# Final Report



# BART Analysis for

Dave Johnston Unit 3

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Dave Johnston Unit 3

Submitted to



# PacifiCorp

December 2007

# Executive Summary

In response to the Regional Haze Rule a nd Best Available Retrofit Technology (BART)

regulations and guidelines, CH 2M HILL was requested to perform a BART analysis for

PacifiCorp’s Dave Johnston Unit 3 (hereafter refe rred to as Dave Johnston 3). Best Available

Retrofit Technology analysis has been conducte d for the following criteria pollutants:

nitrogen oxides (NO

x 

# ), sulfur dioxide (SO 2 

# ), and particulate matter less than 10 micrometers

in aerodynamic diameter (PM 10 

# ). The Dave Johnston Station c onsists of four units with a

total generating capacity of 772 megawatts (MW). Therefore, since the total generating

capacity of the Dave Johnston plant exceeds 750 MW, presumptive BART limits do apply to

Dave Johnston 3 unless it is determined that an alternative control leve l is justified, based on

a careful consideration of the statutory f actors. Presumptive BART emission limits are

referenced in this analysis, based on the Un ited States Environmental Protection Agency’s

(EPA) guidelines for units great er than 200 MW. BART emissions limits must be achieved

within 5 years after the State Implementati on Plan (SIP) is approved by the EPA, and a

compliance date of 2014 was assumed for this analysis.

In completing the BART analysis, technology a lternatives were inve stigated a nd potential

reductions in NO

x 

# , SO 2 

# , and PM 10 

# emissions rates were identified. The following technology

alternatives were investigat ed, listed below by pollutant:

• NO

x 

# emission controls:

− Low-NO

x 

# burners (LNBs) with over-fire air (OFA)

− LNBs with rotating opposed fire air (ROFA)

− LNBs with selective non-catal ytic reduction (SNCR) system

− LNBs with selective catalytic reduction (SCR) system

• SO 2 

# emission controls:

− Dry flue gas desulfurization (FGD) system with existing electrostatic precipitator

(ESP)

− Dry FGD system with new polishing fabric filter

− Wet FGD system and new stack with existing ESP

• PM 10 

# emission controls:

− Sulfur trioxide (SO 3 

# ) injection flue gas conditioning system on existing ESP

− Polishing fabric filter

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# ES-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# BART Engineering Analysis

The specific steps in a BART engineering anal ysis are identified in the Code of Federal

Regulations (CFR) at 40 CFR 51, Appendix Y, Section IV. Th e evaluation must include:

• The identification of available, techni cally feasible, retr ofit control options

• Consideration of any pollution control equipment in use at the source (which affects the

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

• The energy and non-air quality envi ronmental impacts of compliance

• The degree of visibility improvement that ma y reasonably be anticipated from the use of

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Available Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

− The identification of available, techni cally feasible, retr ofit control options

− Consideration of any pollution control equipm ent in use at the source (which affects

the applicability of optio ns and their impacts)

• Step 3 – Evaluate Control Effectiven ess of Remaining Control Technologies

• Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

− The energy and non-air quality envi ronmental impacts of compliance

• Step 5 – Evaluate Visibility Impacts

− The degree of visibility improvement that may reasonably be anticipated from the use

of BART

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included

in the BART analyses are in 2006 dollars, and co sts have not been escalated to the assumed

2014 BART implementation date.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# Recommendations

CH2M HILL recommends instal ling the following control devices, which include LNBs with

OFA, dry FGD system, and the existing ESP. This combination of control devices is

identified as Scenario 1 throughout this report.



# NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by EPA for wall-fired cell burner boilers

combusting sub-bituminous coal is 0.45 pound (lb) per million British thermal units

(MMBtu). The Dave Johnston 3 plant burns only Powder River Basin (PRB) coal, a subbituminous coal.

CH2M HILL recommends the addition of LNBs with an OFA system as BART for Dave

Johnston 3, based on the projecte d significant reduction in NO

x 

# emissions, reasonable control

costs, and the advantages of no additi onal power requirements or non-air quality

environmental impacts. This approach is projected to meet the BART presumptive NO

x 

# limit

of 0.45 pound (lb) per MMBtu.



# SO 2 

# Emission Control

CH2M HILL recommends a dry FGD system as BART for Dave Johnston 3, based on the

significant reduction in SO 2 

# emissions, reasonable control costs, and the advantages of

minimal additional power requirements and mini mal non-air quality environmental impacts.

Although this approach is projected to not meet the BART presumptive SO 2 

# limit of 0.15 lb

per MMBtu, the EPA’s least-cost envelope an alysis and the evaluation of non-air quality

impacts on the environment demonstrate compelling objective reasons why this

recommendation is valid.



# PM 10



# Emission Control

CH2M HILL recommends maintaining the ex isting ESP as BART for Dave Johnston 3,

based on the significant reduction in PM 10 

# emissions, reasonable control costs, and the

advantages of minor additional power requirements and no non-air quality environmental

impacts.



# BART Modeling Analysis

CH2M HILL used the CALPUFF modeling syst em to assess the visibility impacts of

emissions from Dave Johnston 3 at Class I areas . The Class I areas potentially affected are

located more than 50 kilometers—but less than 300 kilometers—from Dave Johnston 3.

The Class I areas include the following national parks (NPs):

• Wind Cave NP

• Badlands NP

Because Dave Johnston 3 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions,

four post-control atmospheric dispersion mode ling scenarios were developed to cover the

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# range of effectiveness for combining the individual NO

x 

# , SO 2 

# , and PM 10 

# control technologies

under evaluation.

These modeling scenarios, and the controls assumed, are as follows:

• Scenario 1 : New LNBs and OFA system, dry FGD system, and the existing ESP. As

indicated previously, this scenario re presents CH2M HILL’s preliminary BART

recommendation.

• Scenario 2 : New LNBs and OFA syst em, dry FGD system, and the replacement of the

ESP with a fabric filter downstr eam of the lime spray dryer.

• Scenario 3 : New LNB and OFA system with SCR, dry FGD system, and the replacement

of the ESP with a fabric filter downstream of the lime spray dryer.

• Scenario 4 : New LNB and OFA system with SCR, wet FGD system and new stack, and

maintaining the existing ESP.

Visibility improvements for all emission contro l scenarios were analyzed, and the results

were compared utilizing a least-cost envelope, as outlined in the New Source Review

Workshop Manual 1



# .



# Least-cost Envelope Analysis

The EPA has adopted the Least-cost Enve lope Analysis Methodology as an accepted

methodology for selecting the most reasonabl e, cost-effective c ontrols. Incremental

cost-effectiveness comparisons focus on annuali zed cost and emission reduction differences

between dominant alternatives. The dominant se t of control alternatives is determined by

generating what is called the enve lope of least-cost alternatives . This is a graphical plot of

total annualized costs for total emissions reduction s for all control altern atives identified in

the BART analysis.

To evaluate the impacts of the modeled contro l scenarios on the two Class I areas, the total

annualized cost, cost per deciview (dV) reducti on, and cost per reduction in number of days

above 0.5 dV were analyzed. This report provid es a comparison of the average incremental

costs between relevant scenario s for the two Class I areas; th e total annualized cost versus

number of days above 0.5 dV; and the total annualized cost versus 98 th 

# percentile

delta-deciview ( Δ dV) reduction.

Results of the least-cost envel ope analysis validate the sele ction of Scenario 1, based on

incremental cost and visibility improvements. Scenario 2 (LNB with OFA, dry FGD, and

new fabric filter) is eliminated, because it is to the left of the curve formed by the dominant

control alternative scenario, which indicates a scenario with lower improvement and/or

higher costs. Scenario 3 (LNB with OFA and SCR, dry FGD, and new fabric filter) is not

selected due to very high incremental cost s, on the basis of both a cost per day of

improvement and cost per dV reduction. While Scenario 4 (LNB with OFA and SCR, wet

1 EPA, 1990. New Source Review Workshop Manual . Draft. Environmental Protection Agency. October, 1990.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC ES-5 

# FGD, and existing ESP) provides some potential visibility advantage over Scenario 1, the

projected improvement is less than half a dV, and the projected costs are excessive.

Therefore, Scenario 1 represents BART for Dave Johnston 3.



# Just-Noticeable Differences in Atmospheric Haze

Studies have been conducted th at demonstrate only dV differe nces of approximately 1.5 to

2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot

be distinguished by the average person. Therefore, the modeling analysis results indicate that

only minimal, if any, observable visibility im provements at the Class I areas studied would

be expected under any of the c ontrol scenarios. Thus, the resu lts indicate that even though

PacifiCorp will be spending many millions of do llars at this single unit—and over a billion

dollars when considering its entire coal fleet—only minimal discernable visibility

improvements may result.

# Contents

1.0 Introduction ........................................................................................................ 1-1

2.0 Present Unit Operation ...................................................................................... 2-1

3.0 BART Engineering Analysis ............................................................................. 3-1

3.1 Applicability ............................................................................................ 3-1

3.2 BART Process .......................................................................................... 3-1

3.2.1 BART NO

x 

# Analysis .................................................................... 3-2

3.2.2 BART SO 2 

# Analysis .................................................................. 3-10

3.2.3 BART PM 10 

# Analysis ................................................................ 3-15

4.0 BART Modeling Analysis .................................................................................. 4-1

4.1 Model Selection ....................................................................................... 4-1

4.2 CALMET Methodology ........................................................................... 4-1

4.2.1 Dimensions of the Modeling Domain .......................................... 4-1

4.2.2 CALMET Input Data ................................................................... 4-3

4.2.3 Validation of CALMET Wind Field ............................................ 4-6

4.3 CALPUFF Modeling Approach ............................................................... 4-6

4.3.1 Background Ozone and Ammonia ............................................... 4-6

4.3.2 Stack Parameters .......................................................................... 4-6

4.3.3 Emission Rates ............................................................................. 4-7

4.3.4 Post-control Scenarios ................................................................. 4-7

4.3.5 Modeling Process ......................................................................... 4-9

4.3.6 Receptor Grids ............................................................................. 4-9

4.4 CALPOST ................................................................................................ 4-9

4.5 Presentation of Modeling Results .......................................................... 4-10

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario ............. 4-10

5.0 Preliminary Assessment and Recommendations ............................................ 5-1

5.1 Least-cost Envelope Analysis .................................................................. 5-1

5.1.1 Analysis Methodology ................................................................. 5-1

5.1.2 Analysis of Results ...................................................................... 5-6

5.2 Recommendations .................................................................................... 5-7

5.2.1 NO

x 

# Emission Control .................................................................. 5-7

5.2.2 SO 2 

# Emission Control .................................................................. 5-7

5.2.3 PM 10 

# Emission Control ................................................................ 5-7

5.3 Just-Noticeable Differences in Atmospheric Haze .................................. 5-7

6.0 References ........................................................................................................... 6-1

P:\PACIFICORP\348295BART\DAVEJOHNSTON3_FINALSUBMITTAL\BART_DJ3_OCT2007_FINAL.DOC 

# iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# iv 

# Tables

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 NO

x 

# Control Technology Emission Rate Ranking

3-2 NO

x 

# Control Cost Comparison

3-3 SO 2 

# Control Technology Emission Rate

3-4 SO 2 

# Control Cost Comparison

3-5 PM 10 

# Control Technology Emission Rates

3-6 PM 10 

# Control Cost

4-1 User-specified CALMET Options

4-2 BART Model Input Data

4-3 Average Natural Levels of Aerosol Components

4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at

Class I Areas

5-1 Badlands Class I Agent Control Data

5-2 Wind Caves Class I Area Control Data

5-3 Badlands Class I Area Incremental Data

5-4 Wind Caves Class I Agent Incremental Data

Figures

3-1 First Year Control Cost for NO

x 

# Air Pollution Control Options

3-2 First Year Control Cost for SO 2 

# Air Pollution Control Options

4-1 Dave Johnston Source-Specific Cl ass I Areas to be Addressed

4-2 Surface and Upper Air Stations Used in the Dave Johnston BART Analysis

5-1 Least-cost Envelope Badlands Class I Area Days Reduction

5-2 Least-cost Envelope Badlands Class I Area 98 th 

# Percentile Reduction

5-3 Least-cost Envelope Wind Caves Class I Area Days Reduction

5-4 Least-cost Envelope Badlands Class I Area 98 th 

# Percentile Reduction

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

°F Degree Fahrenheit

BACT Best Availa ble Control Technology

BART Best Availabl e Retrofit Technology

CALDESK Program to Display Data and Results

CALMET Meteorological Data Pr eprocessing Program for CALPUFF

CALPOST Post-processing Program fo r Calculating Visibility Impacts

CALPUFF Gaussian Puff Dispersion Model

CFR Code of Federal Regulations

CO Carbon Monoxide

COHPAC Compact Hybrid Particulate Collector

dV Deciview

Δ dV Delta Deciview, Change in Deciview

EPA United States Environmental Protection Agency

ESP Electrostatic Precipitator

f (RH) Relative Humidity Factors

FGC Flue Gas Conditioning

FGD Flue Gas Desulfurization

H 2 

# SO 4 

# Sulfuric Acid

kW Kilowatt

kWh Kilowatt-hour

LAER Lowest Achievable Emission Rate

lb Pound(s)

LNB Low-NO

x 

# Burner

LOI Loss on Ignition

MM5 Mesoscale Meteorologi cal Model, Version 5

MMBtu Million British Thermal Units

MW Megawatt

N 2 

# Nitrogen

NH 4 

# Ammonium

(NH 4 

# ) 2 

# SO 4 

# Ammonium Sulfate

NO

x 

# Nitrogen Oxide

NP National Park

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# vi 

# NSR Manual New Source Review Workshop Manual (EPA, 1990)

OFA Over-fire Air

PM Particulate Matter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PM 2.5 

# Particulate Matter less than 2.5 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Study Multi-Pollutant Contro l Report dated October, 2002

S&L Sargent & Lundy

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

TRC TRC Companies, Inc.

USGS United States Geological Survey

WDEQ Wyoming Department of Environmental Quality

WDEQ-AQD Wyoming Department of Envir onmental Quality – Air Quality Division

# 1.0 Introduction

Best Available Retrofit Technol ogy (BART) guidelines were esta blished as a result of United

States Environmental Protection Agency (EPA) re gulations intended to re duce the occurrence of

regional haze in national parks (NPs) and other Cl ass I protected air quality areas in the United

States. These guidelines provide guidance for states when determining which facilities must

install additional controls, and the type of controls that must be used. Facilities eligible for

BART installation were built between 1962 and 1977, and have the potential to emit more than

250 tons per year of visibility-impairing pollutants.

The Wyoming Department of Environmental Qualit y (WDEQ) BART regulations state that each

source subject to BART must submit a BART application for a construction permit by

December 15, 2006. PacifiCorp received an exte nsion from the WDEQ to submit the BART

report for Dave Johnston Unit 3 (hereafter referr ed to as Dave Johnston 3) by January 26, 2007.

The BART Report that was submitted to WDEQ in January 2007 included a BART analysis, and

a proposal and justification fo r BART at the source. This report—submitted in October 2007—

incorporates editorial revisions since the January 2007 version.

The State of Wyoming has identified those eligible, in-state facilities requiring emissions

reductions under BART, and will set their BART emissions limits. This information will be

included in Wyoming’s State Implementation Plan (SIP), which the State has estimated will be

formally submitted to the EPA by early 2008. The EPA BART guidelines also state that the

BART emission limits must be fully implemen ted within 5 years of EPA’s SIP approval.

