# P:\PACIFICORP\370414BART2\TECHNICAL_MEMORANDUM_DEL IVERABLES\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 1 

# TECHNICAL MEMORANDUM



# Addendum to Naughton Unit 1 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-fir e air (OFA), wet flue gas desulfurization (FGD), ESP
(electrostatic precipitato r) with flue gas conditioning

• 

# 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.

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 2



# TABLE 1 

# Control Scenario Summary Naughton Unit 1

Equipment Type Capital Cost

NO

x 

# SO 2 

# PM 10 

# Million dollars

Baseline Good combustion practice Low sulfur coal ESP
—

Scenario A LNB with OFA Wet FGD ESP with gas conditioning $100.8

Scenario B LNB with OFA and SCR Wet FGD ESP with gas conditioning $185.8



# 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 rates that were used for the Naughton Unit 1
BART modeling and analysis.

TABLE 2 

# Calpuff Model Inputs Naughton Unit 1

BART Comparison (d)



# Model Input Data Baseline Scenario

A (e) 

# Scenario

B (f)



# Hourly Heat Input (mmBtu/hour) 1,850 1,850 1,850

Sulfur Dioxide (SO 2 

# ) Stack Emissions (lb/hr) 2,220 278 278

Nitrogen Oxide (NO

x 

# ) Stack Emissions (lb/hr) 1,073 481 130

PM 10 

# Stack Emissions (lb/hr) 104 77.7 77.7

Coarse Particulate (PM 2.5 

# <diameter< PM 10 

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

# 44.5 33.4 33.4

Fine Particulate (diameter<PM 2.5 

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

# 59.1 44.3 44.3

Sulfuric Acid (H 2 

# SO 4 

# ) Stack Emissions (lb/hr) 34 17.0 29.3

Ammonium Sulfate [(NH 4 

# ) 2 

# SO 4 

# ] Stack Emissions (lb/hr) — — 2.1

(NH 4 

# )HSO 4 

# Stack Emissions (lb/hr) — — 3.7

H 2 

# SO 4 

# as Sulfate (SO 4 

# ) Stack Emissions (lb/hr) 33.3 16.7 28.7

(NH 4 

# ) 2 

# SO 4 

# as SO 4 

# Stack Emissions (lb/hr) — — 1.5

(NH 4 

# )HSO 4 

# as SO 4 

# Stack Emissions (lb/hr) — — 3.1

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 3



# TABLE 2 

# Calpuff Model Inputs Naughton Unit 1

BART Comparison (d)



# Model Input Data Baseline Scenario

A (e) 

# Scenario

B (f)



