P:\PACIFICORP\370414BART2\TECHNICAL_MEMORANDUM_DELIVERABLES\BART_TMS_DAVEJOHNSTONUNIT3_FINAL.DOC 1 

TECHNICAL MEMORANDUM 

Addendum to Dave Johnston 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 baseline and for reasonable control technology 

scenarios. PacifiCorp submitted 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 requested 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 scenarios, referred to as Scenario A and Scenario B and 

described as follows: 

• Scenario A: PacifiCorp committed controls at permitted rates—low nitrogen oxide (NOx) 

burners (LNBs) with over-fire air (OFA), dry flue gas desulfurization (FGD), new fabric 

filter 

• 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 DAVE JOHNSTON UNIT 3 BART REPORT 

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TABLE 1 

Control Scenario Summary 

Dave Johnson Unit 3 

 Equipment Type Capital Cost 

 NOx SO2 PM10 Million dollars 

Baseline No control No control ESP — 

Scenario A LNB with OFA Dry FGD Fabric Filter $187.0 

Scenario B LNB with OFA and SCR Dry FGD Fabric Filter $299.2 

Emissions were modeled for the following pollutants: 

• Sulfur dioxide (SO2) 

• NOx

• Coarse particulate (PM2.5<diameter<PM10) 

• Fine particulate (diameter<PM2.5) 

• Sulfates 

Table 2 shows stack parameters and emission rates that were used for the Dave Johnston Unit 3 

BART modeling and analysis. 

TABLE 2 

Calpuff Model Inputs 

Dave Johnston Unit 3 

 BART Comparison(d)

Model Input Data Baseline 

Scenario 

A (e)

Scenario 

B (f)

Hourly Heat Input (mmBtu/hour) 2,500 2,800 2,800 

Sulfur Dioxide (SO2) Stack Emissions (lb/hr) 3,000 420 420 

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,750 784 196 

PM10 Stack Emissions (lb/hr) 75 42.0 42.0 

Coarse Particulate (PM2.5 <diameter< PM10) Stack Emissions (lb/hr)(a) 32.3 23.9 23.9 

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 42.8 18.1 18.1 

Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 46 2.6 3.7 

Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr) — — 0.7 

(NH4)HSO4 Stack Emissions (lb/hr) — — 1.2 

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 45.1 2.5 3.6 

(NH4)2SO4 as SO4 Stack Emissions (lb/hr) — — 0.5 

(NH4)HSO4 as SO4 Stack Emissions (lb/hr) — — 1.0 
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TABLE 2 

Calpuff Model Inputs 

Dave Johnston Unit 3 

 BART Comparison(d)

Model Input Data Baseline 

Scenario 

A (e)

Scenario 

B (f)

Total Sulfate (SO4) (lb/hr)(c) 45.1 2.5 5.1 

Stack Conditions 

Stack Height (meters) 152 152.4 152.4 

Stack Exit Diameter (meters) 4.6 4.57 4.57 

Stack Exit Temperature (Kelvin) 445 348 348 

Stack Exit Velocity (meters per second) 32 25.5 25.5 

NOTES:

(a) Based on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 43% 

ESP and 57% Baghouse. PM10 and PM2.5 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 particulates are counted as a percentage of PM10. This equates to 57% 

ESP and 43% Baghouse. 

(c) Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions 

(lb/hr) + (NH4)HSO4 as SO4 Stack Emissions (lb/hr) (d) SO2, NOx, and PM rates are expressed in terms of permitted emission rates. Actual emissions will be less than 

the permitted rates. 