Five elements related to BART address the i ssue of emissions for the identified facilities:

• Any existing pollution control tech nology in use at the source

• The cost of the controls

• The remaining useful life of the source

• The energy and non-air quality envi ronmental impacts of compliance

• The degree of improvement in visibility that ma y reasonably be anticipated from the use of

such technology

This report documents the BART analysis pe rformed on Dave Johnston 3 by CH2M HILL for

PacifiCorp. The analysis was performe d for the pollutants nitrogen oxide (NO

x 

# ), sulfur dioxide

(SO 2 

# ), and particulate matter less than 10 mi crometers in aerodynamic diameter (PM 10 

# ), because

they are the primary criteria pollutants that impact visibility.

Section 2 of this report provi des a description of the pres ent unit operation, including a

discussion of coal sources and characteristics. The BART Engineering An alysis is provided in

Section 3, by pollutant type. Section 4 provi des the methodology and results of the BART

Modeling Analysis, followed by recommendations in Section 5 and references in Section 6.

Appendices provide more detail on the economic analysis and the 2006 Wyoming BART

Protocol.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 1-1

# 2.0 Present Unit Operation

Dave Johnston 3 is a nominal 230-megawatt (MW) , pulverized coal unit located in central

Wyoming, near the town of Glenrock. The unit is equipped with a cell-fired boiler

manufactured by Babcock & Wilcox. The original burners are still being used on the unit.

Dave Johnston 3 is not equipped with any SO 2 

# removal equipment at this time, nor has the

unit undergone combustion control modifications for NO

x 

# control. A Lodge-Cottrell

single-chamber electrostatic precipitator (ESP) for control of partic ulate matter (PM) was

installed in 1976. Table 2-1 lists additional unit information and the basis of design

assumptions.

The coal currently being burned in Dave Johnsto n 3 is from the Clovis Point Mine; however,

coal from Dry Fork, Rawhide, and other north ern Powder River Basin (PRB) mines may also

be used. All of these coals are sub-bitumi nous rank from Wyoming. Coal sources and

characteristics are summarized in Table 2-2.

Dave Johnston 3 was placed in service in 1964. Its current economic depreciation life is

through 2030; however, this an alysis is based on a 20-ye ar life for BART control

technologies. Assuming a BART implementatio n date of 2014, this will result in an

approximate remaining useful life for Dave Johnston 3 of 20 years from the installation date

of any new or modified BART-re lated equipment. This report does not attempt to quantify

any additional life extension costs needed to allow Dave Johnston 3 to operate until 2034.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 2-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 2-2 

# TABLE 2-1



# Present Unit Operation

Dave Johnston 3

General Plant Data

Site Elevation (feet above mean sea level) 4,950

Stack Height (feet) 500

Stack Exit Internal Diameter (f eet) /Exit Area (square feet) 15 / 176.8

Stack Exit Temperature (degrees Fahrenheit) 341

Stack Exit Velocity (feet per second) 105

Stack Flow (actual cubic feet per minute) 1,113,840

Plant Operation Start Date 1964

Latitude (degree: minut e: second) 42:50:16.91

Longitude (degree: minute: second) 105:46:56.28

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 230 (a)



# Net Unit Heat Rate (British thermal unit [Btu]/kilowatthour)(100% load) 11,121 (as measured by fuel throughput)

Boiler Heat Input (million British thermal units [MMBtu] per

hour)(100% load) 2,500 (as measured by continuous emission

monitoring)

Type of Boiler Cell-Fired

Boiler Fuel Coal

Coal Sources Clovis Point Mine, Dry Fork Mine, Rawhide Mine

Coal Heating Value (Btu per pound [lb]) (b) 

# 8,100

Coal Sulfur Content (percentage by weight [wt. %]) (b) 

# 0.47

Coal Ash Content (wt. %) (b) 

# 5.01

Coal Moisture Content (wt. %) (b) 

# 32.0

Coal Nitrogen Content (wt. %) (b) 

# 0.91

Current Nitrogen Oxide (NO

x 

# ) Controls None

NO

x

# Emission Rate(lb/MMBtu) (c) 

# 0.70

Current Sulfur Dioxide (SO 2 

# ) Controls None

SO 2 

# Emission Rate (lb/MMBtu) (c) 

# 1.20

Current PM 10 (d) 

# Controls Electrostatic Precipitator

Particulate Matter (PM) Emission Rate (lb/MMBtu) (e) 

# 0.030

NOTES:

(a) 

# Output is currently limited to 220 MW, until SO 2 

# controls are installed and operating

(b) 

# Coal characteristics vary between coal sources

(c) 

# Emission rates stated on annual average basis

(d) 

# PM 10 

# refers to particulate matter less than 10 micrometers in aerodynamic diameter

(e) 

# Emission rate stated from test resultsBART ANALYSIS FOR DAVE JOHNSTON UNIT 3TABLE 2-2Coal Sources and CharacteristicsDave Johnston 3Ultimate Analysis (% dry basis)MinesMoisture(%)Ash (%)VolatileMatter(%)FixedCarbon(%)Britishthermalunits perpound(Btu/lb)Sulfur(%)Moistureand AshFree(Btu/lb)HydrogenCarbonSulfurNitrogenOxygenAshClovis Point Mine32.05.331.131.28,0450.4112,8354.9967.30.870.9116.29.7Maximum33.17.034.035.08,2830.4612,9615.5869.51.071.0018.810.8Minimum29.94.530.029.07,9010.3612,7443.8264.40.630.8314.38.7Dry Fork Mine32.15.229.533.08,0360.3912,8184.5668.70.571.0017.77.4Maximum30.74.539.142.78,2000.5412,9245.0471.30.761.5219.710.6Minimum33.27.828.931.97,6500.2612,7264.0765.80.340.6015.65.3Rawhide Mine30.45.330.433.98,2850.3712,8754.6369.40.500.9717.37.3Maximum31.66.632.737.18,4800.5313,0005.4171.10.631.1018.78.5Minimum29.04.529.531.78,1200.2112,5754.3166.30.390.7815.36.6Other NorthernPowder RiverBasin30.15.930.833.28,1220.3912,8434.7368.40.650.9617.18.1Maximum32.05.331.131.28,0450.4112,8354.9967.30.870.9116.29.7Minimum33.17.034.035.08,2830.4612,9615.5869.51.071.0018.810.8JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC2-3

# 3.0 BART Engineering Analysis

This section presents the requi red BART engineering analysis.



# 3.1 Applicability

In compliance with regional haze requirements, the State of Wyoming must prepare and

submit visibility SIPs to the EPA for Class I areas. The State has estimated that the formal

submittal of the SIPs will occur by early 2008. The first phase of the regional haze program

is the implementation of BART emission controls on all BART-eligible units, within 5 years

after EPA approval of the SIP.



# 3.2 BART Process

The specific steps in a BART engineering anal ysis are identified in the Code of Federal

Regulations (CFR) at 40 CFR 51, Appendix Y, Section IV. Th e evaluation must include:

• The identification of available, techni cally feasible, retr ofit control options

• Consideration of any pollution control equipment in use at the source (which affects the

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

• The energy and non-air quality envi ronmental impacts of compliance

• The degree of visibility improvement that ma y reasonably be anticipated from the use of

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Availabl e Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

− The identification of available, techni cally feasible, retr ofit control options

− Consideration of any pollution control equipm ent in use at the source (which affects

the applicability of optio ns and their impacts)

• Step 3 – Evaluate Control Effectiven ess of Remaining Control Technologies

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 3-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# • Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

− The energy and non-air quality envi ronmental impacts of compliance

• Step 5 – Evaluate Visibility Impacts

− The degree of visibility improvement that may reasonably be anticipated from the use

of BART

In order to minimize costs in the BART anal ysis, consideration was made of any pollution

control equipment in use at the source, the co sts of compliance associ ated with the control

options, and the energy and non-air quality envi ronmental impacts of compliance using these

existing control devices. In some cases, enha ncing the performance of the existing control

equipment was considered. Other scenarios with new control equipment were also

developed.

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included

in the BART analysis are in 2006 dollars, and co sts have not been escalated to the assumed

2014 BART implementation date.



# 3.2.1 BART NO

x 

# Analysis

Nitrogen oxide formation in coal -fired boilers is a complex pr ocess that is dependent on a

number of variables, including operati ng conditions, equipment design, and coal

characteristics.

Formation of NO

x



# During coal combustion, NO

x 

# is formed in three different ways. The dominant source of NO

x 

# formation is the oxidation of fuel-bound nitrog en. During combustion, pa rt of the fuel-bound

nitrogen is released from the coal with the vola tile matter, and part is retained in the solid

portion (char). The nitrogen chemically bound in the coal is partially oxidized to nitrogen

oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen. A

smaller part of NO

x 

# formation is due to high temperature fixation of atmospheric nitrogen in

the combustion air. A very small amount of NO

x 

# is called prompt NO

x 

# . Prompt NO

x 

# results

from an interaction of hydrocar bon radicals, nitrogen, and oxygen.

In a conventional pulverized co al burner, air is introduced wi th turbulence to promote good

mixing of fuel and air, which provides stable combustion. Howe ver, not all of the oxygen in

the air is used for combustion. Some of the oxyge n combines with the fuel nitrogen to form

NO

x 

# .

Coal characteristics directly and significantly affect NO

x 

# emissions from coal combustion.

Coal ranking is a means of classifying coals according to their degree of metamorphism in

the natural series, from lignite to sub-bitumi nous to bituminous and on to anthracite. Lower

rank coals, such as the sub-bituminous coals from the PRB, produce lower NO

x 

# emissions

than higher rank bituminous coals, due to their higher reactivity and lower nitrogen content.

The fixed carbon to volatile matter ratio (fuel ratio), coal oxygen c ontent, and rank are good

relative indices of the reactivity of a coal. Lo wer rank coals release more organically bound

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# nitrogen earlier in the combus tion process than do higher rank bituminous coals. When used

with low-NO

x 

# burners (LNBs), sub-bituminous coals cr eate a longer time for the kinetics to

promote more stable molecular nitr ogen, and hence result in lower NO

x 

# emissions.

Coals from the PRB are classified as sub-b ituminous C and demonstrate the high reactivity

and low NO

x 

# production characteristics described above. Based on data from the Energy

Information Administration, PRB coals currentl y represent 88 percent of total U.S. subbituminous production and 73 percent of west ern coal production (Energy Information

Administration, 2006). Most references to west ern coal and sub-bituminous coal infer PRB

origin and characteristics. Em issions standards differentiating between bituminous and subbituminous coals are presumed to use PRB coal as the basis for the sub-bituminous

standards, due to its dominant market presence and unique characteristics.

Dave Johnston 3 burns sub-bituminous coals from the PRB. The BART presumptive NO

x 

# limit for sub-bituminous coal combusted in wall-fired cell burners is 0.45 pound (lb) per

million British thermal unit (MMBtu). The NO

x 

# emission rate at Dave Johnston 3 is 0.70 lb

per MMBtu, which would indicate that a 33 percent reduction from current NO

x 

# emission

levels would be needed to meet the BART presumptive NO

x 

# limit.

The BART analysis for NO

x 

# emissions from Dave Johnston 3 is described in this section.

Step 1: Identify All Availabl e Retrofit Control Technologies

The first step of the BART process is to evaluate NO

x 

# control technologies with practical

potential for application to Dave Johnston 3, including those control technologies identified

as Best Available Control Tec hnology (BACT) or lowest achievable emission rate (LAER)

by permitting agencies across the United States. A broad range of information sources have

been reviewed in an effort to identify poten tially applicable emission control technologies.

Dave Johnston 3 NO

x 

# emissions are currently controlled through the use of good combustion

practices.

The following potential NO

x 

# control technology options were considered:

• New LNBs with advanced over-fire air (OFA)

• Mobotec Rotating Opposed Fire Air (ROFA)

• Conventional selectiv e non-catalytic reduction (SNCR) system

• Selective catalytic reduction (SCR) system

Step 2: Eliminate Technically Infeasible Options

For Dave Johnston 3 on a wall-fired cell burner configuration burning sub-bituminous coal,

technical feasibility will primarily be de termined by physical constraints and boiler

configuration. Dave Johnst on 3 has an uncontrolled NO

x 

# emission rate of 0.70 lb per

MMBtu.

For this BART analysis, information pertaini ng to LNBs, OFA, SNCR, and SCR were based

on the Multi-Pollutant Control Report (Sargent and Lundy, 2002, hereafter referred to as the

S&L Study). Updated cost estimates for S CR and SNCR were used (Sargent & Lundy,

2006). PacifiCorp provided additional emissions data and costs developed by boiler vendors

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# for LNBs and OFA. Also, CH2M HILL solicit ed a proposal from Mobotec for their ROFA

technology.

With SNCR, an amine-based reagent such as ammonia—or mo re commonly urea—is

injected into the furnace within a temperatur e range of 1,600 degrees Fahrenheit (°F) to

2,100°F, where it reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 60 percent

have been achieved, although 20 to 40 percent is more realistic for mo st applications. SNCR

is typically applied on smaller units. Adequate reagent distribution in the furnaces of large

units can be problematic.

Table 3-1 summarizes the control technology options evaluated in this BART analysis, along

with projected NO

x 

# emission rates.

TABLE 3-1



# NO

x 

# Control Technology Emission Rate Ranking

Dave Johnston 3

Technology Projected Emission Rate

(pounds per million

British thermal units)

Presumptive Best Available Retrof it Technology (BART) Limit 0.45

Low-NO

x

# burners (LNBs) with over-fire air (OFA) 0.24

Rotating Opposed Fire Air 0.19

LNB with OFA and Selective Non-catalytic Reduction (SNCR) 0.19

LNB with OFA and Selective Catalytic Reduction (SCR) 0.07



# Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

Preliminary vendor proposals, such as those used to support portions of this BART analysis,

may be technically feasible and provide expect ed or guaranteed emission rates; however, the

proposals include inherent uncer tainties. These proposals are us ually prepared in a limited

time frame, may be based on incomplete information, may contain over-optimistic

conclusions, and are non-binding. Therefore, emission rate values obtained in such

preliminary proposals must be qualified, and it must be recognized that contractual

guarantees are established only after more de tailed analysis has been completed. The

following subsections describe the control technologies and the control effectiveness

evaluated in this BART analysis.

New LNBs with OFA System. The mechanism used to lower NO

x 

# with LNBs is to stage the

combustion process and provide a fuel-rich condi tion initially; this is so oxygen needed for

combustion is not diverted to combine with nitrogen and form NO

x 

# . Fuel-rich conditions

favor the conversion of fuel ni trogen to nitrogen instead of NO

x 

# . Additional air (or OFA) is

then introduced downstream in a lower te mperature zone to burn out the char.

Both LNBs and OFA are considered to be a capital cost, combustion technology retrofit. For

LNB retrofits to units configured with wall-fire d cell burners such as Dave Johnston 3, it is

generally necessary to increase the burner spacin g; this prevents interaction of the flames

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# from adjacent burners and reduces burner zone heat flux. These modifi cations usually require

boiler waterwall tube replacement.

Information provided to CH2M HILL by P acifiCorp—based on the S&L Study and data

from boiler vendors—indicates that a new LNB and OFA retrofit at Dave Johnston 3 would

result in an expected NO

x 

# emission rate of 0.24 lb per MMBtu. PacifiCorp has indicated that

this rate corresponds to a vendor guarantee, pl us an added operating margin, not a vendor

prediction; they also believe that this emissi on rate can be sustained as an average between

overhauls. This emission rate represents a significant redu ction from the 2005 average NO

x 

# emission rate, and is comfortably below the presumptive NO

x 

# emission rate of 0.45 lb per

MMBtu.

ROFA. Mobotec markets ROFA as an improved second generation OFA system. Mobotec

states that “the flue gas volume of the furn ace is set in rotation by as ymmetrically placed air

nozzles. Rotation is reported to prevent laminar flow, so that the entire volume of the furnace

can be used more effectively for the combus tion process. In addition, the swirling action

reduces the maximum temperature of the fl ames and increases heat absorption. The

combustion air is also mixed more effectivel y.” A typical ROFA installation will have a

booster fan(s) to supply the high velocity air to the ROFA boxe s, and Mobotec would

propose one 3,000 to 3,700 horsepower fan for Dave Johnston 3.