# Total Sulfate (SO 4 

# ) (lb/hr) (c) 

# 33.3 16.7 33.3

Stack Conditions

Stack Height (meters) 61 145 145

Stack Exit Diameter (meters) 4.27 4.88 4.88

Stack Exit Temperature (Kelvin) 411 323 323

Stack Exit Velocity (meters per second) 28.1 18.1 18.1

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 gas conditioning

(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 NAUGHTON UNIT 1 BART REPORTJMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC4TABLE 3Scenario A Control CostNaughton Unit 1NOxControl SO2Control PM10Control Scenario ALNB with OFAWet FGDESP with GasConditioningControl CostTotal Installed Capital Costs (million dollars) $9.60 $89.40 $1.80 $100.80Annualized First-Year Capital Costs$0.91$8.50$0.17$9.59First Year Fixed & Variable O&M Costs (million dollars)$0.08 $4.56 $0.08 $4.72Total First Year Annualized Costs (million dollars)(a)$0.99 $13.07 $0.25 $14.31Power Consumption (MW)—2.40.052.45Annual Power Usage (Million kWh/Yr)—18.920.3919.32Permitted Emission Rate (lb/mmBtu) 0.260.150.04—Additional Tons of Pollutant Removed perYear over Baseline2,3347,65710210,093First Year Average Control Cost ($/Tonof Pollutant Removed) 426 1,707 2,440 1,418NOTE:(a)First year annualized costs include power consumption costs.ADDENDUM TO NAUGHTON UNIT 1 BART REPORTJMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC5TABLE 4Scenario B Control CostNaughton Unit 1NOxControl SO2Control PM10Control Scenario BLNB with OFA &SCRWet FGDESP with GasConditioningControl CostTotal Installed Capital Costs (million dollars) $94.60 $89.40 $1.80 $185.80Annualized First-Year Capital Costs $9.00 $8.50 $0.17 $17.68First Year Fixed & Variable O&M Costs (million dollars)$1.23 $4.68 $0.08 $5.87Total First Year Annualized Costs (million dollars)(a)$10.23 $13.07 $0.25 $23.55Power Consumption (MW)0.982.400.053.43Annual Power Usage (MillionkWh/Yr) 7.7318.92 0.39 27.04Permitted Emission Rate (lb/mmBtu) 0.070.150.04—Additional Tons of Pollutant Removed perYear over Baseline3,7197,65710211,479First Year Average Control Cost ($/Ton ofPollutant Removed)2,751 1,707 2,440 2,051NOTE:(a)First year annualized costs include power consumption costs.ADDENDUM TO NAUGHTON UNIT 1 BART REPORTJMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC6TABLE 5Incremental Control Costs, Scenario B compared to Scenario ANaughton Unit 1NOxControl SO2Control PM10ControlTotalIncremental Installed Capital Costs (million dollars) $85.00 0 0 $85.00Incremental Annualized First-Year Capital Costs $8.09 0 0 $8.09Incremental First Year Fixed & VariableO&M Costs (million dollars)$1.1500$1.15Incremental First Year Annualized Costs (million dollars)(a)$9.24 0 0 $9.24Incremental Power Consumption (MW)0.98000.98Incremental Annual Power Usage (Million kWh/Yr)7.73007.73Incremental Improvement in Emission Rate (lb/mmBtu)0.1900—Incremental Tons of PollutantRemoved1,386 0 0 1,386Incremental First Year Average Control Cost ($/Ton of PollutantRemoved)6,667 0 0 6,667NOTE:(a)Incremental first year annualized costs include power consumption costs.

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 7 

# Modeling Results and Least-Cost Envelope Analysis

CH2M HILL modeled Naughton Unit 1 for two post- control scenarios. The results determine
the change in deciview based on each alternative at the Class I areas specific to the project.
The Class I areas potentially affected are Br idger Wilderness and Fitzpatrick 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 good combustion practice, low sulfur coal, and ESP

• 

# Scenario A: LNB with OFA, Wet FGD, and ESP with gas conditioning

• 

# Scenario B: Scenario A with SCR

Summary of Visibility Analysis

Tables 6 and 7 present a summary of the modeling period (2001–2003) results for each

scenario and Class I area.

TABLE 6 

# Costs and Visibility Modeling Results as Applicable to Bridger Wilderness Naughton Unit 1

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 — 4.649 1.797 48

Scenario A Scenario A: PacifiCorp

Committed Controls $14,310,601 2.650 0.771 18

Scenario B Scenario B: PacifiCorp

Committed Controls and SCR $23,548,376 1.512 0.446 5

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 8 

# TABLE 7 

# Costs and Visibility Modeling Results as Applicable to Fitzpatrick Wilderness Naughton Unit 1

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 — 3.190 0.939 23

Scenario A Scenario A: PacifiCorp

Committed Controls $14,310,601 1.334 0.305 4

Scenario B Scenario B: PacifiCorp

Committed Controls and SCR $23,548,376 0.747 0.181 1



# Results

Tables 8 and 9 present a summary of the cost s and modeling results for each scenario and

Class I area.

