostJim Bridger Unit 3NOxControl SO2Control PM10Control Scenario ALNB with OFAWet FGDESP with GasConditioningControl CostTotal Installed Capital Costs (million dollars) $11.3 $25.3 $3.90 $40.5Annualized First-Year Capital Costs$1.07$2.41$0.37$3.85First Year Fixed & Variable O&M Costs (million dollars)$0.07 $0.98 $0.18 $1.22Total First Year Annualized Costs (million dollars)(a)$1.15 $3.39 $0.55 $5.08Power Consumption (MW)—0.520.050.57Annual Power Usage (Million kWh/Yr)—4.100.394.49Permitted Emission Rate (lb/mmBtu) 0.260.150.03—Additional Tons of Pollutant Removedper Year over Baseline4,4942,8386397,971First Year Average Control Cost ($/Ton of Pollutant Removed)2551,193856637NOTE:(a)First year annualized costs include power consumption costs.ADDENDUM TO JIM BRIDGER UNIT 3 BART REPORTJMS ES032008003SLC\BART_TMS_JIMBRIDGERUNIT3_FINAL.DOC5TABLE 4Scenario B Control CostJim Bridger Unit 3NOxControl SO2Control PM10Control Scenario BLNB with OFA &SCRWet FGDESP with GasConditioningControl CostTotal Installed Capital Costs (million dollars) $177.8 $25.3 $3.90 $207.0Annualized First-Year Capital Costs $16.91 $2.41 $0.37 $19.69First Year Fixed & Variable O&M Costs (million dollars)$3.36 $0.98 $0.18 $4.52Total First Year Annualized Costs (million dollars)(a)$20.28 $3.39 $0.55 $24.21Power Consumption (MW)3.220.520.053.79Annual Power Usage (MillionkWh/Yr) 25.394.10 0.39 29.89Permitted Emission Rate (lb/mmBtu) 0.070.150.03—Additional Tons of Pollutant Removed perYear over Baseline8,9882,83863912,465First Year Average Control Cost ($/Tonof Pollutant Removed) 2,256 1,193 856 1,942NOTE:(a)First year annualized costs include power consumption costs.ADDENDUM TO JIM BRIDGER UNIT 3 BART REPORTJMS ES032008003SLC\BART_TMS_JIMBRIDGERUNIT3_FINAL.DOC6TABLE 5Incremental Control Costs, Scenario B compared to Scenario AJim Bridger Unit 3NOxControl SO2Control PM10ControlTotalControl CostIncremental Installed Capital Costs (million dollars) $166.5 0 0 $166.5Incremental Annualized First-YearCapital Costs$15.8400$15.84Incremental First Year Fixed & VariableO&M Costs (million dollars)$3.3000$3.30Incremental First Year Annualized Costs (million dollars)(a)$19.13 0 0 $19.13Incremental Power Consumption (MW)3.22003.22Incremental Annual Power Usage (Million kWh/Yr)25.390025.39Incremental Improvement in Emission Rate (lb/mmBtu)0.1900—Incremental Tons of PollutantRemoved4,494 0 0 4,494Incremental First Year Average Control Cost ($/Ton of PollutantRemoved)4,258 0 0 4,258NOTE:(a)Incremental first year annualized costs include power consumption costs.

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# Modeling Results and Least-Cost Envelope Analysis

CH2M HILL modeled Jim Bridger Unit 3 for two post-control scenarios. The results determine the change in deciview based on each a lternative at the Class I areas specific to the project. The Class I areas potenti ally affected are Bridger Wild erness, Fitzpatrick Wilderness,

and Mount Zirkel Wilderness for this unit.

Modeled Scenarios

Current operations (baseline) a nd two alternative control scenar ios were modeled to cover the range of effectiveness for the combination of the individual NO

x 

# , SO 2 

# , and PM control technologies being evaluated. The mode led scenarios incl ude the following:

• 

# Baseline: Current operations with LNB, Wet sodium FGD, and ESP

• 

# Scenario A: LNB with OFA, Wet sodium FGD, and ESP with SO 3 

# injection

• 

# Scenario B: Scenario A with SCR

Summary of Visibility Analysis

Tables 6 through 8 present a summary of the modeli ng period (2001–2003) results for each

scenario and Class I area.