(e) PacifiCorp Committed Controls @ permitted rates: LNB with OFA, Dry FGD, New Fabric Filter (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 NOx, SO2, and PM10 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 D

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TABLE 3 Scenario A Control Cost Dave Johnston Unit 3 

 NOx Control SO2 Control PM10 Control 

LNB with OFA Dry FGD Fabric Filter 

Total Installed Capital Costs (million dollars) $17.5 $169.5 — 

Annualized First-Year Capital Costs $1.66 $16.12 — 

First Year Fixed & Variable O&M Costs (million dollars) $0.10 $5.30 — 

Total First Year Annualized Costs (million dollars) (a) $1.76 $21.42 — 

Power Consumption (MW) — 3.88 — Annual Power Usage (Million kWh/Yr) — 30.59 — 

Permitted Emission Rate (lb/mmBtu) 0.28 0.15 0.02 

Additional Tons of Pollutant Removed per Year over Baseline 4,636 11,589 166 

First Year Average Control Cost ($/Ton of Pollutant Removed) 381 1,848 — 

NOTE:

(a) First year annualized costs include power consumption costs.
ADDENDUM TO D

JMS ES032008003SLC\BART_TMS_DAVEJOHNSTONUNIT3_FINAL.DOC 

TABLE 4 Scenario B Control Cost Dave Johnston Unit 3 

 NOx Control SO2 Control PM10 Control 

LNB with OFA & 

SCR Dry FGD Fabric Filter 

Total Installed Capital Costs (million dollars) $129.7 $169.5 — 

Annualized First-Year Capital Costs $12.34 $16.12 — 

First Year Fixed & Variable O&M Costs (million dollars) $4.01 $5.30 — Total First Year Annualized Costs (million dollars) (a) $16.35 $21.42 — 

Power Consumption (MW) 0.23 3.88 — 

Annual Power Usage (Million kWh/Yr) 12.34 30.59 — Permitted Emission Rate (lb/mmBtu) 0.07 0.15 0.02 Additional Tons of Pollutant Removed per Year over Baseline 6,954 11,589 166 

First Year Average Control Cost ($/Ton of Pollutant Removed) 2,351 1,848 — NOTE:

(a) First year annualized costs include power consumption costs. 
ADDENDUM TO D

JMS ES032008003SLC\BART_TMS_DAVEJOHNSTONUNIT3_FINAL.DOC 

TABLE 5 Incremental Control Costs, Scenario B compared to Scenario A Dave Johnston Unit 3 

 NOx Control SO2 Control PM10 Control 

Incremental Installed Capital Costs (million dollars) $112.2 0 0 

Incremental Annualized First-Year Capital Costs $10.67 0 0 

Incremental First Year Fixed & Variable O&M Costs (million dollars) $3.91 0 0 

Incremental First Year Annualized Costs (million dollars) (a) $14.58 0 0 

Incremental Power Consumption (MW) 1.57 0 0 

Incremental Annual Power Usage (Million kWh/Yr) 12.38 0 0 

Incremental Improvement in Emission Rate (lb/mmBtu) 0.21 0 0 

Incremental Tons of Pollutant Removed 2,318 0 0 Incremental First Year Average Control Cost ($/Ton of Pollutant Removed) 

6,291 0 0 

NOTE:

(a)Incremental first year annualized costs include power consumption costs. 
ADDENDUM TO DAVE JOHNSTON UNIT 3 BART REPORT 

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Modeling Results and Least-Cost Envelope Analysis 

CH2M HILL modeled Dave Johnston Unit 3 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 Badlands National Park and Windcave 

National Park for this unit. 

Modeled Scenarios 

Current operations (baseline) and two alternative control scenarios were modeled to cover the 

range of effectiveness for the combination of the individual NOx, SO2, and PM control 

technologies being evaluated. The modeled scenarios include the following: 