TABLE 8 

# Incremental Costs and Incremental Visibility Improvements Relative to Bridger Wilderness Naughton Unit 1

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 $14.31 1.026 30 $13.95 $0.48

Scenario B Compared to

Baseline Scenario B: PacifiCorp

Committed

Controls and SCR $23.55 1.351 43 $17.43 $0.55

Scenario B Compared To

Scenario A Addition of SCR $9. 24 0.325 13 $28.42 $0.71

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 9 

# TABLE 9 

# Incremental Costs and Incremental Visibility Improvements Relative to Fitzpatrick Wilderness Naughton Unit 1

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 $14.31 0.634 19 $22.57 $0.75

Scenario B Compared to

Baseline Scenario B: PacifiCorp

Committed

Controls and SCR $23.55 0.758 22 $31.07 $1.07

Scenario B Compared To

Scenario A Addition of SCR $9. 24 0.124 3 $74.50 $3.08



# Least-Cost Envelope Analysis

The least-cost envelope graphs for Bridger Wilderness are shown in Figures 1 and 2 and for
Fitzpatrick Wilderness are shown in Figures 3 and 4.

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 10 

# FIGURE 1

Least Cost Envelope
PacifiCorp Naughton Unit 1 - Bridger Wilderness

Baseline Scenario A Scenario B

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

0 5 10 15 20 25 30 35 40 45 50



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



# FIGURE 2

Least Cost Envelope
PacifiCorp Naughton Unit 1 - Bridger Wilderness

Scenario B

Scenario A

Baseline

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

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60



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

# ADDENDUM TO NAUGHTON UNIT 1 BART REPORT

JMS ES032008003SLC\BART_TMS_NAUGHTONUNIT1_FINAL.DOC 11 

# FIGURE 3

Least Cost Envelope
PacifiCorp Naughton Unit 1 - Fitzpatrick Wilderness

Scenario B

Scenario A

Baseline

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

0 5 10 15 20 25



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



# FIGURE 4

Least Cost Envelope
PacifiCorp Naughton Unit 1 - Fitzpatrick Wilderness

Scenario B

Scenario A

Baseline

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

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80



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

# ATTACHMENT 1 

# Complete Economic Analyses

for Scenarios A and BECONOMIC ANALYSIS SUMMARY - FIRST YEAR COSTSNaughton 1Boiler Design: Opposed Wall-Fired PCTYPE OF EMISSIONS CONTROLSNOxControl SO2ControlPM Control Scenario A Scenario BTechnology Label BASE A B C D E F G h A+F D+FCurrent OperationLow NOxBurners withOverfire AirRotating Overfire AirLow NOxBurners withOverfire Air and NonSelective CatalyticReductionLow NOxBurners withOverfire Air andSelective CatalyticReductionDry FGDDry FGD & FabricFilterWet FGDESP W/ GasConditioningLNB w/OFA, WetFlue GasDesulfurization andESP w/gasconditioningLNB w/OFA, SCR.Wet Flue GasDesulfurization andESP w/gasconditioningECONOMIC FACTORSInterest Rate (%)7.10% 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% 7.10%Plant