TABLE 6 

# Costs and Visibility Modeling Results as Applicable to Bridger Wilderness Jim Bridger Unit 3

Scenario Controls Total First Year

Annualized Cost Highest Δ dV 98 th



# Percentile

Δ dV Maximum

Annual
Number of Days Above

0.5 dV

Baseline Current Operations with FGD
and ESP — 4.381 1.265 30

Scenario A Scenario A: PacifiCorp
Committed Controls $5,077,127 2.919 0.829 17

Scenario B Scenario B: PacifiCorp
Committed Controls and SCR $24,210,545 1.647 0.481 10

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# TABLE 7 

# Costs and Visibility Modeling Results as Applicable to Fitzpatrick Wilderness Jim Bridger Unit 3

Scenario Controls Total First

Year

Annualized
Cost Highest Δ dV 98 th



# Percentile

Δ dV Maximum

Annual
Number of Days Above

0.5 dV

Baseline Current Operations with FGD
and ESP — 2.542 0.615 13

Scenario A Scenario A: PacifiCorp
Committed Controls $5,077,127 1.747 0.379 7

Scenario B Scenario B: PacifiCorp
Committed Controls and SCR $24,210,545 0.959 0.232 4

TABLE 8 

# Costs and Visibility Modeling Results as Applicable to Mount Zirkel Wilderness Jim Bridger Unit 3

Scenario Controls Total First

Year

Annualized
Cost Highest Δ dV 98 th



# Percentile

Δ dV Maximum

Annual
Number of Days Above

0.5 dV

Baseline Current Operations with FGD
and ESP — 3.460 1.642 47

Scenario A Scenario A: PacifiCorp
Committed Controls $5,077,127 2.168 1.046 22

Scenario B Scenario B: PacifiCorp
Committed Controls and SCR $24,210,545 1.298 0.607 12



# Results

Tables 9 through 11 present a summary of the co sts and modeling results for each scenario

and Class I area.

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# TABLE 9 

# Incremental Costs and Incremental Visibility Improvements Relative to Bridger Wilderness Jim Bridger Unit 3

Scenario Comparison Controls Incremental

Annualized
Cost (Million$) Reduction

in 98 th



# Percentile

maximum

dV Reduction

in Number

of Days

Above

0.5 dV Cost per dV

Reduction (Million$/dV

Reduced) Cost per Day

to Achieve a

Reduction in

the Days

above 0.5 dV (Million$/Day)

Scenario A Compared to

Baseline Scenario A: PacifiCorp
Committed Controls $5.08 0.436 13 $11.64 $0.39

Scenario B Compared to

Baseline Scenario B: PacifiCorp
Committed Controls
and SCR $24.21 0.784 20 $30.88 $1.21

Scenario B Compared To
Scenario A Addition of SCR $19.13 0.348 7 $54.98 $2.73

TABLE 10 

# Incremental Costs and Incremental Visibility Improvements Relative to Fitzpatrick Wilderness Jim Bridger Unit 3

Scenario Comparison Controls Incremental

Annualized
Cost (Million$) Reduction

in 98 th



# Percentile

maximum

dV Reduction

in Number

of Days

Above

0.5 dV Cost per dV

Reduction (Million$/dV

Reduced) Cost per Day

to Achieve a

Reduction in

the Days

above 0.5 dV (Million$/Day)

Scenario A Compared to

Baseline Scenario A: PacifiCorp
Committed Controls $5.08 0.236 6 $21.51 $0.85

Scenario B Compared to

Baseline Scenario B: PacifiCorp
Committed Controls
and SCR $24.21 0.383 9 $63.21 $2.69