• Baseline: Current operations with ESP 

• Scenario A: LNB with OFA, Dry FGD, new fabric filter 

• 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 Badlands National Park 

Dave Johnston Unit 3 

Scenario Controls 

Total First Year 

Annualized 

Cost Highest ΔdV 

98th 

Percentile 

ΔdV 

Maximum 

Annual 

Number of 

Days Above 

0.5 dV 

Baseline Current Operations with ESP — 4.202 1.500 59 

Scenario A Scenario A: PacifiCorp 

Committed Controls 

$23,184,500 1.297 0.432 7 

Scenario B Scenario B: PacifiCorp 

Committed Controls and SCR 

$37,766,998 0.638 0.208 3 
ADDENDUM TO DAVE JOHNSTON UNIT 3 BART REPORT 

JMS ES032008003SLC\BART_TMS_DAVEJOHNSTONUNIT3_FINAL.DOC 8 

TABLE 7 

Costs and Visibility Modeling Results as Applicable to Wind Cave National Park 

Dave Johnston Unit 3 

Scenario Controls 

Total First Year 

Annualized 

Cost Highest ΔdV 

98th 

Percentile 

ΔdV 

Maximum 

Annual 

Number of 

Days Above 

0.5 dV 

Baseline Current Operations with ESP — 5.191 1.971 57 

Scenario A Scenario A: PacifiCorp 

Committed Controls 

$23,184,500 1.805 0.583 11 

Scenario B Scenario B: PacifiCorp 

Committed Controls and SCR 

$37,766,998 0.904 0.262 2 

Results 

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

Class I area. 

TABLE 8 

Incremental Costs and Incremental Visibility Improvements Relative to Badlands National Park 

Dave Johnston Unit 3 

Scenario 

Comparison Controls 

Incremental 

Annualized 

Cost 

(Million$) 

Reduction in 

98th 

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 

$23.18 1.068 52 $21.71 $0.45 

Scenario B 

Compared to 

Baseline 

Scenario B: 

PacifiCorp 

Committed Controls 

and SCR 

$37.77 1.292 56 $29.23 $0.67 

Scenario B 

Compared To 

Scenario A 

Addition of SCR $14.58 0.224 4 $65.10 $3.65 
ADDENDUM TO DAVE JOHNSTON UNIT 3 BART REPORT 

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TABLE 9 

Incremental Costs and Incremental Visibility Improvements Relative to Wind Cave National Park 

Dave Johnston Unit 3 

Scenario 

Comparison Controls 

Incremental 

Annualized 

Cost 

(Million$) 

Reduction 

in 98th 

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 

$23.18 1.388 46 $16.70 $0.50 

Scenario B 

Compared to 

Baseline 

Scenario B: 

PacifiCorp 

Committed 

Controls and SCR 

$37.77 1.709 55 $22.10 $0.69 

Scenario B 

Compared To 

Scenario A 

Addition of SCR $14.58 0.321 9 $45.43 $1.62 

Least-Cost Envelope Analysis 

The least-cost envelope graphs for Badlands National Park are shown in Figures 1 and 2 and 

for Wind Cave National Park are shown in Figures 3 and 4. 
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FIGURE 1 

Least Cost Envelope

 PacifiCorp Dave Johnson Unit 3 - Badlands National Park

Baseline

Scenario A

Scenario B

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$40.0

0 10 20 30 40 50 60

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

FIGURE 2 

Least Cost Envelope

 PacifiCorp Dave Johnson Unit 3 - Badlands National Park

Baseline

Scenario A

Scenario B

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$40.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)
ADDENDUM TO DAVE JOHNSTON UNIT 3 BART REPORT 

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FIGURE 3 

Least Cost Envelope

 PacifiCorp Dave Johnson Unit 3 - Wind Cave National Park

Baseline

Scenario A

Scenario B

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$40.0

0 10 20 30 40 50 60

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

FIGURE 4 

Least Cost Envelope

 PacifiCorp Dave Johnson Unit 3 - Wind Cave National Park

Scenario B

Scenario A

Baseline

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$40.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)
ATTACHMENT 1 

Complete Economic Analyses 

for Scenarios A and B 
ECONOMIC ANALYSIS SUMMARY - FIRST YEAR COSTS

DJ3 Boiler Design: 3-Cell BurnerOpposed Wall-Fired PC

TYPE OF EMISSIONS CONTROLS NOx Control 

Technology Label BASE A B C D 

Current Operation Low NOx Burners with Overfire Air Rotating Overfire Air

Low NOx Burners with 

Overfire Air and NonSelective Catalytic 

Reduction

Low NOx Burners with 

Overfire Air and 

Selective Catalytic 

Reduction

Dr

CAPITAL INVESTMENT 

Total Installed Capital Costs ($) $0 $17,500,000 $12,054,022 $24,035,544 $129,700,000  FIRST YEAR DEBT SERVICE ($/Yr) $0 $1,664,737 $1,146,673 $2,286,449 $12,338,079 