Mobotec expects to achieve a NO

x 

# emission rate of 0.15 lb per MMBtu using ROFA

technology. An operating margin of 0.04 lb per MMB tu was added to the expected rate due

to Mobotec’s limited ROFA experience with western sub-bituminous coals. Under the

Mobotec proposal—primarily based on ROFA equi pment—the operation of existing burners

was analyzed. While a typical installation does not require modification to the existing burner

system, results of computational fluid dynami cs modeling will determine the quantity and

location of new ROFA ports. The Mobotec prop osal includes bent tube assemblies for OFA

port installation. Mobotec does not provide installation services, because they believe that the

Owner can more cost-effectively contract for these services. However, they do provide one

onsite construction supervisor dur ing installation and startup.

Because of the expected marginal emission rate improvement, the burden of significant

ongoing parasitic costs, the operating difficulties, and the lack of vendor experience with

sub-bituminous coals, ROFA was not consider ed in the post-contro l modeling scenarios.

SNCR. Selective non-catalytic redu ction is generally utilized to achieve modest NO

x 

# reductions on smaller units. With SNCR, an am ine-based reagent such as ammonia—or more

commonly urea—is injected into the furnace within a temperature range of 1,600°F to

2,100°F, where it reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 60 percent

have been achieved, although 20 to 40 percent is more realistic for most applications.

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NO

x 

# , can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating

conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or

inadequate mixing, ammonia slip occurs, allowing unreacted a mmonia to create problems

downstream. The ammonia may render fly ash unsa leable, react with su lfur to foul heat

exchange surfaces, and/or create a visible stack plume. Reagent utilization can have a

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# significant impact on economics, with higher levels of NO

x 

# reduction generally resulting in

lower reagent utilization and higher operating cost.

Reductions from higher baseline concentrations (inlet NO

x 

# ) are lower in cost per ton, but

result in higher operating costs, due to greate r reagent consumption. To reduce reagent costs,

S&L has assumed that combus tion modifications including LNBs and advanced OFA,

providing a NO

x 

# emission rate of 0.24 lb per MMBtu, w ould be installed in conjunction with

SNCR

. At Dave Johnston 3, a further reduction of 20 percent in NO

x 

# emission rates results in

a projected emission rate of 0.19 lb per MMBtu for SNCR.

Because of the expected marginal emission rate improvement, the burden of significant

ongoing parasitic costs, the operating difficultie s, and the potential ammonia slip emission

problems, SNCR was not considered in the post-control modeling scenarios.

SCR. SCR works on the same principle as SNCR, but uses a catalyst to promote the reaction.

Ammonia is injected into the flue -gas stream, where it reduces NO

x 

# to nitrogen and water.

Unlike the high temperatures required for SNCR , the reaction takes pl ace on the surface of a

vanadium/titanium-based catalyst at a temperature range between 580°F to 750°F. Due to the

catalyst, the SCR process is more efficient th an SNCR. The most common type of SCR is the

high-dust configuration, where the catalyst is located upstr eam of the air heater and

downstream from the economizer. The high-dus t configuration is assumed for Dave

Johnston 3. In a full-scale SCR, the flue ducts are routed to a se parate large reactor

containing the catalyst. With in-duct SCR, the catalyst is located in the existing gas duct,

which may be expanded in the area of the catalyst to increase flue gas residence time. Due to

the higher removal rate, a full- scale SCR was used as the basis for analysis at Dave

Johnston 3.

S&L prepared the design conditions and cost es timates for SCR at Dave Johnston 3. As with

SNCR, it is generally more cost effective to reduce NO

x 

# emission levels as much as possible

through combustion modifications, in order to minimize the catalyst surface area and

ammonia requirements of the SCR. To redu ce reagent costs, S&L has assumed that

combustion modifications—including LNBs and OFA, providing a NO

x 

# emission rate of

0.34 lb per MMBtu—would be installed in conjun ction with the SCR. The S&L design basis

includes a 90 percent removal rate , which results in a projected NO

x 

# emission rate of 0.07 lb

per MMBtu. Additional catalyst surface was included in the SCR design to accommodate the

characteristics of the coal used at Dave Johnston 3.

Level of Confidence for Vendor Post-control Emissions Estimates. In order to determine the

level of NO

x 

# emissions needed to consistently achieve compliance with an established goal, a

review of typical NO

x 

# emissions from coal-fired generati ng units was completed. As a result

of this review, it was noted that NO

x 

# emissions can vary signif icantly around an average

emissions level. This variance can be attr ibuted to many reason s, including coal

characteristics, unit load, boiler operation including excess air, boiler slagging, burner

equipment condition, coal mill fineness, and so forth.

The steps utilized for determining a level of confidence for the vendor expected value are as

follows:

1. Establish expected NO

x 

# emissions value from vendor.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# 2. Evaluate vendor experience and historical basis for meeting expected values.

3. Review and evaluate unit physical and opera tional characteristics and restrictions. The

fewer variations there are in operations, coal supply, etc., the more predictable and less

variant the NO

x 

# emissions are.

4. For each technology expected value, there is a corresponding potential for actual NO

x 

# emissions to vary from this expected va lue. From the vendor information presented,

along with anticipated unit operational data, an adjustment to the expected value can be

made.

Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration of energy, environmental, and economic impacts

associated with each control technology. The remaining useful life of the plant is also

considered during the evaluation.

Energy Impacts. The installation of LNBs with OFA is not expected to significantly impact

the boiler efficiency or forced-draft fan power usage. Therefore, these technologies will not

have energy impacts.

The Mobotec ROFA system requires in stallation and opera tion of one 3,000 to

3,700 horsepower ROFA fan.

Selective catalytic reduction re trofit impacts the existing flue gas fan systems, due to the

additional pressure drop associated with the cat alyst, which is typica lly a 6- to 8-inch

increase. Total additional power requirements for SCR installation at Dave Johnston 3 are

estimated at approximately 1,570 kilowatts (kW), based on the S&L Study.

Environmental Impacts. Mobotec has predicted that the RO FA system may result in an

increase in carbon monoxide (C O) emissions, and LOI (loss on ignition) would be the same

or lower than prior levels. In stallation of LNBs with OFA ma y also result in higher CO

emissions and LOI, which will result in unburned carbon in the ash.

The installation of SNCR or SCR systems could impact the saleability and disposal of fly ash

due to ammonia levels, and could potentially cr eate a visible stack plume, which may negate

other visibility improvements.

Other environmental impacts involve the stor age of ammonia, especially if anhydrous

ammonia is used, and the transportation of the ammonia to the power plant site.

Economic Impacts. Costs and schedules for the LNBs and OFA, SNCR, and SCR were

furnished to CH2M HILL by PacifiCorp, de veloped using S&L’s internal proprietary

database, and supplemented (as needed) by ve ndor-obtained price quotes. The relative

accuracy of these cost estimates is stated by S&L to be in the range of plus or minus

20 percent. Cost for the ROFA system was obtained from Mobotec, to which construction

and other costs were added to make a comparable estimate.

A comparison of the technologies on the basis of costs, design control efficiencies, and tons

of NO

x 

# removed is summarized in Table 3-2. The co mplete economic analysis is contained in

Appendix A.

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 3-8 

# TABLE 3-2



# NO

x 

# Control Cost Comparison

Dave Johnston 3

Factor Low-NO

x 

# Burners

(LNBs) with

Over-fire

Air (OFA) Mobotec

Rotating

Opposed

Fire Air

(ROFA) LNB with

OFA and

Selective

NonCatalytic

Reduction

(SNCR) LNB with

OFA and

Selective

Catalytic

Reduction

(SCR)

Total Installed Capital Costs $15.9 mi llion $12.1 million $24.0 million $83.3 million

Total First Year Fixed and Variable

Operation and Maintenance Costs $0.1 million $1.2 million $1.0 million $1.8 million

Total First Year Annualized Cost $1.6 mil lion $2.4 million $3.3 million $9.7 million

Power Consumption (mega watts)

---- 2.76 0.23 1.57

Annual Power Usage

(million kilowatt-hours per year) ---- 21.8 1.8 12.4

Nitrogen Oxide (NO

x 

# ) Design Control Efficiency 65.7% 72.9% 72.9% 90%

Tons NO

x

# Removed per Year 5,077 5,629 5,629 6,954

First Year Average Control Cost (dollars per ton

[$/Ton] of NO

x

# Removed) $318/ton $424/ton $584/ton $1,401/ton

Incremental Control Cost ($/Ton of NO

x

# Removed) $318/ton $1,398 /ton $3,035/ton $5,555/ton



# Preliminary BART Selection. CH2M HILL recommends the selection of LNBs with OFA as

BART for Dave Johnston 3 based on its significant reduction in NO

x 

# emissions, reasonable

control cost, and no additional power require ments or environmental impacts. Low-NO

x 

# burners with OFA is projected to meet the EPA presumptive limit of 0.45 lb per MMBtu for

the PRB sub-bituminous coal burned at the facility.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR DAVE JOHNSTON UNIT 3FIGURE 3-1First Year Control Cost for NOxAir Pollution Control OptionsDave Johnston 301,0002,0003,0004,0005,0006,000LNB w/OFAROFALNB w/OFA & SNCRLNB w/OFA & SCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC3-9

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# 3.2.2 BART SO 2 

# Analysis

Sulfur dioxide forms in the boiler during the combustion process, and is primarily dependent

on coal sulfur content. The BART analysis for SO 2 

# emissions on Dave Johnston 3 is

described below.

Step 1: Identify All Availabl e Retrofit Control Technologies

A broad range of information sources were revi ewed, in an effort to identify potentially

applicable emission control technologies for SO 2 

# at Dave Johnston 3; this included control

technologies identified as BACT or LAER by permitting agencies across the United States.

The following potential SO 2 

# control technology options were considered:

• Dry flue gas desulfurization (FGD) system with existing ESP

• Dry FGD system with new fabric filter

• Wet FGD system and new stack with existing ESP

Step 2: Eliminate Technically Infeasible Options

Dave Johnston 3 currently has an uncontrolled SO 2 

# emission rate of 1.20 lb per MMBtu. The

following summarizes the technical feasibility analysis performed.

Dry FGD with Existing ESP. The lime spray dryer typically inj ects lime slurry in the top of the

absorber vessel with a rapidly rotating atom izer wheel. The rapid speed of the atomizer

wheel causes the lime slurry to separate into ve ry fine droplets that in termix with the flue

gas. The SO 2 

# in the flue gas reacts with the calcium in the lime slurry to form calcium sulfate

in the form of particulate matter. At Dave Johnston 3, this dry particulate matter would be

captured in the downstream existing ESP, along with the fly ash. A lime spray dryer system

typically produces a dry waste produ ct suitable for landfill disposal.

Dry FGD with the existing ESP is projected to achieve 81.7 percent SO 2 

# removal. At Dave

Johnston 3, this would result in a controlled SO 2 

# emission rate of 0.22 lb per MMBtu, based

on an average coal sulfur cont ent of 0.47 percent by weight.

Lime Spray Drying FGD with New Fabric Filter. If the existing ESP is replaced with a fabric

filter located downstream of the lime spray dryer, then 90.0 percent SO 2 

# removal is

projected, allowing the facility to achieve a limit of 0.12 lb SO 2 

# per MMBtu.

The combination of dry FGD followed by the existing ESP and a new polishing fabric filter

is projected to result in a controlled SO 2 

# emission rate of 0.15 lb per MMBtu, based on an

average coal sulfur content of 0.47 percent by wei ght. This option is described in more detail

in Section 3.2.3, Step 2.

Wet Lime/Limestone FGD. Wet SO 2 

# scrubbers operate by flowi ng the flue gas upward through

a large reactor vessel that has an alkaline r eagent (typically a lime or limestone slurry)

flowing down from the top. The scrubber mixes the flue gas and alkaline reagent using a

series of spray nozzles to distribute the reagent across the scrubber vessel. The calcium in the

reagent reacts with the SO 2 

# in the flue gas to form calcium sulfite and/or calcium sulfate,

which are removed from the sc rubber with the sludge, and disposed. Most wet FGD systems

use forced oxidation to assure that only calcium sulfate sludge is produced. The wet

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 3-10

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# lime/limestone forced oxidation process is used in most new wet FGD installations. Several

variations on wet FGD technology are offe red by various process developers. These

variations include using a jet bubb ling reactor as a combination SO 2 

# absorber and calcium

sulfite oxidation vessel , and using magnesium enhanced li me as the alkaline reagent. Wet

lime/limestone scrubbing is projected to achieve an SO 2 

# removal rate of 95 percent and an

outlet SO 2 

# emission rate of 0.058 lb per MMBtu.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

Table 3-3 summarizes the projected emission ra tes for the FGD technologies being evaluated

for Dave Johnston 3.

TABLE 3-3



# SO 2 

# Control Technology Emission Rate

Dave Johnston 3

Control Technology Projected Sulfur Dioxide (SO 2 

# ) Emission Rate

(pound per million Brit ish thermal units)

Presumptive Best Available Re trofit Technology Limit 0.15

Wet Lime/Limestone Flue Gas Desulfurization (FGD) 0.058

Dry FGD with Fabric Filter 0.12

Dry FGD with Existing Electrostatic Precipitator (ESP) 0.22



# Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration of energy, environmental, and economic impacts

associated with each control technology. The remaining useful life of the plant is also

considered during the evaluation.

Energy Impacts. A dry FGD system with the existing E SP has the advantage of requiring less

electric power for its operation, compared to a wet FGD system. A dry FGD system at

Dave Johnston 3 using the existing ESP woul d require approximately 2.5 MW of power,

compared to approximately 3.5 MW for wet FGD. Based on a 90 percent annual plant

capacity factor, this would equate to an a nnual power savings of approximately 7.5 million

kilowatt-hour (kWh) for dry FGD ve rsus wet FGD for Dave Johnston 3.

Environmental Impacts. The dry FGD system has the following environmental advantages

when compared to wet FGD technology:

• Sulfuric Acid Mist. Sulfur trioxide (SO 3 

# ) in the flue gas, which condenses to liquid

sulfuric acid at temperatures below the acid dew point, is removed e fficiently with a lime

spray dryer system. Wet scrubbers capt ure less than 40 to 60 percent of SO 3 

# and may

require the addition of a wet ESP or hydrated lime injection when me dium to high sulfur

coal is burned in a unit, in or der to remove the balance of SO 3 

# . Otherwise, the emission of

sulfuric acid mist, if above a threshold value, may result in a visible plume after the vapor

plume dissipates.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# • Plume Buoyancy. Flue gas following a dry FGD syst em is not saturated with water

(30 ° F to 50 ° F above dew point), which reduces or eliminates a visible moisture plume.

Wet FGD scrubbers produce flue gas that is saturated with water, which would require a

gas-gas heat exchanger to reheat the flue gas if it were to operate as a dry stack. Due to

the high capital and operating costs associated with heating the flue gas, all recent wet

FGD systems in the United States have used wet stack operation.

• Liquid Waste Disposal. There is no liquid waste from a dry FGD system. However, wet

FGD systems produce a wastewater blowdown stream that must be treated to limit

chloride buildup in the absorber scrubbing l oop. In some cases, a wastewater treatment

plant must be installed to treat the liqui d waste prior to disposal. The wastewater

treatment plant would produce a small vol ume of solid waste, which may be

contaminated with toxic metals (includi ng mercury), requirin g proper disposal.

• Solid Waste Disposal. The creation of a wet sludge from the wet FGD process creates a

solid waste handling and disposal challenge. This sludge need s to be handled properly to

prevent groundwater contamination. Wet FGD systems can produce saleable gypsum if a

gypsum market is available, reducing the qua ntity of solid waste from the power plant

that needs to be disposed.