Scenario B Compared To
Scenario A Addition of SCR $19.13 0.147 3 $130.16 $6.38

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# TABLE 11 

# Incremental Costs and Incremental Visibility Improvements Relative to Mount Zirkel Wilderness Jim Bridger Unit 3

Scenario Comparison Controls Incremental

Annualized
Cost (Million$) Reduction

in 98 th



# Percentile

maximum

dV Reduction

in Number

of Days

Above

0.5 dV Cost per dV

Reduction (Million$/dV

Reduced) Cost per Day

to Achieve a

Reduction in

the Days

above 0.5 dV (Million$/Day)

Scenario A Compared to

Baseline Scenario A: PacifiCorp
Committed Controls $5.08 0.596 25 $8.52 $0.20

Scenario B Compared to

Baseline Scenario B: PacifiCorp
Committed Controls
and SCR $24.21 1.035 35 $23.39 $0.69

Scenario B Compared To
Scenario A Addition of SCR $19.13 0.439 10 $43.58 $1.91



# Least-Cost Envelope Analysis

The least-cost envelope gra phs for Bridger Wilderness are shown in Figures 1 and 2, for Fitzpatrick Wilderness in Figures 3 and 4, and for Mount Zirkel Wilderness in Figures 5 and 6.

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# FIGURE 1

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Bridger Wilderness

Scenario B

Scenario A

Baseline

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0 5 10 15 20 25



### Reduction in Days of Exceeding 0.5 dV (days)Total Annualized Cost (Mil $)



# FIGURE 2

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Bridger Wilderness

Baseline Scenario A Scenario B

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90



### 98th Percentile Delta-Deciview Reduction (dV)Total Annualized Cost (Mil $)

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# FIGURE 3

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Fitzpatrick Wilderness

Scenario B

Scenario A

Baseline

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0 1 2 3 4 5 6 7 8 91 0



### Reduction in Days of Exceeding 0.5 dV (days)Total Annualized Cost (Mil $)



# FIGURE 4

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Fitzpatrick Wilderness

Scenario B

Scenario A

Baseline

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45



### 98th Percentile Delta-Deciview Reduction (dV)Total Annualized Cost (Mil $)

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# FIGURE 5

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Mount Zirkel Wilderness

Baseline Scenario A Scenario B

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0 5 10 15 20 25 30 35 40



### Reduction in Days of Exceeding 0.5 dV (days)Total Annualized Cost (Mil $)



# FIGURE 6

Least Cost Envelope PacifiCorp Jim Bridger Unit 3 - Mount Zirkel Wilderness

Scenario B

Scenario A

Baseline

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0 5 10 15 20 25 30 35 40