Economic Life (Years) 20 20 20 20 20 20 20 20 20 20 20CAPITAL INVESTMENTTotal Installed Capital Costs ($) $0 $9,600,000 $9,068,746 $17,526,855 $94,600,000 $64,297,623 $108,995,970 $89,400,000 $1,800,000 $100,800,000 $185,800,000FIRST YEAR DEBT SERVICE ($/Yr) $0 $913,227 $862,690 $1,667,292 $8,999,092 $6,116,493 $10,368,549 $8,504,427 $171,230 $9,588,885 $17,674,750FIRST YEAR FIXED O&M Costs ($/Yr)Operating Labor ($/Yr)$0 $0 $0 $0 $0 $506,128 $506,128 $809,804 $0 $809,804 $809,804Maintenance Material ($/Yr)$0 $32,000 $48,000 $83,000 $132,000 $587,643 $632,660 $963,589 $0 $995,589 $1,095,589Maintenance Labor ($/Yr)$0 $48,000 $72,000 $124,500 $198,000 $391,762 $459,286 $642,393 $10,000 $700,393 $850,393Administrative Labor ($/Yr)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0TOTAL FIRST YEAR FIXED O&M COST $0 $80,000 $120,000 $207,500 $330,000 $1,485,533 $1,598,074 $2,415,786 $10,000 $2,505,786 $2,755,786FIRST YEAR VARIABLE O&M Costs ($/Yr)Makeup Water Costs ($/Yr)$0 $0 $0 $0 $0 $69,063 $69,063 $92,084 $0 $92,084 $92,084Reagent Costs ($/Yr)$0 $0 $0 $34,461 $314,596 $715,851 $781,547 $642,227 $48,132 $690,359 $1,004,955SCR Catalyst / FF Bag Costs ($/Yr) $0 $0 $0 $0 $201,000 $0 $89,960 $0 $0 $0 $201,000Waste Disposal Costs ($/Yr)$0 $0 $0 $0 $0 $309,360 $418,879 $467,697 $0 $467,697 $467,697Electric Power Costs ($/Yr)$0 $0 $559,764 $63,072 $386,316 $646,488 $1,048,572 $946,080 $19,710 $965,790 $1,352,106TOTAL FIRST YEAR VARIABLE O&M Costs ($/Yr) $0 $0 $559,764 $97,533 $901,912 $1,740,762 $2,408,021 $2,148,088 $67,842 $2,215,930 $3,117,842SUMMARY OF FIRST YEAR COSTS ($/Yr)First Year Debt Service ($/Yr) $0 $913,227 $862,690 $1,667,292 $8,999,092 $6,116,493 $10,368,549 $8,504,427 $171,230 $9,588,885 $17,674,750First Year Fixed O&M Costs ($/Yr) $0 $80,000 $120,000 $207,500 $330,000 $1,485,533 $1,598,074 $2,415,786 $10,000 $2,505,786 $2,755,786First Year Variable O&M Costs($/Yr)$0 $0 $559,764 $97,533 $901,912 $1,740,762 $2,408,021 $2,148,088 $67,842 $2,215,930 $3,117,842Total First Year Costs ($/Yr) $0 $993,227 $1,542,454 $1,972,324 $10,231,004 $9,342,788 $14,374,644 $13,068,302 $249,072 $14,310,601 $23,548,377CONTROL COST COMPARISONSNOxTechnology ComparisonAdditional NOxRemoved From Base Case (Tons/Yr)0 2,334 2,334 2,698 3,719First Year Average Control Cost ($/Ton NOxRemoved)$0 $426 $661 $731 $2,751Technology Case ComparisonA-BASE B-A C-A D-AIncremental NOxRemoved (Tons/Yr)0 2,334 0 365 1,386Incremental Control Cost ($/Ton NOxRemoved)$0 $426 #DIV/0! $2,685 $6,667SO2Technology Comparison-1.5%65.3% 87.3% 87.3%Additional SO2Removed From Base Case (Tons/Yr)05,761 7,657 7,657First Year Average Control Cost ($/Ton SO2Removed)$0$1,622 $1,877 $1,707Technology Case ComparisonE-BASE F-E G-FIncremental SO2Removed (Tons/Yr)05,761 1,896 0Incremental Control Cost ($/Ton SO2Removed)$0$1,622 $2,654 #DIV/0!PM Technology Comparison0.0%Additional PM Removed From Base Case (Tons/Yr)0102First Year Average Control Cost ($/Ton PM Removed)$0$2,440Technology Case Comparisonh-baseIncremental PM Removed (Tons/Yr)0102Incremental