• Makeup Water Requirements. Dry FGD has advantages over a wet scrubber,

producing a dry waste material and requiring less makeup wate r in the absorber. Given

that water is a valuable commodity in we stern Wyoming, the reduced water consumption

required for dry FGD is a major advantage for this technology.

Economic Impacts. A summary of the costs and amounts of SO 2 

# removed for each technology

option is provided in Table 3-4, and a comparison of the first year control cost (dollars per

ton removed) is shown in Figure 3-2. The co mplete economic analysis is contained in

Appendix A.

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 3-13



# TABLE 3-4



# SO 2 

# Control Cost Comparison

Dave Johnston 3

Factor Dry Flue Gas

Desulfurization

(FGD) with

Electrostatic

Precipitator Dry FGD with

Fabric Filter Wet Lime FGD

Total Installed Capital Costs $91. 5 million 139.0 million $144.3 million

Total First Year Fixed and Variable

Operation and Maintenance Costs $4.8 million $5.6 million $6.3 million

Total First Year Annualized Cost $13.5 million $18.8 million $20.0 million

Power Consumption (megawatts) 2.49 3.88 3.45

Annual Power Usage

(million kilowatt-hours per year) 19.7 30.6 27.2

Sulfur Dioxide (SO 2 

# ) Design Control

Efficiency 81.7% 90.0% 95.0%

Tons SO 2 

# Removed per Year 10,817 11,920 12,583

First Year Average Control Cost (dollars

per ton [$/Ton] of SO 2 

# Removed) $1,251/ton $1,576/ton $1,591/ton

Incremental Control Cost ($/Ton of SO 2 

# Removed) $1,251/ton $4,758 /ton $1,859/ton



# Preliminary BART Selection. CH2M HILL recommends a lime spray drying FGD system as

BART for Dave Johnston 3, based on the significant reduction in SO 2 

# emissions, reasonable

control costs, and the advantages of mini mal additional power requirements and minimal

non-air quality environmental impacts. Although th is approach is projec ted to not meet the

BART presumptive SO 2 

# limit of 0.15 lb per MMBtu, the cost-effectiveness analysis

performed in Section 5, as well as the advantages of zero to mini mal non-air impacts, lead us

to recommend this selection. When the costs ve rsus the visibility improvements (measured as

either deciview [dV] reduction or as the reduc tion in the number of days above 0.5 dV) of the

next control scenario, Scenario 2, is compared with Scenario 1, the analysis indicates

excessive incremental costs for minimal benefit in visibility.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR DAVE JOHNSTON UNIT 3FIGURE 3-2First Year Control Cost for SO2Air Pollution Control OptionsDave Johnston 305001,0001,5002,0002,5003,0003,5004,0004,5005,000Dry FGD w/ESPDry FGD w/Fabric FilterWet FGD w/ESPAir Pollution Control Option

Control Cost ($/Ton SO2 Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC3-14

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# 3.2.3 BART PM 10



# Analysis

Dave Johnston 3 is currently equipped with an ESP. Electrostatic precipitators remove PM

from the flue gas stream by charging fly ash pa rticles with a very high direct current voltage,

and attracting these particles to grounded collection plates. A layer of collected PM forms on

the collecting plates and is removed by period ically rapping the plates. The collected ash

particles drop into hoppers below the precipita tor and are removed pe riodically by the fly

ash-handling system. The ESP at Dave Johnsto n 3 controls PM emissions to 0.030 lb per

MMBtu.

The BART analysis for PM emissions on Dave Johnston 3 is described below. For the

modeling analysis to be completed in Section 4, PM 10 

# will be used as an indicator for PM,

and PM 10 

# includes particulate matter less than 2.5 micrometers in aerodynamic diameter

(PM 2.5 

# ) as a subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

Two retrofit control t echnologies have been identified for additional PM control:

• Flue gas conditioning

• Polishing fabric filter downstream of existing ESP

• Baghouse fabric filter

Step 2: Eliminate Technically Infeasible Options

Flue Gas Conditioning. If the fly ash from coal has high re sistivity, such as fly ash from PRB

coal, the ash is not collected effectively in a small ESP. Adding flue gas conditioning (FGC),

which is typically accomplished by injection of SO 3 

# , will lower the resistivity of the particles

so that they will accept more charge and will allow the ESP to collect the ash more

effectively. Adding FGC can account for large improvements in collection efficiency for

small ESPs.

The Dave Johnston 3 ESP was sized based on a very conservative de sign. It has a large

specific collecting area and large residence time in the collection area of the ESP. This ESP

operates effectively without the assistan ce of FGC equipment; thus, a significant

improvement in collection effi ciency is not expected w ith the addition of FGC to

Dave Johnston 3. Therefore, this option will not be carried forward to the next step of the

BART analysis.

Polishing Fabric Filter. A polishing fabric filter could be added downstream of the existing

ESP at Dave Johnston 3. One such technology is licensed by the Electric Power Research

Institute, and referred to as a Compact H ybrid Particulate Collector (COHPAC). The

COHPAC collects the ash that is not collected by the ESP, thus acti ng as a polishing device.

The ESP needs to be kept in service for the COHPAC fabric filter to work.

The COHPAC fabric filter is about one-half to two-thirds the size of a full-size fabric filter,

because the COHPAC has a higher air-to-cloth ratio (7 to 9:1) , compared to a full-size pulse

jet fabric filter (3.5 to 4:1).

Baghouse Fabric Filter. Another available contro l technology is replacing the existing ESP

with a new baghouse fabric filter. However, beca use the environmental benefits (that is, the

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# same control efficiencies that would be achieved by a replacement fabric filter) are also

achieved by installing a polishing fa bric filter downstream of the existing ESP at lower costs,

installation of a full-size fabric filter was not considered in the analysis.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

The existing ESP at Dave Johnston 3 is achievi ng a controlled PM emission rate of 0.03 lb

per MMBtu. Adding a COHPAC fabric filter downstream of the existing ESP is projected to

reduce PM emissions to approximately 0.015 lb per MMBtu.

The PM 10 

# control technology emission rates are summarized in Table 3-5.

TABLE 3-5



# PM 10



# Control Technology Emission Rates

Dave Johnston 3

Control Technology Projected PM 10 (a) 

# Emission Rate

(pound per million

British thermal units)

Current Electrostatic Precip itator (ESP) Controls 0.030

Polishing Fabric Filter with Existing ESP 0.015

(a) 

# PM 10 

# refers to particulate matter less than 10 micrometers in aerodynamic diameter



# Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration of energy, environmental, and economic impacts

associated with each control technology. The remaining useful life of the plant is also

considered during the evaluation.

Energy Impacts. Energy is required to overcome the additional pressure drop from the

COHPAC fabric filter and a ssociated ductwork. Therefore, a COHPAC retrofit will require

an internal diameter fan upgrade and upgrad e of the auxiliary power supply system.

The Dave Johnston 3 COHPAC fabric filter w ould require approximately 1.4 MW of power,

equating to an annual power usage of approximately 10.3 million kWh, based on an

85 percent annual plan t capacity factor.

Environmental Impacts. There are no negative environmental impacts from the addition of a

COHPAC polishing fabric filter.

Economic Impacts. A summary of the costs and PM removed for the fabric filter is provided

in Table 3-6. The complete economic an alysis is contained in Appendix A.

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

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# 3-17 

# TABLE 3-6



# PM 10



# Control Cost

Dave Johnston 3

Factor Compact Hybrid Particulate Collector

(COHPAC) Fabric Filter wi th Existing Electrostatic

Precipitator (ESP)

Total Installed Capital Costs $29.8 million

Total First Year Fixed and Variable Operations and

Maintenance Costs $0.8 million

Total First Year Annualized Cost $3.6 million

Power Consumption (megawatts) 1.38

Annual Power Usage (million kilowatt-hours per year) 10.9

Particulate Matter (PM) Design Control Efficiency 50.0%

Tons PM Removed per Year 166

First Year Average Control Cost (dollars per ton [$/ton]

of PM Removed) $22,008/ton

Incremental Control Cost ($/T on of PM Removed) $22,008/ton



# Preliminary BART Selection. CH2M HILL recommends maintaining the existing ESP as

BART for Dave Johnston 3, based on the significant reduction in PM 10 

# emissions, the

reasonable control costs, and the advantages of no additional power requirements and no

non-air quality environmental impacts.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.

# 4.0 BART Modeling Analysis

4.1 Model Selection

CH2M HILL used the CALPUFF modeling syst em to assess the visibility impacts of

emissions from Dave Johnston 3 at nearby Cl ass I areas. The Class I areas potentially

affected are located more than 50 kilometers but less than 300 kilome ters from the Dave

Johnston 3 facility. These areas include:

• Wind Cave NP

• Badlands NP

The CALPUFF modeling system includes the CALMET meteorological model, a Gaussian

puff dispersion model (CALPUFF) with algor ithms for chemical transformation and

deposition, and a post processor ca pable of calculating co ncentrations, visib ility impacts, and

deposition (CALPOST). The CALPUFF modeling system was applied in a full, refined

mode. Version numbers of the various pr ograms in the CALPUFF system used by

CH2M HILL were as follows:

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

CH2M HILL used the CALMET model to genera te a three-dimensional wind field and other

meteorological parameters suitable for use by the CALPUFF model. A modeling domain was

established to encompass the Dave Johnston facility and allow for a 50-kilometer buffer

around the Class I areas that were within 300 kilo meters of the facilit y. Grid resolution was

4 kilometers. Figure 4-1 shows the extent of the modeling domain. Except when specifically

instructed otherwise by the Wyoming Departme nt of Environmental Quality—Air Quality

Division (WDEQ-AQD), CH2M HILL followed the methodology spelled out in the

WDEQ-AQD BART Modeling Protocol, a copy of which is included in this report as

Appendix B.

CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to the

large extent of the domain. The latitude of the projection orig in and the longitude of the

central meridian were chosen at the approxima te center of the domain. Standard parallels

were drawn to represent one-six th and five-sixths of the north -south extent of the domain to

minimize distortion in the north-south direction.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 4-1Badlands NPWind Cave NPIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinLEGEND300 KilometersClass I AreasCALMET DomainStandard Parallels0 100 200 300KilometersFigure 4-1Dave Johnston Source-SpecificClass I Areas to be AddressedStandard Parallel 1: 40 12' 2.30"Standard Parallel 2: 45 14' 28.09"Domain Dimensions 1060 x 780 KM114° 5' 20.40" Longitude39° 3' 53.37" Latitude100° 56' 34.08" Longitude45° 51' 57.22" Latitude101° 54' 25.88" Longitude38° 54' 0.04" Latitude114° 28' 37.96" Longitude46° 6' 26.20" LatitudeDave JohnstonSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\DAVE_JOHNSON_CLASSI.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# The default technical options listed in TRC Companies, In c.’s (TRC) current example

CALMET.inp file were used for CALMET. Verti cal resolution of the wind field included ten

layers, with vertical face hei ghts as follows (in meters):

• 0, 20, 40, 100, 140, 320, 580, 1020, 1480, 2220, 3500

Other user-specified model options were se t to values established by WDEQ-AQD, which

appear in Table 3 of Appendix B. Table 4-1 lists the key user-sp ecified options used for this

analysis.

TABLE 4-1



# User-specified CALMET Options

Dave Johnston 3

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500



# 4.2.2 CALMET Input Data

CH2M HILL ran the CALMET model to pr oduce 3 years of analysis: 2001, 2002, and 2003.

WDEQ-AQD provided 12-kilomete r resolution Mesoscale Meteor ological Model, Version 5

(MM5) meteorological data fi elds that covered the entire modeling domain for each study

year.

These three data sets were chosen because th ey are current and have been evaluated for

quality. The MM5 data were used as input to CALMET as the “initial guess” wind field. The

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

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# 4-4 

# initial guess wind field was adjusted by CALMET for local terrain and land use effects to

generate a Step 1 wind field, and further refine d using local surface observations to create a

final Step 2 wind field.

Surface data for 2001 through 2003 were obtained from the National Climatic Data Center.

CH2M HILL processed the data from the Na tional Weather Service’s Automated Surface

Observing System network for all stations that are in the domain. The surface data were

obtained in abbreviated DATSAV3 format. A conversion routine avai lable from the TRC

Web site was used to convert the DATSAV3 files to CD-144 format for input into the

SMERGE preprocessor and CALMET.

Land use and terrain data were obtained from the United States Geological Survey (USGS).

Land use data were obtained in Composite Theme Grid format from the USGS, and the

Level 1 USGS land use categories were mapped into the 14 primary CALMET land use

categories. Surface properties such as albedo, Bowen ratio, roughness length, and leaf area

index were computed from the land use values. Terrain data were taken from USGS 1-degree

Digital Elevation Model data, which pr imarily derive from USGS 1:250,000 scale

topographic maps. Missing land use data were filled with values that were assumed

appropriate for the missing area.

Precipitation data were ordered from the National Climatic Data Center. All available data in

fixed-length, TD-3240 format were ordered fo r the modeling domain. The list of available

stations that have collected complete data varies by year, but CH2M HILL processed all

available stations/data within the domain for each year. Precipitation data were prepared with

the PXTRACT/PMERGE processors in preparation for use within CALMET.

Upper-air data were prepared for the CALM ET model with the READ62 preprocessor for the

following stations:

• Denver, Colorado

• Salt Lake City, Utah

• Riverton, Wyoming

• Rapid City, South Dakota

Figure 4-2 shows the locations of surface and upper air stations within the MM5 modeling

domain.Badlands NPWind Cave NPRAP (UA)P60WRLTORSHRRKSRIW (UA)RWLLARLNDGEYGCCEVWDGWCYSCPRBYGBPIVELSLC (UA)PUCOGDLGUDLNRXEPIHIDALLJBYIRILEEOLICLXVGJTDEN (UA)APACAGITRASEAKOIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinIENPHPD072WXSNYBFFCDRAIALVMDLNBTMBZNBILLEGENDClass I AreasCALMET DomainASOS Surface StationsUpper Air Station0 100 200 300KilometersFigure 4-2Surface and Upper Air Stations Used in theDave Johnston BART AnalysisStandard Parallel 1: 40 12' 2.30"Standard Parallel 2: 45 14' 28.09"Domain Dimensions 1060 x 780 KM114° 5' 20.40" Longitude39° 3' 53.37" Latitude100° 56' 34.08" Longitude45° 51' 57.22" Latitude101° 54' 25.88" Longitude38° 54' 0.04" Latitude114° 28' 37.96" Longitude46° 6' 26.20" LatitudeDave JohnstonSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\DAVE_JOHNSTON_ASOS.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# 4.2.3 Validation of CALMET Wind Field

CH2M HILL used the CALDESK data display and analysis system (v2.97, Enviromodeling

Ltd.) to view plots of wind vectors and other meteorological parameters to evaluate the

CALMET wind fields. The CALDESK displays were compared to observed weather

conditions, as depicted in surface and upper-a ir weather maps (National Oceanic and

Atmospheric Administration, 2006).



# 4.3 CALPUFF Modeling Approach

For the BART control technology visibility improvement modeling, CH2M HILL followed

WDEQ-AQD guidance provided (WDEQ-AQD, 2006).

CH2M HILL drove the CALPUFF model with the meteorological output from CALMET

over the modeling domain described earlier. The CALPUFF model wa s used to predict

visibility impacts for the pre- control (baseline) scenario fo r comparison to the predicted

impacts for post-control scen arios for Dave Johnston 3.