### 98th Percentile Delta-Deciview Reduction (dV)Total Annualized Cost (Mil $)

# ATTACHMENT 1 

# Complete Economic Analyses

for Scenarios A and BECONOMIC ANALYSIS SUMMARY - FIRST YEAR COSTSJim Bridger 3Boiler Design: Tangential fired PCTYPE OF EMISSIONS CONTROLSNOxControl SO2Control and PMScenario A Scenario BTechnology Label BASE A B C D E F G A+F D+FCurrent OperationLow NOxBurners withOverfire AirRotating Overfire AirLow NOxBurners withOverfire Air and NonSelective CatalyticReductionLow NOxBurners withOverfire Air andSelective CatalyticReductionESP w/ GasConditioningFabric Filter Upgrade Wet FGDLNB w/OFA, UpgradeWet FGD and ESPw/gas conditioningLNB w/OFA, SCR,Upgrade Wet FGDand ESP w/gasconditioningECONOMIC FACTORSInterest Rate (%)7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10%Discount Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10%Plant Economic Life (Years) 20 20 20 20 20 20 20 20 20 20CAPITAL INVESTMENTTotal Installed Capital Costs ($) $0 $11,300,000 $20,528,122 $21,973,632 $177,800,000 $3,900,000 $48,386,333 $25,300,000 $40,500,000 $207,000,000FIRST YEAR DEBT SERVICE ($/Yr) $0 $1,074,944 $1,952,796 $2,090,304 $16,913,727 $370,999 $4,602,887 $2,406,734 $3,852,677 $19,691,459FIRST YEAR FIXED O&M Costs ($/Yr)Operating Labor ($/Yr)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0Maintenance Material ($/Yr)$0 $28,000 $42,000 $122,000 $190,000 $0 $51,099 $25,500 $53,500 $215,500Maintenance Labor ($/Yr)$0 $42,000 $63,000 $183,000 $285,000 $10,000 $76,649 $17,033 $69,033 $312,033Administrative Labor ($/Yr)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL FIRST YEAR FIXED O&M COST $0 $70,000 $105,000 $305,000 $475,000 $10,000 $127,748 $42,533 $122,533 $527,533FIRST YEAR VARIABLE O&M Costs ($/Yr)Makeup Water Costs ($/Yr)$0 $0 $0 $0 $0 $0 $0 $29,927 $29,927 $29,927Reagent Costs ($/Yr)$0 $0 $0 $89,411 $1,020,310 $145,854 $0 $383,167 $529,021 $1,549,331SCR Catalyst / FF Bag Costs ($/Yr) $0 $0 $0 $0 $600,000 $0 $294,008 $0 $0 $600,000Waste Disposal Costs ($/Yr)$0 $0 $0 $0 $0 $0 $0 $318,275 $318,275 $318,275Electric Power Costs ($/Yr)$0 $0 $2,526,822 $204,984 $1,269,324 $19,710 $1,312,686 $204,984 $224,694 $1,494,018TOTAL FIRST YEAR VARIABLE O&M Costs ($/Yr) $0 $0 $2,526,822 $294,395 $2,889,634 $165,564 $1,606,694 $936,353 $1,101,917 $3,991,551SUMMARY OF FIRST YEAR COSTS ($/Yr)First Year Debt Service ($/Yr) $0 $1,074,944 $1,952,796 $2,090,304 $16,913,727 $370,999 $4,602,887 $2,406,734 $3,852,677 $19,691,459First Year Fixed O&M Costs ($/Yr) $0 $70,000 $105,000 $305,000 $475,000 $10,000 $127,748 $42,533 $122,533 $527,533First Year Variable O&M Costs($/Yr)$0 $0 $2,526,822 $294,395$2,889,634 $165,564 $1,606,694 $936,353 $1,101,917$3,991,551Total First Year Costs ($/Yr) $0 $1,144,944 $4,584,618 $2,689,699 $20,278,361 $546,563 $6,337,329 $3,385,620 $5,077,127 $24,210,544CONTROL COST COMPARISONSNOxTechnology ComparisonAdditional NOxRemoved From Base Case (Tons/Yr)0 4,494 5,440 5,440 8,988First Year Average Control Cost ($/Ton NOxRemoved)$0 $255 $843 $494 $2,256Technology Case ComparisonA-BASE B-A C-A D-AIncremental NOxRemoved (Tons/Yr)0 4,494 946 946 4,494Incremental Control Cost ($/Ton NOxRemoved)$0 $255 $3,636 $1,633 $4,258SO2Technology Comparison77.5%77.5% 77.5% 87.5%Additional SO2Removed From Base Case (Tons/Yr)00 0 2,838First Year Average Control Cost ($/Ton SO2Removed)$0#DIV/0! #DIV/0! $1,193Technology Case ComparisonE-BASE