FIRST YEAR FIXED O&M Costs ($/Yr)

Operating Labor ($/Yr) $0 $0 $0 $0 $0 Maintenance Material ($/Yr) $0 $40,000 $60,000 $98,000 $155,000 Maintenance Labor ($/Yr) $0 $60,000 $90,000 $147,000 $2,325,000 Administrative Labor ($/Yr) $0 $0 $0 $0 $0  TOTAL FIRST YEAR FIXED O&M COST $0 $100,000 $150,000 $245,000 $2,480,000 

FIRST YEAR VARIABLE O&M Costs ($/Yr)

Makeup Water Costs ($/Yr) $0 $0 $0 $0 $0 Reagent Costs ($/Yr) $0 $0 $0 $57,025 $526,265 SCR Catalyst / FF Bag Costs ($/Yr) $0 $0 $0 $0 $384,000 Waste Disposal Costs ($/Yr) $0 $0 $0 $0 $0 Electric Power Costs ($/Yr) $0 $0 $1,087,992 $90,666 $618,894  TOTAL FIRST YEAR VARIABLE O&M Costs ($/Yr) $0 $0 $1,087,992 $147,691 $1,529,159 

SUMMARY OF FIRST YEAR COSTS ($/Yr)

First Year Debt Service ($/Yr) $0 $1,664,737 $1,146,673 $2,286,449 $12,338,079 First Year Fixed O&M Costs ($/Yr) $0 $100,000 $150,000 $245,000 $2,480,000 First Year Variable O&M Costs ($/Yr) $0 $0 $1,087,992 $147,691 $1,529,159 

Total First Year Costs ($/Yr) $0 $1,764,737 $2,384,665 $2,679,140 $16,347,238 

CONTROL COST COMPARISONS

NOx Technology Comparison

Additional NOx Removed From Base Case (Tons/Yr) 0 4,636 5,629 5,298 6,954

First Year Average Control Cost ($/Ton NOx Removed) $0 $381 $424 $506 $2,351

Technology Case Comparison A-BASE B-A C-A D-AIncremental NOx Removed (Tons/Yr) 0 4,636 993 662 2,318

Incremental Control Cost ($/Ton NOx Removed) $0 $381 $624 $1,381 $6,291

SO2 Technology Comparison 0.5% 

Additional SO2 Removed From Base Case (Tons/Yr) 0 

First Year Average Control Cost ($/Ton SO2 Removed) $0 

Technology Case Comparison Incremental SO2 Removed (Tons/Yr) 0 

Incremental Control Cost ($/Ton SO2 Removed) $0 PM Technology Comparison 0.0%Additional PM Removed From Base Case (Tons/Yr) 0 

First Year Average Control Cost ($/Ton PM Removed) $0 

Technology Case Comparison Incremental PM Removed (Tons/Yr) 0 

Incremental Control Cost ($/Ton PM Removed) $0 

SCENARIO A AND B COMPARISONS

Additional NOx, SO2, & PM Removed From Base Case (Tons/Yr) 0 

First Year Average Control Cost Compared to Base Case ($/Ton Removed) $0 Incremental Tons Removed - Scenario B vs Scenario A (Tons/Yr) 0 

Incremental Control Costs - Scenario B vs Scenario A ($/Ton Removed) $0 

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INPUT CALCULATIONS

DJ3 Boiler Design: 3-Cell BurnerOpposed Wall-Fired PC

PARAMETER Current Operation NOx Control Technologies 

Control TechnologiesNOx Emission Control System Good Practices LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR 