# 4.3.1 Background Ozone and Ammonia

Hourly values of background ozone concen trations were used by CALPUFF for the

calculation of SO 2 

# and NO

x 

# transformation with the MESOPUFF II chemical transformation

scheme. CH2M HILL obtained hourly ozone data from the following stations located within

the modeling domain for 2001, 2002, and 2003:

• Rocky Mountain National Park, Colorado

• Craters of the Moon National Park, Idaho

• Highland, Utah

• Thunder Basin National Grasslands, Wyoming

• Yellowstone National Park, Wyoming

• Centennial, Wyoming

• Pinedale, Wyoming

For periods of missing hourly ozone data, the chemical transformation relied on a monthly

default value of 44 parts per billion. Background a mmonia was set to 2 parts per billion. Both

of these background values were taken from the guidance document (WDEQ-AQD, 2006).



# 4.3.2 Stack Parameters

The stack parameters used for the baseline m odeling reflect those that are in place under the

current permit for Dave Johnston 3. Post-contro l stack parameters re flect the anticipated

changes associated with insta llation of the control technology alternativ es that are being

evaluated. The maximum heat input rate of 2,500 MMBtu per hour was used to calculate a

maximum emission rate for the baseline. This heat input is based on a permit limit. Upon

installation of control devices, it is assumed that the perm it limit would be removed, and the

new maximum heat input rate would be 2,800 MMB tu per hour. It is un clear whether this

change will require a modificat ion of the applicable Title V Permit. Maximum emission rates

for all four scenarios assumed a maximum heat input rate of 2,800 MMBtu per hour. Measured

velocities and stack flow rates were used in the modeling to represen t a worst-case situation.

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

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# 4-7 

# 4.3.3 Emission Rates

Pre-control emission rates for Dave Johnston 3 reflect peak 24-hour average emissions that

may occur under the source’s current permit. Th e emission rates reflect actual emissions

under normal operating conditions, as described by the EPA in the Regional Haze

Regulations and Guidelines for Best Availabl e Retrofit Technology De terminations; Final

Rule (40 CFR Part 51).

CH2M HILL used available continuous emissi on monitoring data to determine peak 24-hour

emission rates. Data reflected operations from the most recent 3- to 5-year period, unless a

more recent period was more representative. Allowable short-term (24-hour or shorter

period) emissions or short-term emission limits were used if continuous emission monitoring

data were not available.

Emissions were modeled for the following pollutants:

• SO 2



# • NO

x



# • Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• Fine particulate (diameter<PM 2.5 

# )

• Sulfates

Post-control emission rates reflect the effect s of the emissions control scenario under

consideration. Modeled pollutants were the same as those listed for the pre-control scenario.



# 4.3.4 Post-control Scenarios

Four post-control modeling scenarios were develo ped to cover the range of effectiveness for

the combination of the individual NO

x 

# , SO 2 

# , and PM control technol ogies being evaluated.

The selection of each control device was made based on the engineering analyses described

in Section 3 for reasonable technologies that would meet or exceed the presumptive BART

levels for each pollutant.

• Scenario 1 : New LNBs with OFA system, dry F GD system, and the existing ESP. As

indicated previously, this scenario re presents CH2M HILL’s preliminary BART

recommendation.

• Scenario 2 : New LNBs with OFA system, dry FGD system, and the replacement of the

ESP with a fabric filter downstr eam of the lime spray dryer.

• Scenario 3 : New LNB with OFA and SCR, dry F GD system, and the replacement of the

ESP with a fabric filter downst ream of the lime spray dryer.

• Scenario 4 : New LNB with OFA and SCR, we t FGD system and new stack, and

maintaining the existing ESP.

Table 4-2 presents the stack parameters and emission rates used for the Dave Johnston 3

analysis for baseline and post-control m odeling. In accordance with the WDEQ BART

modeling protocol, elemental car bon stack emissions and organic aerosol emissions were not

modeled.TABLE 4-2BART Model Input DataDave Johnston 3BaselinePost-control Scenario 1Post-control Scenario2 Post-control Scenario 3Post-control Scenario 4Model Input DataCurrent Operation withElectrostatic Precipitator(ESP)Low-NOxBurners (LNBs) with Over-fireAir (OFA), Dry Flue Gas Desulfurization(FGD), Existing ESPLNB with OFA, Dry FGD,New Fabric FilterLNB with OFA and SelectiveCatalytic Reduction (SCR), DryFGD, New Fabric FilterLNB with OFA and SCR, Wet FGD,Existing ESP, New StackSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr]) 3,000 616 336 336 162Nitrogen Oxide (NOx) Stack Emissions (lb/hr)1,750672672196196PM10Stack Emissions (lb/hr) 75.0 84.0 42.0 42.0 75.0Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)32.3 32.3 23.9 23.9 32.3Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)42.8 42.8 18.1 18.1 42.8Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 46.0 2.58 2.58 3.64 43.9H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 45.1 2.52 2.52 3.57 43.1Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)0.673.30(NH4)2SO4as SO4Stack Emissions (lb/hr)0.492.40(NH4)HSO4Stack Emissions (lb/hr)1.125.77(NH4)HSO4as SO4Stack Emissions (lb/hr)0.934.82Total Sulfate (SO4) (lb/hr)45.12.52 2.52 5.0 50.3Stack ConditionsStack Height (meters)152.4 152.4 152.4 152.4 152.4Stack Exit Diameter (meters) 4.574.574.574.574.57Stack Exit Temperature (Kelvin)445350355355322Stack Exit Velocity (meters persecond)32.025.1 25.5 25.5 16.7NOTES:(a)Based on AP-42, Table 1.1-6, the coarse particulates are countedas a percentage of PM10. This equates to 43 percent ESP and 57 percent Baghouse. PM10and PM2.5refer to particulate matter less than 10 and 2.5micrometers, respectively, in aerodynamicdiameter.(b)Based on AP-42, Table 1.1-6, the fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent Baghouse.Total Sulfate (SO4) (lb/hr) = H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4as SO4Stack Emissions (lb/hr) + (NH4)HSO4as SO4Stack Emissions (lb/hr)

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# 4.3.5 Modeling Process

The CALPUFF modeling for the control tec hnology options for Unit 3 followed this

sequence:

• Model pre-control (baseline) emissions

• Model preferred post-control scenario (if applicable)

• Determine degree of visibility improvement

• Model other control scenarios

• Determine degree of visibility improvement

• Factor visibility results into the BART five-step evaluation



# 4.3.6 Receptor Grids

Discrete receptors for the CALPUFF modeli ng were placed at uniform receptor spacing

along the boundary and in the interior of each ar ea of concern. Class I area receptors were

taken from the National Park Service database for Class I area modeling receptors. The TRC

COORDS program was used to convert all latitude/longitude coordinates to Lambert

Conformal Conic coordinates, including rece ptors, meteorological stations, and source

locations.



# 4.4 CALPOST

The CALPOST processor was used to determin e 24-hour average visibility results with

output specified in dV units. Calculations of light extinction were made for each pollutant

modeled. The sum of all extinction values were used to calculate the delta-dV ( Δ dV) change

relative to natural background. The following default extinction coefficients for each

pollutant were used:

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 

# ) 0.6

• PM fine (PM 2.5 

# ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0

CALPOST visibility Method 6 was used to determine the visibil ity impacts. Monthly relative

humidity factors [ f (RH)] were used in the light extinc tion calculations to account for the

hygroscopic characteristics of nitrate and sulf ate particles. Table 5 of the Wyoming BART

Air Modeling Protocol (Appe ndix B) lists the monthly f (RH) factors for the Class I areas.

These values were used for the pa rticular Class I area being modeled.

The natural background conditions as a reference for determining the Δ dV change

represented the 20 percent best natural visi bility days. The EPA BART guidance document

provided deciview values for the 10 percent best days for each Class I area, but did not

provide individual species concentration data for the 20 percent best background conditions.

Species concentrations corresponding to the 20 pe rcent best days were calculated for each

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# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

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# 4-10 

# Class I area by scaling back the annual average species concentrations given in Table 2-1 of

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule (EPA,

2003). A separate scaling factor was derived fo r each Class I area such that, when multiplied

by the guidance table annual concen trations, the 20 percent best da ys dV value for that area

would be calculated. This procedure was taken from Protocol for BART-Related Visibility

Improvement Modeling Analysis in North Dakota (North Dakota Department of Health,

2005). However, the Wyoming BART Air Mode ling Protocol (see Appendix B) provided

natural background concentrations of aerosol components to use in the BART analysis.

Table 4-3 lists the annual average species concentrations from the BART protocol.

TABLE 4-3



# Average Natural Levels of Aerosol Components

Dave Johnston 3

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Wind Cave NP and Badlands NP Class I Areas

Ammonium Sulfate 0.047

Ammonium Nitrate 0.040

Organic Carbon 0.186

Elemental Carbon 0.008

Soil 0.198

Coarse Mass 1.191

NOTE:

Data in this table was taken from Table 6 of the Wyoming BART Air Modeling Protocol



# 4.5 Presentation of Modeling Results

This section presents the resu lts of the CALPUFF visibility improvement modeling analysis

for Dave Johnston 3.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Dave Johnston 3 for the ba seline and four post-control scenarios. The

post-control scenarios included emission rates for SO 2 

# , NO

x 

# , and PM 10 

# that would be

achieved if BART state- of-the-art technology were installed on Unit 3.

Baseline (and post-control) 98 th 

# percentile results were greater than 0.5 Δ dV for both the

Badlands NP and Wind Cave NP modeled Class I areas. The 98 th 

# percentile results for each

Class I area are presented in Table 4-4.BART ANALYSIS FOR DAVE JOHNSTON UNIT 3TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasDave Johnston 3ModelingResultsScenarioTotal FirstYearAnnualizedCostClass I AreaHighestDeltaDeciview(ΔdV)98thPercentileDelta-Deciview(ΔdV)Number (No.) ofDays Above0.5 dVCost per dVReductionCost per Reductionin No. of Days Above0.5 dVIncremental Costper dV ReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2001Badlands4.2021.63559----Baseline: Current Operation withElectrostatic Precipitator (ESP)Wind Cave5.1911.59757----$15,149,158Badlands1.3430.4777$13,082,174$291,330Scenario 1: Low-NOxBurners (LNBs) with Over-fire Air (OFA), dry FlueGas Desulfurization (FGD), existing ESP$15,149,158Wind Cave1.8710.56710$14,707,920$322,323$20,400,821Badlands1.1010.3786$16,229,770$384,921$53,047,101$5,251,663Scenario 2: LNB with OFA,dry FGD, fabric filter$20,400,821Wind Cave1.5290.4815$18,280,306$392,323$61,065,849$1,050,333$28,530,147Badlands0.5630.2081$19,993,095$491,899$47,819,565$1,625,865Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR),dry FGD, fabric filter$28,530,147Wind Cave0.7940.2131$20,614,268$509,467$30,333,306$2,032,332$29,761,524Badlands0.5670.2533$21,535,111$531,456NANAScenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack$29,761,524Wind Cave0.7640.2691$22,410,786$531,456NANA2002Badlands2.6061.17637----Baseline: Current Operation with ESPWind Cave2.4661.80643----$15,149,158Badlands0.6450.3514$18,362,616$459,065Scenario 1: LNB with OFA, dry FGD, existing ESP$15,149,158Wind Cave1.010.4887$11,494,050$420,810$20,400,821Badlands0.4960.3050$23,422,297$551,374$114,166,587$1,312,916Scenario 2: LNB with OFA,dry FGD, fabric filter$20,400,821Wind Cave0.8660.4045$14,551,228$536,864$62,519,798$2,625,832$28,530,147Badlands0.2760.1430$27,618,729$771,085$50,181,025NAScenario 3: LNB with OFA and SCR, dry FGD, fabric filter$28,530,147Wind Cave0.3820.2110$17,887,239$663,492$42,120,860$1,625,865$29,761,524Badlands0.2770.1550$29,149,387$804,366NANAScenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack$29,761,524Wind Cave0.4580.2050$18,589,334$692,128$205,229,500NA2003Badlands3.0911.65247----Baseline: Current Operation with ESPWind Cave4.8672.40249----$15,149,158Badlands0.8480.4787$12,903,882$378,729Scenario 1: LNB with OFA, dry FGD, existing ESP$15,149,158Wind Cave1.5520.74811$9,159,104$398,662$20,400,821Badlands0.6670.4013$16,307,611$463,655$68,203,416$1,312,916Scenario 2: LNB with OFA,dry FGD, fabric filter$20,400,821Wind Cave1.2550.62410$11,474,028$523,098$42,352,121$5,251,663$28,530,147Badlands0.3660.1880$19,487,805$607,024$38,165,850$2,709,775Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$28,530,147Wind Cave0.6630.3051$13,605,220$594,378$25,483,781$903,258$29,761,524Badlands0.340.2330$20,973,590$633,224NANAScenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack$29,761,524Wind Cave0.6140.3121$14,239,964$620,032NANAJMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC4-11BART ANALYSIS FOR DAVE JOHNSTON UNIT 3JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC4-12TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasDave Johnston 3ModelingResultsScenarioTotal FirstYearAnnualizedCostClass I AreaHighestDeltaDeciview(ΔdV)98thPercentileDelta-Deciview(ΔdV)Number (No.) ofDays Above0.5 dVCost per dVReductionCost per Reductionin No. of Days Above0.5 dVIncremental Costper dV ReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV3-Year AveragesBadlands1.48847.7Baseline: Current Operation with ESPWind Cave1.93549.7$15,149,158Badlands0.4356.0$14,395,779$363,580Scenario 1: LNB with OFA, dry FGD, existing ESP$15,149,158Wind Cave0.6019.3$11,356,190$375,599$20,400,821Badlands0.3613.0$18,112,596$456,735$70,968,419$1,750,554Scenario 2: LNB with OFA,dry FGD, fabric filter$20,400,821Wind Cave0.5036.7$14,246,383$474,438$53,588,398$1,969,374$28,530,147Badlands0.1800.3$21,812,039$602,750$44,748,583$3,048,497Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$28,530,147Wind Cave0.2430.7$16,861,789$582,248$31,266,638$1,354,888$29,761,524Badlands0.2141.0$23,360,694$637,747NANAScenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack$29,761,524Wind Cave0.2620.7$17,789,315$607,378NANANOTES:Sample Calculations: Cost per dV Reduction for Scenario1 for 2001: = $15,149,158 / (1.635 - 0.477) = $13,082,174Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $15,149,158 / (59 - 7) = $291,330

# 5.0 Preliminary Assessment and

Recommendations

As a result of the completed technical and ec onomic evaluation, and in consideration of the

modeling analysis completed for Dave Johns ton 3, the preliminary recommended BART

controls for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# New LNBs and OFA system for NO

x 

# control

• 

# Lime spray dryer FGD for SO 2 

# control

• 

# Maintain the existing ESP for PM control

These recommendations were identified as Scenar io 1 for the modeling analysis described in

Section 4. Visibility improvements for all emi ssion control scenarios we re analyzed, and the

results are compared below, utilizing a least-cost envelope, as outlined in the New Source

Review Workshop Manual (EPA, 1990, hereafter referred to as NSR Manual).



# 5.1 Least-cost Envelope Analysis

The total annualized cost, cost per dV reduction, and cost per reduction in number of days

above 0.5 dV for the scenarios modeled in Se ction 4 to determine the impact on the two

Class I areas are listed in Tables 5-1 thr ough 5-3. A comparison of the incremental costs

between relevant scenarios is shown in Tables 5-4 through 5-6. The total annualized cost

versus number of days above 0.5 dV, and the total annualized cost versus 98 th 

# percentile Δ dV

reduction are shown in Figures 5-1 to 5-6 for the two Class I areas.



# 5.1.1 Analysis Methodology

On page B-41 of the New Source Review Ma nual, the EPA states that “Incremental

cost-effectiveness comparisons should focu s on annualized cost and emission reduction

differences between dominant alternatives. Dominant set of control alternatives are

determined by generating what is called the envelope of least- cost alternatives. This is a

graphical plot of total annua lized costs for a total emissions reductions for all control

alternatives identified in the BACT analysis...”