F-E G-FIncremental SO2Removed (Tons/Yr)00 0 2,838Incremental Control Cost ($/Ton SO2Removed)$0#DIV/0! #DIV/0! -$1,040PM Technology Comparison0.0%Additional PM Removed From Base Case (Tons/Yr)0639 993 0First Year Average Control Cost ($/Ton PM Removed)$0$856 $6,380 #DIV/0!Technology Case ComparisonE-BASE F-E G-FIncremental PM Removed (Tons/Yr)0639 355 -993Incremental Control Cost ($/Ton PM Removed)$0$856 $16,322 $2,971SCENARIO A AND B COMPARISONSAdditional NOx, SO2, & PM Removed From Base Case (Tons/Yr)07,971 12,465First Year Average Control Cost Compared to Base Case ($/Ton Removed)$0$637 $1,942Incremental Tons Removed - Scenario B vs Scenario A (Tons/Yr)04,494Incremental Control Costs - Scenario B vs Scenario A ($/Ton Removed)$0$4,258JMS ES032008003SLC\First Yr Summary\JB3 appendix.xlsPAGE 1 OF 1INPUT CALCULATIONSJim Bridger 3Boiler Design: Tangential-Fired PCPARAMETERCurrentOperationNOxControl TechnologiesScenario A Scenario BControl TechnologiesNOxEmission Control SystemLNCFS-1 & WindboxMods.LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCRLNB w/OFA LNB w/OFA & SCRSO2Emission Control SystemWet FGDN/A N/A Upgrade Wet FGD Upgrade Wet FGD Upgrade Wet FGDPM Emission Control System ESPESP w/ GasConditioningFabric Filter ESPESP w/ GasConditioningESP w/ GasConditioningGeneral Plant Design and Operating DataType of Unit PC PC PC PC PC PC PC PC PC PCAnnual Power Plant Capacity Factor 90% 90% 90% 90% 90% 90% 90% 90% 90% 90%Annual Operation (Hours/Year) 7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884Net Power Output (kW) 530,000 530,000 530,000 530,000 530,000 530,000 530,000 530,000 530,000 530,000Net Plant Heat Rate (Btu/kW-Hr)11,320 11,320 11,320 11,320 11,320 11,320 11,320 11,320 11,320 11,320Boiler Heat Input, Measured by Fuel Input (MMBtu/Hr)6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000Annual Heat Input, Measured by Fuel Input (MMBtu/Year)47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846Boiler Heat Input, Measured by CEM (MMBtu/Hr)6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000Annual Heat Input, Measured by CEM (MMBtu/Year)47,304,00047,304,00047,304,00047,304,00047,304,00047,304,00047,304,00047,304,00047,304,00047,304,000Plant Fuel SourceBoiler Fuel SourceBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundCoal Heating Value (Btu/Lb) 9,660 9,660 9,660 9,660 9,660 9,660 9,660 9,660 9,660 9,660Coal Sulfur Content (wt.%) 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.580% 0.58% 0.58%Coal Ash Content (wt.%) 10.30% 10.30% 10.30% 10.30% 10.30% 10.30% 10.30% 10.30% 10.30% 10.30%Coal Flow Rate (Lb/Hr) 621,077 621,077 621,077 621,077 621,077 621,077 621,077 621,077 621,077 621,077Coal Consumed (Ton/Yr) 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284Nitrogen Oxide EmissionsNOxEmission Rate (Lb/MMBtu)0.45 0.26 0.22 0.22 0.070.26 0.07NOxEmission Rate (Lb/Hr)2,700 1,560 1,320 1,320 4201,560 420NOxEmission Rate (Lb Moles/Hr)89.97 51.98 43.99 43.99 14.0051.98 14.00NOxEmission Rate (Ton/Yr)10,643 6,150 5,203 5,203 1,6566,150 1,656Add'l NOxRemoved from Current Operations (Lb/Hr)0 1,140 