Control Cost ($/Ton PM Removed)$0$2,440SCENARIO A AND B COMPARISONSAdditional NOx, SO2, & PM Removed From Base Case (Tons/Yr)010,093 11,479First Year Average Control Cost Compared to Base Case ($/Ton Removed)$0$1,418 $2,051Incremental Tons Removed - Scenario B vs Scenario A (Tons/Yr)01,386Incremental Control Costs - Scenario B vs Scenario A ($/Ton Removed)$0$6,667JMS ES032008003SLC\First Yr Summary\Naughton 1 appendix.xlsPAGE 1 OF 1INPUT CALCULATIONSNaughton 1Boiler Design: Tangentail-Fired PCPARAMETERCurrentOperationNOxControl TechnologiesPM ControlTechnologiesScenario A Scenario BControl TechnologiesNOxEmission Control SystemNone LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCRLNB w/OFA LNB w/OFA & SCRSO2Emission Control SystemNoneDry FGD Dry FGD Wet FGD N/A Wet FGD Wet FGDPM Emission Control System ESPESP Fabric Filter ESPESP W/ GasConditioningESP w/ GasConditioningESP w/ GasConditioningGeneral Plant Design and Operating DataType of Unit PC PC PC PC PC PC PC PC PC PC PCAnnual Power Plant Capacity Factor 90% 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 7,884 7,884Net Power Output (kW) 160,000 160,000 160,000 160,000 160,000 160,000 160,000 160,000 160,000 160,000 160,000Net Plant Heat Rate (Btu/kW-Hr)11,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563Boiler Heat Input, Measured by Fuel Input (MMBtu/Hr)1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850Annual Heat Input, Measured by Fuel Input (MMBtu/Year)14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031Boiler Heat Input, Measured by CEM (MMBtu/Hr)1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850Annual Heat Input, Measured by CEM (MMBtu/Year)14,585,40014,585,40014,585,40014,585,40014,585,40014,585,40014,585,40014,585,40014,585,40014,585,40014,585,400Plant Fuel SourceBoiler Fuel Source Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer MineCoal Heating Value (Btu/Lb) 9,800 9,800 9,800 9,800 9,800 9,800 9,800 9,800 9,800 9,800 9,800Coal Sulfur Content (wt.%) 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.58% 0.580% 0.580% 0.58% 0.58%Coal Ash Content (wt.%) 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00%Coal Flow Rate (Lb/Hr) 188,784 188,784 188,784 188,784 188,784 188,784 188,784 188,784 188,784 188,784 188,784Coal Consumed (Ton/Yr) 744,185 744,185 744,185 744,185 744,185 744,185 744,185 744,185 744,185 744,185 744,185Nitrogen Oxide EmissionsNOxEmission Rate (Lb/MMBtu)0.58 0.26 0.26 0.21 0.070.26 0.07NOxEmission Rate (Lb/Hr)1,073 481 481 389 130481 130NOxEmission Rate (Lb Moles/Hr)35.75 16.03 16.03 12.95 4.3216.03 4.32NOxEmission Rate (Ton/Yr)4,230 1,896 1,896 1,531 5101,896 510Add'l NOxRemoved from Current Operations (Lb/Hr)0 592 592 685 944592 944Add'l NOxRemoved from Current Operations (Ton/Yr)0 2,334 2,334 2,698 3,7192,334 3,719Sulfur Dioxide EmissionsUncontrolled SO2(Lb/MMBtu)1.181.18 1.18 1.18 1.18 1.18Uncontrolled SO2(Lb/Hr)2,1882,188 2,188 2,188 2,188 2,188Uncontrolled SO2(Lb Moles/Hr)34.1534.15 34.15 34.15 34.15 34.15Uncontrolled SO2(Tons/Yr)8,6248,624 8,624 8,624 8,624 