An analysis of incremental cost effectiv eness has been conducted. This analysis was

performed in the following way. First, the cont rol option scenarios are ranked in ascending

order of annualized total costs as show n in Tables 5-1 and 5-2. The incremental

cost-effectiveness data, expressed per day and per dV reduction, represents a comparison of

the different scenarios, and is summarized in Tables 5-3 and 5-4 for each of the two Class I

areas. Then the most reasonable smooth curve of least-cost control opti on scenarios is plotted

for each analysis. Figures 5-1 through 5-4 pres ent the two analyses (cost per dV reduction

and cost per reduction in number of days a bove 0.5 dV) for each of the two Class I areas

impacted by the operation of Dave Johnston 3.

In Figure 5-1, the four scenarios are compared as a graph of total annualized cost versus

number of days above 0.5 dV. EPA states that “In calculating incrementa l costs, the analysis

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 5-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# should only be conducted for control options th at are dominant among all possible options.”

In Figure 5-1, the dominant set of control options , Scenarios 1 and 3, represent the least-cost

envelope depicted by the curvilinear line conn ecting them. Scenarios 2 and 4 are inferior

options and should not be considered in the de rivation of incremental cost effectiveness.

Scenarios 2 and 4 represent infe rior controls because Scenario 1 provides approximately the

same amount of visibility impact reduction fo r less cost than Scen ario 2, and similarly,

Scenario 3 provides approximately the same am ount of visibility impact reduction for less

cost than Scenario 4. The incremental cost e ffectiveness is determined by the difference in

total annual costs betwee n two contiguous scenarios divided by the difference in emissions

reduction.

TABLE 5-1



# Badlands Class I Agent Control Data

Dave Johnston 3

Scenario Controls 98 th



# Percentile

deciView

(dV)

Reduction Reduction

in Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualized

Cost

(Million$) Cost per

dV

Reduction

(Million$/dV

Reduced) Cost per

Reduction

in No. of

Days Above

0.5 dV

(Million$/

Day

Reduced)

Base Current Operation with

Electrostatic Precipitator

(ESP) 0.00 0.0 $0.0 $0.0 $0.0

1 Low-NO

x

# Burners (LNBs)

with Over-fire Air (OFA),

Dry Flue Gas

Desulfurization (FGD),

Existing ESP 1.05 41.7 $15. 1 $14.4 $0.4

2 LNB with OFA, Dry FGD,

New Fabric Filter 1.13 44.7 $20. 4 $18.1 $0.5

3 LNB with OFA and

Selective Catalytic

Reduction (SCR), Dry

FGD, New Fabric Filter 1.31 47.3 $28. 5 $21.8 $0.6

4 LNB with OFA and SCR,

Wet FGD, Existing ESP,

New Stack 1.27 46.7 $29. 8 $23.4 $0.6

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# 5-2

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# TABLE 5-2



# Wind Caves Class I Area Control Data

Dave Johnston 3

Scenario Controls 98 th



# Percentile

deciView

(dV)

Reduction Reduction

in Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualized

Cost

(Million$) Cost per dV

Reduction

(Million$/dV

Reduced) Cost per

Reduction in

No. of Days

Above 0.5 dV

(Million$/Day

Reduced)

Base Current Operation with

Electrostatic Precipitator

(ESP) 0.00 0.0 $0.0 $0.0 $0.0

1 Low NO

x 

# Burners (LNBs)

with Over-fire Air (OFA),

Dry Flue Gas

Desulfurization (FGD),

Existing ESP 1.33 40.3 $15. 1 $11.4 $0.4

2 LNB with OFA, Dry FGD,

New Fabric Filter 1.43 43.0 $20. 4 $14.2 $0.5

3 LNB with OFA and

Selective Catalytic

Reduction (SCR), DRY

FGD, New Fabric Filter 1.69 49.0 $28. 5 $16.9 $0.6

4 LNB with OFA and SCR,

Wet FGD, Existing ESP,

New Stack 1.67 49.0 $29. 8 $17.8 $0.6

TABLE 5-3



# Badlands Class I Area Incremental Data

Dave Johnston 3

Options Compared Incremental

Reduction in

Days Above

0.5 deciView

(dV) (Days) Incremental dV

Reductions (dV) Incremental Cost

Effectiveness

(Million $/Days) Incremental Cost

Effectiveness

(Million $/dV)

Baseline and Scenario 1 41.7 1.05 $0.4 $14.4

Scenario 1 and Scenario 2 3.0 0.07 $1.8 $71.0

Scenario 1 and Scenario 3 5.7 0.26 $2.4 $52.3

Scenario 1 and Scenario 4 5.0 0.22 $2.9 $65.9

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# 5-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# TABLE 5-4



# Wind Caves Class I Agent Incremental Data

Dave Johnston 3

Options Compared Incremental

Reduction in

Days Above

0.5 deciView

(dV) (Days) Incremental dV

Reductions (dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 40.3 1.33 $0.4 $11.4

Scenario 1 and Scenario 2 2.7 0.10 $2.0 $53.6

Scenario 1 and Scenario 3 8.7 0.36 $1.5 $37.4

Scenario 1 and Scenario 4 8.7 0.34 $1.7 $43.1

FIGURE 5-1



# Least-cost Envelope Badlands Class I Area Days Reduction

Dave Johnston 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0

0 5 10 15 20 25 30 35 40 45 50



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



# JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 5-4

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# FIGURE 5-2



# Least-cost Envelope Badlands Class I Area 98 th



# Percentile Reduction

Dave Johnston 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0

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 $)



# FIGURE 5-3



# Least-cost Envelope Wind Caves Class I Area Days Reduction

Dave Johnston 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0

0 1 0 2 0 3 0 4 0 5 0



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



# 6 0



# JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 5-5

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# FIGURE 5-4



# Least-cost Envelope Badlands Class I Area 98 th



# Percentile Reduction

Dave Johnston 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0

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 $)



# 5.1.2 Analysis of Results

Results of the least-cost analysis, shown in Ta bles 5-1 to 5-4 and Figur es 5-1 to 5-4 on the

following pages, confirm the select ion of Scenario 1, based on incremental cost and visibility

improvements. Scenario 2 is elim inated because it is to the le ft of the curve formed by the

dominant control alternative scen arios in three of the four cat egories plotted, which indicates

a scenario with lower improvement and/or higher costs. Scenario 3 is not selected due to very

high incremental costs on the basis of both a cost per day of improvement and a cost per

deciview reduction. Scenario 4 is also not sel ected because it is to the left of the curve

formed by the dominant control alternative scenar ios in three of the f our categories plotted.

This placement to the left of the curve indica tes a scenario with lower improvement and/or

higher costs. While Scenario 4 provides some potential visibility advantage over Scenario 1,

the projected improvement is less than half a deciview, and the cost increment is excessive.

Analysis of the results for the Badlands NP Class I Area in Tables 5-1 and 5-3 and

Figures 5-1 and 5-2 illustrate s the conclusions stated above. The greatest reduction in

98 th 

# percentile dV and number of days above 0.5 dV is between the Baseline and Scenario 1.

For example, Table 5-3 shows that the incr emental cost effectiveness for Scenario 1

compared to the Baseline is reasonable at $0.4 million per day and $14.4 million per dV to

improve visibility at Badlands NP. Howeve r, the incremental cost effectiveness for

Scenario 2 compared to Scenario 1 is ex cessive at $1.8 million per day and $71.0 million per

dV. The incremental cost effectiveness for Scen ario 3 compared to Scenario 1 is equally

excessive at $2.4 million per day and $52.3 m illion per dV. Using Table 5-4, a similar

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 5-6

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3



# conclusion is reached for improving visibility at Wind Caves NP. Therefore, EPA’s least-cost

analysis confirms that Scenario 1 represen ts the proper BART control technology for Dave

Johnston 3 because the incremental cost effectiven ess if Scenario 2 were chosen compared to

Scenario 1 is excessive. Note the least-cost e nvelope analysis shows that Scenario 2 should

be eliminated. Elimination of Scenario 2 is just ified because it is to the left of the curve

formed by the dominant control alternative scenar ios in three of the f our categories plotted.

This indicates a scenario with lowe r improvement and/or higher costs.



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by EPA for wall-fired cell burner boilers

combusting sub-bituminous coal is 0.45 lb per MMBtu. The Dave Johnston 3 plant burns

only PRB coal, a sub-bituminous coal.

CH2M HILL recommends the addition of LNBs with OFA system as BART for

Dave Johnston 3, based on the projec ted significant reduction in NO

x 

# emissions, reasonable

control costs, and the advantages of no a dditional power requireme nts or non-air quality

environmental impacts. This approach is projected to meet the BART presumptive NO

x 

# limit

of 0.45 lb per MMBtu.



# 5.2.2 SO 2 

# Emission Control

CH2M HILL recommends a new dry FGD syst em as BART for Dave Johnston 3, based on

the significant reduction in SO 2 

# emissions, reasonable control co sts, and the advantages of no

additional power requirements and minimal non- air quality environmental impacts. Although

this approach is projected to not meet the BART presumptive SO 2 

# limit of 0.15 lb per

MMBtu, the incremental cost effectiveness if Scenario 2 were chosen compared to

Scenario 1 is excessive.



# 5.2.3 PM 10



# Emission Control

CH2M HILL recommends maintaining the ex isting ESP as BART for Dave Johnston 3,

based on the significant reduction in PM 10 

# emissions, reasonable control costs, and the

advantages of minor additional power requirements and no non-air quality environmental

impacts.



# 5.3 Just-Noticeable Differences in Atmospheric Haze

Conclusions reached in the reference document “Just-Noticeable Differences in Atmospheric

Haze” (Henry, 2002), state that only deciview differences of approximately 1.5 to

2.0 deciviews or more are perceivable by the human eye. Deciview changes of less than

1.5 dV cannot be distinguished by the average person. Therefore, the modeling analysis

results indicate that only minima l, if any, visibility improvement s at the Class I areas studied

would be expected under any of the scenarios. Thus the results indi cate that even though

many millions of dollars will be spent, only minimal visibility improvements may result.

Finally, it should be noted that none of the data were corrected for natural obscuration.

During the period of 2001 through 2003, there were several mega-wildfires that lasted for

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# 5-7

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 3

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 5-8 

# many days and could have had a significant im pact on visibility in these Class I areas. If

natural obscuration were to reduce the visibi lity impacts modeled for the Dave Johnston 3

facility, it would increase the costs per deciview reduction that are pres ented in this report.

# 6.0 References

40 CFR Part 51. Regional Haze Regulations and Guide lines for Best Available Retrofit

Technology Determinations; Final Rule. July 6, 2005.

Energy Information Administration, 2006. Official Energy Statistics from the U.S.

Government: Coal. http://www.eia.doe.gov/fuelcoal.html. Accessed October 2006

.

EPA, 1990. New Source Review Workshop Manual—Prevention of Significant Deterioration

and Nonattainment Area Permitting . Draft. October 1990.

EPA, 2003. Guidance for Estimating Natural Visibil ity Conditions Under the Regional Haze

Rule . Environmental Protection Agency. EPA-454/8-03-005. September 2003.

Henry, Ronald, 2002. “Just-Noticeable Di fferences in Atmospheric Haze,” Journal of the Air

& Waste Management Association. Volume 52, p. 1238.

National Oceanic and Atmospheric Administra tion, 2006. U.S. Daily Weather Maps Project.

http://docs.lib.noaa.gov/rescue/dwm/d ata_rescue_daily_weather_maps.html

. Accessed October 2006.

North Dakota Department of Health, 2005. Protocol for BART-Related Visibility

Improvement Modeling Analysis in North Dakota . North Dakota Department of

Health. October 26, 2005.

Sargent & Lundy, 2002. Multi-Pollutant Control Report. October 2002.

Sargent & Lundy, 2006. Multi-Pollutant Control Report. Revised. October 2006.

WDEQ-AQD, 2006. BART Air Modeling Protocol—Individu al Source Visibility Assessments

for BART Control Analyses . Wyoming Department of Environmental Quality – Air

Quality Division. September 2006.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 