SO2 Emission Control System Dry FGD w/ESP 

PM Emission Control System ESP 

General Plant Design and Operating Data

Type of Unit PC PC PC PC PC PC Annual Power Plant Capacity Factor 90% 90% 90% 90% 90% 90Annual Operation (Hours/Year) 7,884 7,884 7,884 7,884 7,884 7,8Net Power Output (kW) 223,214 223,214 223,214 223,214 223,214 223,2Net Plant Heat Rate (Btu/kW-Hr) 12,175 12,175 12,175 12,175 12,175 12,1Boiler Heat Input, Measured by Fuel Input (MMBtu/Hr) 2,718 2,718 2,718 2,718 2,718 2,7Annual Heat Input, Measured by Fuel Input (MMBtu/Year) 21,425,798 21,425,798 21,425,798 21,425,798 21,425,798 21,425,7Boiler Heat Input, Measured by CEM (MMBtu/Hr) 2,800 2,800 2,800 2,800 2,800 2,8Annual Heat Input, Measured by CEM (MMBtu/Year) 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200 22,075,2

Plant Fuel Source

Boiler Fuel Source Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Coal Heating Value (Btu/Lb) 7,784 7,784 7,784 7,784 7,784 7,7Coal Sulfur Content (wt.%) 0.47% 0.47% 0.47% 0.47% 0.47% 0.47Coal Ash Content (wt.%) 5.01% 5.01% 5.01% 5.01% 5.01% 5.0Coal Flow Rate (Lb/Hr) 349,130 349,130 349,130 349,130 349,130 349,1Coal Consumed (Ton/Yr) 1,376,272 1,376,272 1,376,272 1,376,272 1,376,272 1,376,2

Nitrogen Oxide Emissions

NOx Emission Rate (Lb/MMBtu) 0.70 0.28 0.19 0.22 0.07 

NOx Emission Rate (Lb/Hr) 1,960 784 532 616 196 

NOx Emission Rate (Lb Moles/Hr) 65.31 26.12 17.73 20.53 6.53 

NOx Emission Rate (Ton/Yr) 7,726 3,091 2,097 2,428 773 Add'l NOx Removed from Current Operations (Lb/Hr) 0 1,176 1,428 1,344 1,764 

Add'l NOx Removed from Current Operations (Ton/Yr) 0 4,636 5,629 5,298 6,954 

Sulfur Dioxide Emissions

Uncontrolled SO2 (Lb/MMBtu) 1.21 1

Uncontrolled SO2 (Lb/Hr) 3,378 3,3

Uncontrolled SO2 (Lb Moles/Hr) 52.73 52Uncontrolled SO2 (Tons/Yr) 13,316 13,3

Controlled SO2 Emission Rate (Lb/MMBtu) 1.20 0

SO2 Removal Efficiency (%) 0.5% 81.8

Controlled SO2 Emissions (Lb/Hr) 3,360 6

Controlled SO2 Emissions (Ton/Yr) 13,245 2,4

SO2 Removed (Lb/Hr) 18 2,7

SO2 Removed (Ton/Yr) 71 10,8

Add'l SO2 Removed from Current Operations (Lb/Hr) 0 2,7

Add'l SO2 Removed from Current Operations (Ton/Yr) 0 10,8

Particulate Matter Emissions

Uncontrolled Fly Ash (Lb/Hr) 13,993 13,9Uncontrolled Fly Ash (Lb/MMBtu) 4.998 4.9Uncontrolled Fly Ash (Tons/Yr) 55,161 55,1Controlled Fly Ash Emission Rate (Lb/MMBtu) 0.030 0.0Controlled Fly Ash Removal Efficiency (%) 99.4% 99.4Controlled Fly Ash Emissions (Lb/Hr) 84 Controlled Fly Ash Emissions (Ton/Yr) 331 3Fly Ash Removed (Lb/Hr) 13,909 13,9Fly Ash Removed (Ton/Yr) 54,830 54,8Add'l Ash Removed from Current Operation (Lb/Hr) 0 Add'l Ash Removed from Current Operation (Ton/Yr) 0 

Economic Factors

Interest Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10Discount Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10Plant Economic Life (Years) 20 20 20 20 20 