1,380 1,380 2,2801,140 2,280Add'l NOxRemoved from Current Operations (Ton/Yr)0 4,494 5,440 5,440 8,9884,494 8,988Sulfur Dioxide EmissionsUncontrolled SO2(Lb/MMBtu)1.201.20 1.20 1.20 1.20 1.20Uncontrolled SO2(Lb/Hr)7,1987,198 7,198 7,198 7,198 7,198Uncontrolled SO2(Lb Moles/Hr)112.35112.35 112.35 112.35 112.35 112.35Uncontrolled SO2(Tons/Yr)28,37428,374 28,374 28,374 28,374 28,374Controlled SO2Emission Rate (Lb/MMBtu)0.270.27 0.27 0.15 0.15 0.15SO2Removal Efficiency (%)77.5%77.5% 77.5% 87.5% 87.5% 87.5%Controlled SO2Emissions (Lb/Hr)1,6201,620 1,620 900 900 900Controlled SO2Emissions (Ton/Yr)6,3866,386 6,386 3,548 3,548 3,548SO2Removed (Lb/Hr)5,5785,578 5,578 6,298 6,298 6,298SO2Removed (Ton/Yr)21,98821,988 21,988 24,826 24,826 24,826Add'l SO2Removed from Current Operations (Lb/Hr)00 0 720 720 720Add'l SO2Removed from Current Operations (Ton/Yr)00 0 2,838 2,838 2,838Particulate Matter EmissionsUncontrolled Fly Ash (Lb/Hr) 51,17751,177 51,177 51,177 51,177 51,177Uncontrolled Fly Ash (Lb/MMBtu) 8.5298.529 8.529 8.529 8.529 8.529Uncontrolled Fly Ash (Tons/Yr) 201,739201,739 201,739 201,739 201,739 201,739Controlled Fly Ash Emission Rate (Lb/MMBtu) 0.0570.030 0.015 0.057 0.030 0.030Controlled Fly Ash Removal Efficiency (%) 99.3%99.6% 99.8% 99.3% 99.6% 99.6%Controlled Fly Ash Emissions (Lb/Hr) 342180 90 342 180 180Controlled Fly Ash Emissions (Ton/Yr) 1,348710 355 1,348 710 710Fly Ash Removed (Lb/Hr) 50,83550,997 51,087 50,835 50,997 50,997Fly Ash Removed (Ton/Yr) 200,390201,029 201,384 200,390 201,029 201,029Add'l Ash Removed from Current Operation (Lb/Hr) 0162 252 0 162 162Add'l Ash Removed from Current Operation (Ton/Yr) 0639 993 0 639 639Economic FactorsInterest Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10%Discount Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10%Plant Economic Life (Years) 20 20 20 20 20 20 20 20 20 20SO2and PM Control TechnologiesJMS ES032008003SLC\Tech Calcs\JB3 appendix.xlsPAGE 1 OF 2INPUT CALCULATIONSJim Bridger 3Boiler Design: Tangential-Fired PCPARAMETERCurrentOperationNOxControl TechnologiesScenario A Scenario BControl TechnologiesNOxEmission Control SystemLNCFS-1 & WindboxMods.LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCRLNB w/OFA LNB w/OFA & SCRSO2Emission Control SystemWet FGDN/A N/A Upgrade Wet FGD Upgrade Wet FGD Upgrade Wet FGDPM Emission Control System ESPESP w/ GasConditioningFabric Filter ESPESP w/ GasConditioningESP w/ GasConditioningSO2and PM Control TechnologiesInstalled Capital CostsNOxEmission Control System ($2012)$11,300,000 $20,528,122 $21,973,632 $177,800,000$11,300,000 $177,800,000SO2Emission Control System ($2012)$0 $0 $25,300,000 $25,300,000 $25,300,000PM Emission Control System ($2012)$3,900,000 $48,386,333 $0 $3,900,000 $3,900,000Total Emission Control System Capital Costs ($2012) $11,300,000 $20,528,122 $21,973,632 $177,800,000 $3,900,000 $48,386,333 $25,300,000 $40,500,000 $207,000,000NOxEmission Control System ($/kW)$21 $39 $41 $335$21 $335SO2Emission Control System ($/kW)$48 $48 $48PM Emission Control System ($/kW)$7 $91 $7 $7Total Emission Control Capital Costs ($/kW) $21 $39 $41 $335 $7 $91 $48 $76 $391Fixed Operating & Maintenance CostsOperating Labor ($)$0 $0 $0 $0 $0 $0 $0 $0 $0Maintenance Material ($)$28,000 $42,000 $122,000 $190,000 $0 $51,099 $25,500 $53,500 $215,500Maintenance Labor ($)$42,000 $63,000 $183,000 $285,000 $10,000 $76,649 $17,033 $69,033 $312,033Administrative Labor ($)$0 $0 $0 $0 $0 $0 $0 $0 $0Total 1st Fixed Year O&M Cost ($) $70,000 $105,000 $305,000 $475,000 $10,000 $127,748 $42,533 $122,533 $527,533Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Fixed O&M Cost ($/Yr) $82,985 $124,478 $361,578 $563,114 $11,855 $151,446 $50,423 $145,263 $625,392Variable Operating & Maintenance CostsWater CostMakeup Water Usage (gpm)0 0 0 0 0 0 52 52 52Unit Price ($/1000 gallons)$1.22 $1.22 $1.22 $1.22 $1.22 $1.22 $1.22 $1.22 $1.22First Year Water Cost ($)$0 $0 $0 $0 $0 $0 $29,927 $29,927 $29,927Annual Water Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Water Costs ($/Yr)$0 $0 $0 $0 $0 $0 $35,479 $35,479 $35,479Reagent CostType of ReagentNone None UreaAnhydrous NH3Elemental Sulfur Lime Soda AshSoda Ash & ElementalSulfurSoda Ash, ElementalSulfur, Anhydrous NH3Unit Cost ($/Ton)$0.00 $370.00 $400.00 $370.00 $91.25 $80.00Unit Cost ($/Lb)$0.000 $0.185 $0.200 $0.185 $0.046 $0.040Molar Stoichiometry0.00 0.45 1.00 0.00 1.15 1.02Reagent Purity (Wt.%)100% 100% 100% 100% 90% 100%Reagent Usage (Lb/Hr)61 647 100 0 1,215First Year Reagent Cost ($)$0 $89,411 $1,020,310 $145,854 $0 $383,167 $529,021 $1,549,331Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Reagent Costs ($/Yr)$105,997 $1,209,580 $172,910 $0 $454,246 $627,156 $1,836,737SCR Catalyst / Fabric Filter Bag Replacement CostMaterial ReplacedSCR Catalyst Bags 0 & SCR CatalystAnnual SCR Catalyst (m3) / No. FF Bags200 2,827SCR Catalyst ($/m3) / Bag Cost ($/ea.)$3,000 $104First Year SCR Catalyst / Bag Replacement Cost ($)$600,000 $294,008 $0 $600,000Annual SCR Catalyst / Bag Cost Escalation Rate (%)2.00% 2.00% 0% 2.00%Levelized Catalyst/Fabric Fitler Bag Costs ($/Yr)$711,302 $348,547 $0 $711,302FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr)0 0 3,319 3,319 3,319FGD Waste Disposal Unit Cost ($/Dry Ton)$24.33 $24.33 $24.33 $24.33 $24.33First Year FGD Waste Disposal Cost ($)$0 $0 $318,275 $318,275 $318,275Annual Waste Disposal Cost Esc. Rate (%)2.00% 2.00% 2.00% 2.00% 2.00%Levelized Waste Disposal Costs ($/Yr)$0 $0 $377,316 $377,316 $377,316AuxiliaryPower CostAuxiliary Power Requirement (MW) 0.00 6.41 0.52 3.22 0.05 3.33 0.52 0.57 3.79Auxiliary Power Requirement (% of Plant Output) 0.00% 1.21% 0.10% 0.61% 0.01% 0.63% 0.10% 0.11% 0.72%Auxilliary Power Useage (MWh)0 50,536 4,100 25,386 394 26,254 4,100 4,494 29,880Unit Cost ($2006/MW-Hr)$50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00First Year Auxiliary Power Cost ($)$0 $2,526,822 $204,984 $1,269,324 $19,710 $1,312,686 $204,984 $224,694 $1,494,018Annual Power Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Auxilliary Power Costs ($/Yr) $0 $2,995,555 $243,009 $1,504,787 $23,366 $1,556,193 $243,009 $266,375 $1,771,163JMS ES032008003SLC\Tech Calcs\JB3 appendix.xlsPAGE 2 OF 2