# 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios1Index No. Name of Unit1 Dave Johnston Unit 32 Dave Johnston Unit 43 Jim Bridger Unit 14 Jim Bridger Unit 25 Jim Bridger Unit 36 Jim Bridger Unit 47 Naughton Unit 18 Naughton Unit 29 Naughton Unit 310 Wyodak Unit 1Scenario First Year Cost ScenarioFirst YearCost Scenario First Year Cost Scenario First Year Cost Scenario First Year Cost$ 15,149,158 N/A N/A N/A N/A$ 15,149,158 N/A N/A N/A N/A$ 20,400,821 N/A N/A N/A N/A$ 20,400,821 N/A N/A N/A N/A$ 28,530,147 N/A N/A N/A N/A$ 28,530,147 N/A N/A N/A N/A$ 29,761,524 N/A N/A N/A N/A$ 29,761,524 N/A N/A N/A N/AScenario First Year Cost Scenario First Year Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/AN/A N/A N/A N/AN/AN/A N/A N/A N/AN/A N/A N/A N/AN/AN/AN/A N/A N/A N/AN/A N/A N/A N/AN/AN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 1 - LNB with OFA, DryFGD, Fabric FilterBaseline - Current Operation withESPScenario 1 - LNB with OFA, DryFGD, Existing ESPScenario 2 - LNB with OFA, DryFGD, New Fabric FilterJim BridgerSelect Unit:Scenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterDJ Unit 4Scenario 4 - LNB with OFA andSCR, Wet FGD, Existing ESP,New StackDave JohnstonDJ Unit 3Baseline - Current Operation withVenturi ScrubberJB Unit 1 JB Unit 2 JB Unit 3 JB Unit 4Baseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, Fabric FilterScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPNaughtonScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterBaseline - Current Operation withESPBaseline - Current Operation withESPBaseline - Current Operation with WetFGD and ESPNTN Unit 1 NTN Unit 2 NTN Unit 3Scenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA, Wet FGD,New Fabric FilterScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, Wet FGD,ESPScenario 4 - LNB with OFA and SCR, WetFGD, Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA and SCR, WetFGD, ESPScenario 4 - LNB with OFA and SCR, WetFGD, ESPDave Johnston Unit 3Scenario 3 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 2 - LNB with OFA, Dry FGD,Fabric FilterScenario 1 - LNB with OFA, Dry FGD,ESPBaseline - Current Operation with DryFGD, ESPWDK Unit 1WyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 1ECONOMIC ANALYSIS SUMMARYDave Johnston Unit 3Boiler Design: 3-Cell Burner, Opposed Wall-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESPDry FGDw/Fabric FilterWet FGDw/ESPFabric FilterCase1 2 3 4 5 6 7 8 10NOx Emission Control SystemNone LNB w/OFA ROFALNB w/OFA &SNCRLNB w/OFA &SCR None None None NoneSO2 Emission Control SystemNone None None None None Dry FGD w/ESP Dry FGD w/Fabric Filter Wet FGD w/ESP NonePM Emission Control SystemESP ESP ESP ESP ESP ESP ESP ESP Fabric FilterTOTAL INSTALLED CAPITAL COST ($)0 15,900,001 12,054,022 24,035,544 83,301,164 91,499,734 138,999,942 144,300,464 29,795,555FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 506,128 506,128 809,804 0Maintenance Material ($) 0 40,000 60,000 98,000 155,000 714,175 714,175 1,182,587 45,016Maintenance Labor ($) 0 60,000 90,000 147,000 232,500 476,928 476,928 788,391 67,524Administrative Labor ($) 0 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 100,000 150,000 245,000 387,500 1,697,231 1,697,231 2,780,782 112,540Makeup Water Cost 0 0 0 0 0 99,566 99,566 132,371 0Reagent Cost 0 0 0 665,287 426,024 1,351,845 1,351,845 1,134,609 0SCR Catalyst / FF Bag Cost 0 0 0 0 384,000 0 151,563 0 151,563Waste Disposal Cost 0 0 0 0 0 701,072 735,825 884,924 0Electric Power Cost 0 0 1,087,633 90,666 620,077 982,741 1,529,496 1,359,990 545,179TOTAL VARIABLE O&M COST0 0 1,087,633 755,953 1,430,101 3,135,224 3,868,295 3,511,894 696,741TOTAL FIRST YEAR O&M COST 0 100,000 1,237,633 1,000,953 1,817,601 4,832,455 5,565,526 6,292,676 809,282FIRST YEAR DEBT SERVICE ($)0 1,512,533 1,146,673 2,286,449 7,924,258 8,704,171 13,222,762 13,726,989 2,834,386TOTAL FIRST YEAR COST ($)0 1,612,533 2,384,306 3,287,402 9,741,859 13,536,625 18,788,288 20,019,665 3,643,668Power Consumption (MW) 0.0 0.0 2.8 0.2 1.6 2.5 3.9 3.5 1.4Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 21.8 1.8 12.4 19.7 30.6 27.2 10.9CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0% 65.7% 72.9% 72.9% 90.0% 0.0% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 5,077 5,629 5,629 6,954 0 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 318 424 584 1,401 0 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 318 1,398 3,035 5,555 0 0 0 02-1 3-2 4-2 5-3SO2 Removal Rate (%)0.0% 0.0% 0.0% 0.0% 0.0% 81.7% 90.0% 95.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 10,817 11,920 12,583 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 1,251 1,576 1,591 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 1,251 4,758 1,859 06-1 7-6 8-7PM Removal Rate (%) 99.42% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 50.00%PM Removed (Tons/Yr) 0 0 0 0 0 0 0 0 166First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 0 0 22,008Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 0 0 22,00810-1PRESENT WORTH COST ($)0 17,121,787 27,175,244 36,265,039 105,508,343 150,541,955 206,998,725 221,183,453 39,683,240PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 1INPUT CALCULATIONSDave Johnston Unit 3Boiler Design:3-Cell Burner, Opposed Wall-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESPDry FGD w/FabricFilterWet FGDw/ESPFabric FilterCase1 2 3 4 5 6 7 8 10NOx Emission Control SystemNone LNB w/OFA ROFALNB w/OFA &SNCR LNB w/OFA & SCRNone None None NoneSO2 Emission Control SystemNoneNone None None NoneDry FGD w/ESP Dry FGD w/Fabric Filter Wet FGD w/ESPNonePM Emission Control SystemESPESP ESP ESP ESP ESP ESP ESPFabric FilterUnit Design and Coal CharacteristicsType of UnitPC PC PC PC PC PC PC PC PCNet Power Output (kW)223,214 250,000250,000 250,000 250,000 250,000 250,000 250,000 250,000Net Plant Heat Rate (Btu/kW-Hr)11,20011,200 11,200 11,200 11,200 11,200 11,200 11,200 11,200Boiler FuelDry Fork PRBDry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRBCoal Heating Value (Btu/Lb)7,7847,784 7,784 7,784 7,784 7,784 7,784 7,784 7,784Coal Sulfur Content (wt.%)0.47%0.47%0.47%0.47%0.47%0.47%0.47%0.468%0.47%Coal Ash Content (wt.%)5.01%5.01%5.01%5.01%5.01%5.01%5.01%5.01%5.01%Boiler Heat Input, each (MMBtu/Hr)2,500 2,800 2,800 2,800 2,800 2,800 2,800 2,800 2,800Coal Flow Rate (Lb/Hr)321,172 359,712 359,712 359,712 359,712 359,712 359,712 359,712 359,712(Ton/Yr)1,266,059 1,417,986 1,417,986 1,417,986 1,417,986 1,417,986 1,417,986 1,417,986 1,417,986(MMBtu/Yr)19,710,000 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200EmissionsUncontrolled SO2 (Lb/Hr)3,000 3,360 3,360 3,360 3,360 3,360 3,360 3,360 3,360(Lb/MMBtu)1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20(Lb Moles/Hr)46.83 52.45 52.45 52.45 52.45 52.45 52.45 52.45 52.45(Tons/Yr)11,826 13,245 13,245 13,245 13,245 13,245 13,245 13,245 13,245SO2 Removal Rate (%)0.0%0.0%0.0%0.0%0.0%81.7%90.0%95.0%0.0%(Lb/Hr)0 0 0 0 0 2,744 3,024 3,192 0(Ton/Yr)0 0 0 0 0 10,817 11,920 12,583 0SO2 Emission Rate (Lb/Hr)3,000 3,360 3,360 3,360 3,360 616 336 168 3,360(Lb/MMBtu)1.201.20 1.20 1.20 1.200.22 0.12 0.061.20(Ton/Yr)11,826 13,245 13,245 13,245 13,245 2,428 1,325 662 13,245Uncontrolled NOx (Lb/Hr)1,750 1,960 1,960 1,960 1,960 1,960 1,960 1,960 1,960(Lb/MMBtu)0.700.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70(Lb Moles/Hr)58.31 65.31 65.31 65.31 65.31 65.31 65.31 65.31 65.31(Tons/Yr)6,899 7,726 7,726 7,726 7,726 7,726 7,726 7,726 7,726NOx Removal Rate (%)0.0%65.7%72.9%72.9%90.0%0.0%0.0%0%0%(Lb/Hr)0 1,288 1,428 1,428 1,764 0 0 0 0(Lb Moles/Hr)0.00 42.92 47.58 47.58 58.78 0.00 0.00 0.00 0.00(Ton/Yr)0 5,077 5,629 5,629 6,954 0 0 0 0NOx Emission Rate (Lb/Hr)1,750 672 532 532 196 1,960 1,960 1,960 1,960(Lb/MMBtu)0.700.24 0.19 0.19 0.070.70 0.70 0.70 0.70(Ton/Yr)6,899 2,649 2,097 2,097 773 7,726 7,726 7,726 7,726Uncontrolled Fly Ash (Lb/Hr)12,873 84 84 84 84 84 84 84 84(Lb/MMBtu)5.149 0.030 0.030 0.030 0.030 0.030 0.030 0.030 0.030(Lb Moles/Hr)428.9 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8(Tons/Yr)50,744 331 331 331 331 331 331 331 331Fly Ash Removal Rate (%)99.42%0.00%0.00%0.00%0.00%0.00%0.00%0.00%50.00%(Lb/Hr)12,798 0 0 0 0 0 0 0 42(Ton/Yr)50,448 0 0 0 0 0 0 0 166Fly Ash Emission Rate (Lb/Hr)75 84 84 84 84 84 84 84 42(Lb/MMBtu)0.0300.030 0.030 0.030 0.030 0.030 0.030 0.0300.015(Ton/Yr)296 331 331 331 331 331 331 331 166ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 2LNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESPDry FGD w/FabricFilterWet FGDw/ESPFabric FilterCase1 2 3 4 5 6 7 8 10ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlGeneral Plant DataAnnual Operation (Hours/Year)7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884Annual On-Site Power Plant Capacity Factor0.900.90 0.90 0.90 0.90 0.90 0.90 0.90 0.90Economic FactorsInterest Rate (%)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%Plant Economic Life (Years)2020 20 20 20 20 20 20 20Installed Capital CostsNOx Emission Control System ($2006)015,900,001 12,054,022 24,035,54483,301,1640 000SO2 Emission Control System ($2006)00 0 0 0 91,499,734138,999,942 144,300,4640PM Emission Control System ($2006)00 0 0 0 0 0 0 29,795,555Total Emission Control Systems ($2006)0 15,900,001 12,054,022 24,035,54483,301,16491,499,734138,999,942 144,300,46429,795,555NOx Emission Control System ($/kW)0 64 48 96 333 0 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 366 556 577 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 0 119Total Emission Control Systems ($/kW)0 64 48 96 333 366 556 577 119Total Fixed Operating & Maintenance CostsOperating Labor ($)0 0 0 0 0 506,128 506,128 809,804 0Maintenance Material ($)0 40,000 60,000 98,000 155,000 714,175 714,175 1,182,587 45,016Maintenance Labor ($)0 60,000 90,000 147,000 232,500 476,928 476,928 788,391 67,524Administrative Labor ($)00000 0 0 0 0Total Fixed O&M Cost ($)0 100,000 150,000 245,000 387,500 1,697,231 1,697,231 2,780,782 112,540Annual Fixed O&M Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Water CostMakeup Water Usage (Gpm)0 0 0 0 0 173 173 230 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 99,566 99,566 132,371 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Lime Lime Lime NoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 91.25 91.25 91.25 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.046 0.046 0.046 0.000Molar Stoichiometry0.00 0.00 0.00 0.41 1.00 1.15 1.15 1.02 0.00Reagent Purity (Wt.%)100%100%100%100%100%90%90%90%90%Reagent Usage (Lb/Hr)0 0 0 456 270 3,758 3,758 3,154 0First Year Reagent Cost ($)0 0 0 665,287 426,024 1,351,845 1,351,845 1,134,609 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags Bags Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000128 0 1,457 0 1,457SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000104104 104 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 384,000 0 151,563 0 151,563Annual SCR Catalyst / Bag Cost Esc. Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr)0 0 0 0 0 7,309 7,671 9,226 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 701,072 735,825 884,924 0Annual Waste Disposal Cost Esc. Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Auxiliary Power CostAuxiliary Power Requirement (% of Plant Output)0.00%0.00%1.10%0.09%0.63%1.00%1.55%1.38%0.55%(MW)0.00 0.00 2.76 0.23 1.57 2.49 3.88 3.45 1.38Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 1,087,633 90,666 620,077 982,741 1,529,496 1,359,990 545,179Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls2 of 2Input TablesTable 1 - CasesExisting1 2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESP N/A Fabric Filter2 Dave Johnston Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/ADry FGD w/FabricFilterWet FGD w/FabricFilter N/A Fabric Filter3 Jim Bridger Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter4 Jim Bridger Unit 2Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter5 Jim Bridger Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter6 Jim Bridger Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter7 Naughton Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter8 Naughton Unit 2Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter9 Naughton Unit 3Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter10 Wyodak Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Upgraded Dry FGD N/A Wet FGDFlue GasConditioning Fabric FilterTable 2 - Unit Design and Coal CharacteristicsNOx SO2 PM Boiler DesignNet PowerOutput (kW)Net Plant HeatRate (Btu/kW-Hr) CoalHeating Value,HHV (Btu/Lb)Sulfur Content(Wt.%)AshContent(Wt.%)1 Dave Johnston Unit 3None None ESP3-Cell Burner, OpposedWall-Fired PC250,000 11,200Dry Fork PRB7,784 0.47% 5.01%2 Dave Johnston Unit 4Windbox Mods.Lime Added to VenturiScrubber Venturi Scrubber Tangential-Fired PC360,000 11,390Dry Fork PRB7,784 0.47% 5.01%3 Jim Bridger Unit 1LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%4 Jim Bridger Unit 2LNB - TFS 2000 Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%5 Jim Bridger Unit 3LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%6 Jim Bridger Unit 4LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%7 Naughton Unit 1None None ESP Tangential-Fired PC173,000 10,694Kemmerer Mine9,970 0.60% 4.64%8 Naughton Unit 2None None ESP Tangential-Fired PC226,000 10,574Kemmerer Mine9,970 0.60% 4.64%9 Naughton Unit 3LNCFS II LNB Wet FGD ESP Tangential-Fired PC356,000 10,336Kemmerer Mine9,970 0.60% 4.64%10 Wyodak Unit 1LNB Dry FGD ESP Opposed Wall-Fired PC335,000 12,087Clovis Point Mine7,977 0.65% 7.46%Coal QualityUnit DesignCurrent Emission Control SystemsIndex No. Name of UnitIndex No. Name of Unit | Case --->NOx Control SO2 Control PM ControlEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 5Table 3 - EmissionsControlledSO2 Controlled NOxControlledPM Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9 Case 101 Dave Johnston Unit 31.20 0.70 0.030 0.24 0.190.190.07 0.220.120.06N/A0.0152 Dave Johnston Unit 40.50 0.40 0.061 0.15 0.150.120.07 N/A0.150.10N/A0.0153 Jim Bridger Unit 10.27 0.45 0.045 0.24 0.220.200.07 N/AN/A0.100.030 0.0154 Jim Bridger Unit 20.27 0.24 0.074 0.24 0.220.200.07 N/AN/A0.100.030 0.0155 Jim Bridger Unit 30.27 0.45 0.057 0.24 0.220.200.07 N/AN/A0.100.030 0.0156 Jim Bridger Unit 40.17 0.45 0.030 0.24 0.220.200.07 N/AN/A0.100.030 0.0157 Naughton Unit 11.20 0.58 0.056 0.24 0.280.180.07 0.180.150.100.040 0.0158 Naughton Unit 21.20 0.54 0.064 0.24 0.280.180.07 0.180.150.100.040 0.0159 Naughton Unit 30.50 0.45 0.094 0.35 0.300.250.07 N/AN/A0.100.040 0.01510 Wyodak Unit 10.50 0.50 0.0300.230.220.180.070.25N/A0.100.025 0.015Table 4 - Case 1 O&M Costs (Current Operation)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None - -2 Dave Johnston Unit 4-$ -$ -$ $ - -None - -3 Jim Bridger Unit 1-$ -$ -$ $ - -None - -4 Jim Bridger Unit 2-$ -$ -$ $ - -None - -5 Jim Bridger Unit 3-$ -$ -$ $ - -None - -6 Jim Bridger Unit 4-$ -$ -$ $ - -None - -7 Naughton Unit 1-$ -$ -$ $ - -None - -8 Naughton Unit 2-$ -$ -$ $ - -None - -9 Naughton Unit 3-$ -$ -$ $ - -None - -10 Wyodak Unit 1-$ -$ -$$ --None--Table 5 - Case 2 O&M Costs (LNB w/OFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 40,000$ 60,000$ -$ -None - -2 Dave Johnston Unit 4-$ 36,000$ 54,000$ $ - -None - -3 Jim Bridger Unit 1-$ 28,000$ 42,000$ $ - -None - -4 Jim Bridger Unit 2-$ -$ -$ $ - -None - -5 Jim Bridger Unit 3-$ 28,000$ 42,000$ $ - -None - -6 Jim Bridger Unit 4-$ 28,000$ 42,000$ $ - -None - -7 Naughton Unit 1-$ 32,000$ 48,000$ $ - -None - -8 Naughton Unit 2-$ 32,000$ 48,000$ $ - -None - -9 Naughton Unit 3-$ -$ -$ $ - -None - -10 Wyodak Unit 1-$ 24,000$ 36,000$$ --None--SO2 Control Emission Rates (Lb/MMBtu)Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsPM Emission Rates (Lb/MMBtu)Index No. Name of UnitCurrent Emission Rates (Lb/MMBtu) NOx Control Emission Rates (Lb/MMBtu)Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls2 of 5Table 6 - Case 3 O&M Costs (Mobotec ROFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 60,000$ 90,000$ -$ -None - 2.762 Dave Johnston Unit 4-$ 54,000$ 81,000$ $ - -None - 4.333 Jim Bridger Unit 1-$ 42,000$ 63,000$ $ - -None - 6.414 Jim Bridger Unit 2-$ 42,000$ 63,000$ $ - -None - 6.415 Jim Bridger Unit 3-$ 42,000$ 63,000$ $ - -None - 6.416 Jim Bridger Unit 4-$ 42,000$ 63,000$ $ - -None - 6.417 Naughton Unit 1-$ 48,000$ 72,000$ $ - -None - 1.428 Naughton Unit 2-$ 48,000$ 72,000$ $ - -None - 2.619 Naughton Unit 3-$ 48,000$ 72,000$ $ - -None - 4.4710 Wyodak Unit 1-$ 36,000$ 54,000$$ --None-5.22Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 98,000$ 147,000$ -$ -Urea 0.41 0.232 Dave Johnston Unit 4-$ 105,000$ 157,500$ $ - -Urea 0.45 0.333 Jim Bridger Unit 1-$ 123,000$ 184,500$ $ - -Urea 0.45 0.534 Jim Bridger Unit 2-$ 95,000$ 142,500$ $ - -Urea 0.45 0.535 Jim Bridger Unit 3-$ 122,000$ 183,000$ $ - -Urea 0.45 0.526 Jim Bridger Unit 4-$ 123,000$ 184,500$ $ - -Urea 0.45 0.537 Naughton Unit 1-$ 83,000$ 124,500$ $ - -Urea 0.45 0.168 Naughton Unit 2-$ 93,000$ 139,500$ $ - -Urea 0.51 0.229 Naughton Unit 3-$ 75,000$ 112,500$ $ - -Urea 0.45 0.3310 Wyodak Unit 1-$ 93,000$ 139,500$--Urea0.450.34Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.AnnualSCRCatalyst Replace.