8,624Controlled SO2Emission Rate (Lb/MMBtu)1.200.41 0.15 0.15 0.15 0.15SO2Removal Efficiency (%)-1.5%65.3% 87.3% 87.3% 87.3% 87.3%Controlled SO2Emissions (Lb/Hr)2,220759 278 278 278 278Controlled SO2Emissions (Ton/Yr)8,7512,990 1,094 1,094 1,094 1,094SO2Removed (Lb/Hr)-321,429 1,910 1,910 1,910 1,910SO2Removed (Ton/Yr)-1285,634 7,530 7,530 7,530 7,530Add'l SO2Removed from Current Operations (Lb/Hr)01,462 1,943 1,943 1,943 1,943Add'l SO2Removed from Current Operations (Ton/Yr)05,761 7,657 7,657 7,657 7,657Particulate Matter EmissionsUncontrolled Fly Ash (Lb/Hr) 7,5517,551 7,551 7,551 7,551 7,551 7,551Uncontrolled Fly Ash (Lb/MMBtu) 4.0824.082 4.082 4.082 4.082 4.082 4.082Uncontrolled Fly Ash (Tons/Yr) 29,76729,767 29,767 29,767 29,767 29,767 29,767Controlled Fly Ash Emission Rate (Lb/MMBtu) 0.0560.056 0.015 0.056 0.042 0.042 0.042Controlled Fly Ash Removal Efficiency (%) 98.6%98.6% 99.6% 98.6% 99.0% 99.0% 99.0%Controlled Fly Ash Emissions (Lb/Hr) 104104 28 104 78 78 78Controlled Fly Ash Emissions (Ton/Yr) 408408 109 408 306 306 306Fly Ash Removed (Lb/Hr) 7,4487,448 7,524 7,448 7,474 7,474 7,474Fly Ash Removed (Ton/Yr) 29,35929,359 29,658 29,359 29,461 29,461 29,461Add'l Ash Removed from Current Operation (Lb/Hr) 00 76 0 26 26 26Add'l Ash Removed from Current Operation (Ton/Yr) 00 299 0 102 102 102Economic FactorsInterest Rate (%) 7.10% 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% 7.10%Plant Economic Life (Years) 20 20 20 20 20 20 20 20 20 20 20SO2Control TechnologiesJMS ES032008003SLC\Tech Calcs\Naughton 1 appendix.xlsPAGE 1 OF 2INPUT CALCULATIONSNaughton 1Boiler Design: Tangentail-Fired PCPARAMETERCurrentOperationNOxControl TechnologiesPM ControlTechnologiesScenario A Scenario BControl TechnologiesNOxEmission Control SystemNone LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCRLNB w/OFA LNB w/OFA & SCRSO2Emission Control SystemNoneDry FGD Dry FGD Wet FGD N/A Wet FGD Wet FGDPM Emission Control System ESPESP Fabric Filter ESPESP W/ GasConditioningESP w/ GasConditioningESP w/ GasConditioningSO2Control TechnologiesInstalled Capital CostsNOxEmission Control System ($2006)$9,600,000 $9,068,746 $17,526,855 $94,600,000$9,600,000 $94,600,000SO2Emission Control System ($2006)$64,297,623 $108,995,970 $89,400,000 $0 $89,400,000 $89,400,000PM Emission Control System ($2006)$0 $0 $0 $1,800,000 $1,800,000 $1,800,000Total Emission Control System Capital Costs ($2006) $9,600,000 $9,068,746 $17,526,855 $94,600,000 $64,297,623 $108,995,970 $89,400,000$1,800,000 $100,800,000 $185,800,000NOxEmission Control System ($/kW)$60 $57 $110 $591$60 $591SO2Emission Control System ($/kW)$402 $681 $559 $11 $559 $559PM Emission Control System ($/kW)$11 $11Total Emission Control Capital Costs ($/kW) $60 $57 $110 $591 $402 $681 $559 $11 $630 $1,161Fixed Operating & Maintenance CostsOperating Labor ($)$0 $0 $0 $0 $506,128 $506,128 $809,804 $0 $809,804 $809,804Maintenance Material ($)$32,000 $48,000 $83,000 $132,000 $587,643 $632,660 $963,589 $0 $995,589 $1,095,589Maintenance Labor ($)$48,000 $72,000 $124,500 $198,000 $391,762 $459,286 $642,393 $10,000 $700,393 $850,393Administrative Labor ($)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0Total 1st Fixed Year O&M Cost ($) $80,000 $120,000 $207,500 $330,000 $1,485,533 $1,598,074 $2,415,786 $10,000 $2,505,786 $2,755,786Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Fixed O&M Cost ($/Yr) $94,840 $142,260 $245,992 $391,216 $1,761,104 $1,894,521 $2,863,921 $11,855 $2,970,617 $3,266,992Variable Operating & Maintenance CostsWater CostMakeup Water Usage (gpm)0 0 0 0 120 120 160 0 160 160Unit Price ($/1000 gallons)$1.22 $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 $69,063 $69,063 $92,084 $0 $92,084 $92,084Annual Water Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Water Costs ($/Yr)$0 $0 $0 $0 $81,874 $81,874 $109,166 $0 $109,166 $109,166Reagent CostType of ReagentNone None Urea Anhydrous NH3 Lime Lime Lime Elemental SulfurLime & ElementalSulfurLime & Anhydrous NH3& Elemental SulfurUnit Cost ($/Ton)$0.00 $370.00 $400.00 $91.25 $91.25 $91.25 $370.00Unit Cost ($/Lb)$0.000 $0.185 $0.200 $0.046 $0.046 $0.046 $0.185Molar Stoichiometry0.00 0.45 1.00 1.40 1.15 1.05 0.00Reagent Purity (Wt.%)100% 100% 100% 90% 90% 100% 100%Reagent Usage (Lb/Hr)24 200 1,990 2,173 1,785 33First Year Reagent Cost ($)$0 $34,461 $314,596 $715,851 $781,547 $642,227 $48,132 $690,359 $1,004,955Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Reagent Costs ($/Yr)$40,853 $372,954 $848,644 $926,526 $761,363 $57,060 $818,423 $1,191,377SCR Catalyst / Fabric Filter Bag Replacement CostMaterial ReplacedSCR Catalyst Bags 0 & SCR CatalystAnnual SCR Catalyst (m3) / No. FF Bags67 865SCR Catalyst ($/m3) / Bag Cost ($/ea.)$3,000 $104First Year SCR Catalyst / Bag Replacement Cost ($)$201,000 $89,960 $0 $201,000Annual SCR Catalyst / Bag Cost Escalation Rate (%)2.00% 2.00% 0% 2.00%Levelized Catalyst/Fabric Fitler Bag Costs ($/Yr)$238,286 $106,648 $0 $238,286FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr)3,226 4,367 4,876 4,876 4,876FGD Waste Disposal Unit Cost ($/Dry Ton)$24.33 $24.33 $24.33 $24.33 $24.33First Year FGD Waste Disposal Cost ($)$309,360 $418,879 $467,697 $467,697 $467,697Annual Waste Disposal Cost Esc. Rate (%)2.00% 2.00% 2.00% 2.00% 2.00%Levelized Waste Disposal Costs ($/Yr)$366,747 $496,582 $554,456 $554,456 $554,456AuxiliaryPower CostAuxiliary Power Requirement (MW) 0.00 1.42 0.16 0.98 1.64 2.66 2.40 0.05 2.45 3.43Auxiliary Power Requirement (% of Plant Output) 0.00% 0.89% 0.10% 0.61% 1.03% 1.66% 1.50% 0.03% 1.53% 2.14%Auxilliary Power Useage (MWh)0 11,195 1,261 7,726 12,930 20,971 18,922 394 19,316 27,042Unit Cost ($2006/MW-Hr)$50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00 $50.00First Year Auxiliary Power Cost ($)$0 $559,764 $63,072 $386,316 $646,488 $1,048,572 $946,080 $19,710 $965,790 $1,352,106Annual Power Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00%Levelized Auxilliary Power Costs ($/Yr) $0 $663,602 $74,772 $457,979 $766,413 $1,243,085 $1,121,581 $23,366 $1,144,947 $1,602,926JMS ES032008003SLC\Tech Calcs\Naughton 1 appendix.xlsPAGE 2 OF 2