SO2 an

JMS ES032008003SLC\Tech Calcs\DJ3 appendix.xls 
INPUT CALCULATIONS

DJ3 Boiler Design: 3-Cell BurnerOpposed Wall-Fired PC

PARAMETER Current Operation NOx Control Technologies 

Control TechnologiesNOx Emission Control System Good Practices LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR 

SO2 Emission Control System Dry FGD w/ESP 

PM Emission Control System ESP 

SO2 an

Installed Capital Costs

NOx Emission Control System ($2006) $17,500,000 $12,054,022 $24,035,544 $129,700,000 

SO2 Emission Control System ($2006) $91,499,7

PM Emission Control System ($2006) Total Emission Control System Capital Costs ($2006) $17,500,000 $12,054,022 $24,035,544 $129,700,000 $91,499,7NOx Emission Control System ($/kW) $78 $54 $108 $581 

SO2 Emission Control System ($/kW) $4

PM Emission Control System ($/kW)Total Emission Control Capital Costs ($/kW) $78 $54 $108 $581 $4

Fixed Operating & Maintenance Costs

Operating Labor ($) $0 $0 $0 $0 $506,1Maintenance Material ($) $40,000 $60,000 $98,000 $155,000 $714,1Maintenance Labor ($) $60,000 $90,000 $147,000 $2,325,000 $476,9Administrative Labor ($) $0 $0 $0 $0 Total 1st Fixed Year O&M Cost ($) $100,000 $150,000 $245,000 $2,480,000 $1,697,2Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00Levelized Fixed O&M Cost ($/Yr) $118,550 $177,825 $290,448 $2,940,047 $2,012,0

Variable Operating & Maintenance Costs

Water CostMakeup Water Usage (gpm) 0 0 0 0 1Unit Price ($/1000 gallons) $1.22 $1.22 $1.22 $1.22 $1First Year Water Cost ($) $0 $0 $0 $0 $99,5Annual Water Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00Levelized Water Costs ($/Yr) $0 $0 $0 $0 $118,0Reagent CostType of Reagent None None Urea Anhydrous NH3 Lime Unit Cost ($/Ton) $0.00 $370.00 $400.00 $91Unit Cost ($/Lb) $0.000 $0.185 $0.200 $0.0Molar Stoichiometry 0.00 0.41 1.00 1Reagent Purity (Wt.%) 100% 100% 100% 90Reagent Usage (Lb/Hr) 39 334 3,0First Year Reagent Cost ($) $0 $57,025 $526,265 $1,104,0Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00Levelized Reagent Costs ($/Yr) $67,603 $623,889 $1,308,8SCR Catalyst / Fabric Filter Bag Replacement CostMaterial Replaced SCR Catalyst Annual SCR Catalyst (m3) / No. FF Bags 128 SCR Catalyst ($/m3) / Bag Cost ($/ea.) $3,000 First Year SCR Catalyst / Bag Replacement Cost ($) $384,000 Annual SCR Catalyst / Bag Cost Escalation Rate (%) 2.00% Levelized Catalyst/Fabric Fitler Bag Costs ($/Yr) $455,233 FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr) 5,9FGD Waste Disposal Unit Cost ($/Dry Ton) $24First Year FGD Waste Disposal Cost ($) $572,8Annual Waste Disposal Cost Esc. Rate (%) 2.00Levelized Waste Disposal Costs ($/Yr) $679,0Auxiliary Power CostAuxiliary Power Requirement (MW) 0.00 2.76 0.23 1.57 2Auxiliary Power Requirement (% of Plant Output) 0.00% 1.24% 0.10% 0.70% 1.12Auxilliary Power Useage (MWh) 0 21,760 1,813 12,378 19,6Unit Cost ($2006/MW-Hr) $50.00 $50.00 $50.00 $50.00 $50First Year Auxiliary Power Cost ($) $0 $1,087,992 $90,666 $618,894 $981,5Annual Power Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00Levelized Auxilliary Power Costs ($/Yr) $0 $1,289,818 $107,485 $733,701 $1,163,6

JMS ES032008003SLC\Tech Calcs\DJ3 appendix.xls