(m3)Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 155,000$ 232,500$ -$ -Anhydrous NH31.00 1281.572 Dave Johnston Unit 4-$ 166,000$ 249,000$ $ - -Anhydrous NH31.00 1232.293 Jim Bridger Unit 1-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 1983.284 Jim Bridger Unit 2-$ 162,000$ 243,000$ $ - -Anhydrous NH31.00 1983.255 Jim Bridger Unit 3-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2003.226 Jim Bridger Unit 4-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2143.367 Naughton Unit 1-$ 132,000$ 198,000$ $ - -Anhydrous NH31.00 670.988 Naughton Unit 2-$ 160,000$ 240,000$ $ - -Anhydrous NH31.00 1011.349 Naughton Unit 3-$ 156,000$ 234,000$ $ - -Anhydrous NH31.00 1671.9910 Wyodak Unit 1-$ 181,000$ 271,500$$ --Anhydrous NH31.001602.42Annual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls3 of 5Table 9 - Case 6 O&M Costs (Dry FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 -2.492 Dave Johnston Unit 4-$ -$ -$ $ - -Lime- --3 Jim Bridger Unit 1-$ -$ -$ $ - -Lime- --4 Jim Bridger Unit 2-$ -$ -$ $ - -Lime- --5 Jim Bridger Unit 3-$ -$ -$ $ - -Lime- --6 Jim Bridger Unit 4-$ -$ -$ $ - -Lime- --7 Naughton Unit 1506,128$ 587,643$ 391,762$ $ - 120Lime1.40 -1.648 Naughton Unit 2506,128$ 860,174$ 573,044$ $ - 165Lime1.40 -2.259 Naughton Unit 3-$ -$ -$ $ - -Lime- --10 Wyodak Unit 1-$ 21,900$ 14,600$-25Lime1.10-0.11Table 10 - Case 7 O&M Costs (Dry FGD w/Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 1,4573.882 Dave Johnston Unit 4506,128$ 1,102,288$ 734,858$ $ - 248Lime1.10 1,7984.543 Jim Bridger Unit 1-$ -$ -$ $ - -Lime- --4 Jim Bridger Unit 2-$ -$ -$ $ - -Lime- --5 Jim Bridger Unit 3-$ -$ -$ $ - -Lime- --6 Jim Bridger Unit 4-$ -$ -$ $ - -Lime- --7 Naughton Unit 1506,128$ 632,660$ 459,286$ $ - 120Lime1.15 8652.668 Naughton Unit 2506,128$ 905,190$ 640,568$ $ - 165Lime1.15 1,1933.639 Naughton Unit 3-$ -$ -$ $ - -Lime- --10 Wyodak Unit 1-$ -$ -$--Lime---Table 11 - Case 8 O&M Costs (Wet FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3809,804$ 1,182,587$ 788,391$ -$ 230Lime1.02 -3.452 Dave Johnston Unit 4809,804$ 1,430,784$ 953,856$ $ - 330Lime1.02 1,7986.293 Jim Bridger Unit 1-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.534 Jim Bridger Unit 2-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.535 Jim Bridger Unit 3-$ 25,550$ 17,033$ $ - 52Soda Ash1.02 -0.526 Jim Bridger Unit 4-$ 25,550$ 17,033$ $ - 27Soda Ash1.02 -0.537 Naughton Unit 1809,804$ 963,589$ 642,393$ $ - 160Lime1.05 -2.408 Naughton Unit 2809,804$ 1,226,386$ 817,591$ $ - 220Lime1.05 -3.309 Naughton Unit 3-$ 21,900$ 14,600$ $ - 66Soda Ash1.02 -0.3310 Wyodak Unit 1303,677$ 328,496$ 218,998$$ -82Lime1.02-1.75Variable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsEY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur67 -0.0510 Wyodak Unit 1-$ -$ 10,000$--Elemental Sulfur63-0.05Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak Unit 1-$ 48,666$ 72,999$$ --None-1,7982.06Table 14 - Major Materials Design and Supply Costs2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3$ 5,449,830 $ 3,556,617 $ 5,773,000 $ 49,355,000 $ 56,379,000 $ 85,647,000 $ 88,913,000 $ - $ 18,359,0002 Dave Johnston Unit 4$ 2,673,501 $ 4,343,192 $ 7,171,085 $ 66,200,000 $ - $ 137,267,000 $ 178,174,384 $ - $ 30,853,5303 Jim Bridger Unit 1$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0004 Jim Bridger Unit 2$ - $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0005 Jim Bridger Unit 3$ 2,981,982 $ 6,056,955 $ 9,419,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0006 Jim Bridger Unit 4$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 93,009,000 $ - $- $ 3,549,000 $ - $ 29,814,0007 Naughton Unit 1$ 2,502,123 $ 2,675,792 $ 7,257,000 $ 37,292,000 $ 26,819,000 $ 42,301,000 $ 44,000,000 $ 800,000 $ 15,482,0008 Naughton Unit 2$ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 39,262,000 $ 57,621,000 $ 56,000,000 $ 800,000 $ 18,359,0009 Naughton Unit 3$ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $- $ 2,963,000 $ 800,000 $ 20,106,00010 Wyodak Unit 1$ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 996,100 $ -$ 178,174,384 $ 1,247,061 $ 20,106,000Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsNOx Control SO2 Control PM ControlIndex No. Name of Unit | Case --->EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls5 of 5CAPITAL COSTDave Johnston Unit 3CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control SystemCAPITAL COST COMPONENTFactor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source CostLNB w/OFA or ROFALNB w/OFA ROFA LNB w/OFA LNB w/OFAMajor Materials Design and SupplyVendor $5,449,830Vendor $3,556,617Vendor $5,449,830Vendor $5,449,830Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$4,650,54585.3%$3,034,99585.3%$4,650,54585.3%$4,650,54585.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$2,817,13451.7%$1,838,49251.7%$2,817,13451.7%$2,817,13451.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$1,066,9850.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$722,01213.2%$471,19313.2%$722,01213.2%$722,01213.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$895,16116.4%$584,19216.4%$895,16116.4%$895,16116.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$665,88512.2%$434,56412.2%$665,88512.2%$665,88512.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal $15,200,567 $10,987,037 $15,200,567 $15,200,567 $0 $0 $0 $0 $0Contingency12.8%$699,43430.0%$1,066,98512.8%$699,43412.8%$699,43412.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $15,900,001 $12,054,022 $15,900,001 $15,900,001 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $5,773,000 S&L Report $49,355,000 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0Contingency20.0%$020.0%$020.0%$1,154,60010.0%$4,935,50020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$322,8845.6%$2,760,4255.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$4,169,0178.4%$08.4%$08.4%$08.4%$08.4%$0Boiler Reinforcement (Allowance)0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Sales Tax1.1%$01.1%$01.1%$63,6181.1%$543,8921.1%$01.1%$01.1%$01.1%$01.1%$0Escalation0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Contingency on Adders2.8%$02.8%$02.8%$162,0480.0%$02.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$659,39211.4%$5,637,32811.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $8,135,543 $67,401,162 $0 $0 $0 $0 $0Dry or Wet FGD, FGC or Fabric FilterDry FGD Dry FGD w/FF Wet FGD FGC Fabric FilterMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $56,379,000 S&L Report $85,647,000 S&L Report $88,913,000 S&L Report $0 S&LReport $18,359,000Contingency20.0%$020.0%$020.0%$020.0%$020.0%$11,275,80020.0%$17,129,40020.0%$17,782,60020.0%$020.0%$3,671,800Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$3,153,2775.6%$4,790,2375.6%$4,972,9045.6%$05.6%$1,026,819EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$4,762,3348.4%$7,234,6028.4%$7,510,4818.4%$08.4%$1,550,785Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$1,586,5052.8%$2,410,1072.8%$2,502,0122.8%$02.8%$516,622Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$621,2971.1%$943,8301.1%$979,8211.1%$01.1%$202,316Escalation10.1%$010.1%$010.1%$010.1%$010.1%$5,699,35310.1%$8,658,05510.1%$8,988,21510.1%$010.1%$1,855,911Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$1,582,5592.8%$2,404,1112.8%$2,495,7882.8%$02.8%$515,337Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$6,439,60911.4%$9,782,60011.4%$10,155,64311.4%$011.4%$2,096,965Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $91,499,734 $138,999,942 $144,300,464 $0 $29,795,555Fabric Filter8NoneFabric Filter10NoneNoneNoneNoneN/ADry FGD w/Fabric FilterDry FGD w/ESPLNB w/OFA & SNCRSO2 ControlWet FGD w/ESPWet FGD w/ESPESPLNB w/OFANoneESP ESPROFANoneNoneDry FGD w/Fabric FilterParameterLNB w/OFA ROFA LNB w/OFA & SCRESPNoneDry FGD w/ESPESPLNB w/OFA & SNCRNoneESP ESPLNB w/OFA & SCRNonePM ControlN/ANOx Control45 76293EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 1Dave Johnston Unit 3LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 100,000------1,512,5331,612,5333182 2015 102,000------1,512,5331,614,5333183 2016 104,040------1,512,5331,616,5733184 2017 106,121------1,512,5331,618,6533195 2018 108,243------1,512,5331,620,7763196 2019 110,408------1,512,5331,622,9413207 2020 112,616------1,512,5331,625,1493208 2021 114,869------1,512,5331,627,4013219 2022 117,166------1,512,5331,629,69832110 2023 119,509------1,512,5331,632,04232111 2024 121,899------1,512,5331,634,43232212 2025 124,337------1,512,5331,636,87032213 2026 126,824------1,512,5331,639,35732314 2027 129,361------1,512,5331,641,89332315 2028 131,948------1,512,5331,644,48032416 2029 134,587------1,512,5331,647,11932417 2030 137,279------1,512,5331,649,81132518 2031 140,024------1,512,5331,652,55732519 2032 142,825------1,512,5331,655,35732620 2033 145,681------1,512,5331,658,214327Present Worth1,221,785------15,900,00117,121,787169(% of PW)7.1% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 92.9% 100.0%Dave Johnston Unit 3ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 150,000----1,087,6331,087,6331,146,6732,384,3064242 2015 153,000----1,109,3861,109,3861,146,6732,409,0594283 2016 156,060----1,131,5741,131,5741,146,6732,434,3074324 2017 159,181----1,154,2051,154,2051,146,6732,460,0594375 2018 162,365----1,177,2891,177,2891,146,6732,486,3274426 2019 165,612----1,200,8351,200,8351,146,6732,513,1204467 2020 168,924----1,224,8521,224,8521,146,6732,540,4494518 2021 172,303----1,249,3491,249,3491,146,6732,568,3244569 2022 175,749----1,274,3361,274,3361,146,6732,596,75846110 2023 179,264----1,299,8221,299,8221,146,6732,625,75946611 2024 182,849----1,325,8191,325,8191,146,6732,655,34147212 2025 186,506----1,352,3351,352,3351,146,6732,685,51447713 2026 190,236----1,379,3821,379,3821,146,6732,716,29148314 2027 194,041----1,406,9701,406,9701,146,6732,747,68348815 2028 197,922----1,435,1091,435,1091,146,6732,779,70449416 2029 201,880----1,463,8111,463,8111,146,6732,812,36450017 2030 205,918----1,493,0871,493,0871,146,6732,845,67850618 2031 210,036----1,522,9491,522,9491,146,6732,879,65851219 2032 214,237----1,553,4081,553,4081,146,6732,914,31851820 2033 218,522----1,584,4761,584,4761,146,6732,949,671524Present Worth1,832,678----13,288,54413,288,54412,054,02227,175,244241(% of PW)6.7% 0.0% 0.0% 0.0% 0.0% 48.9% 48.9% 44.4% 100.0%EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 4Dave Johnston Unit 3LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 245,000-665,287--90,666755,9532,286,4493,287,4025842 2015 249,900-678,593--92,479771,0722,286,4493,307,4215883 2016 254,898-692,164--94,329786,4932,286,4493,327,8405914 2017 259,996-706,008--96,215802,2232,286,4493,348,6685955 2018 265,196-720,128--98,140818,2682,286,4493,369,9135996 2019 270,500-734,530--100,103834,6332,286,4493,391,5826037 2020 275,910-749,221--102,105851,3262,286,4493,413,6846068 2021 281,428-764,205--104,147868,3522,286,4493,436,2296109 2022 287,057-779,490--106,230885,7192,286,4493,459,22561510 2023 292,798-795,079--108,354903,4342,286,4493,482,68061911 2024 298,654-810,981--110,521921,5022,286,4493,506,60562312 2025 304,627-827,201--112,732939,9322,286,4493,531,00862713 2026 310,719-843,745--114,986958,7312,286,4493,555,89963214 2027 316,934-860,619--117,286977,9062,286,4493,581,28863615 2028 323,272-877,832--119,632997,4642,286,4493,607,18564116 2029 329,738-895,388--122,0241,017,4132,286,4493,633,60064517 2030 336,332-913,296--124,4651,037,7612,286,4493,660,54365018 2031 343,059-931,562--126,9541,058,5162,286,4493,688,02565519 2032 349,920-950,193--129,4931,079,6872,286,4493,716,05666020 2033 356,919-969,197--132,0831,101,2812,286,4493,744,648665Present Worth2,993,374-8,128,377--1,107,7449,236,12124,035,54436,265,039322(% of PW)8.3% 0.0% 22.4% 0.0% 0.0% 3.1% 25.5% 66.3% 100.0%Dave Johnston Unit 3LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 387,500-426,024384,000-620,0771,430,1017,924,2589,741,8591,4012 2015 395,250-434,545391,680-632,4781,458,7037,924,2589,778,2111,4063 2016 403,155-443,236399,514-645,1281,487,8777,924,2589,815,2901,4124 2017 411,218-452,100407,504-658,0301,517,6347,924,2589,853,1111,4175 2018 419,442-461,142415,654-671,1911,547,9877,924,2589,891,6881,4236 2019 427,831-470,365423,967-684,6151,578,9477,924,2589,931,0361,4287 2020 436,388-479,772432,446-698,3071,610,5267,924,2589,971,1721,4348 2021 445,116-489,368441,095-712,2731,642,7367,924,25810,012,1101,4409 2022 454,018-499,155449,917-726,5191,675,5917,924,25810,053,8671,44610 2023 463,098-509,138458,916-741,0491,709,1037,924,25810,096,4601,45211 2024 472,360-519,321468,094-755,8701,743,2857,924,25810,139,9041,45812 2025 481,808-529,707477,456-770,9871,778,1517,924,25810,184,2161,46513 2026 491,444-540,302487,005-786,4071,813,7147,924,25810,229,4161,47114 2027 501,273-551,108496,745-802,1351,849,9887,924,25810,275,5191,47815 2028 511,298-562,130506,680-818,1781,886,9887,924,25810,322,5441,48416 2029 521,524-573,372516,813-834,5411,924,7277,924,25810,370,5101,49117 2030 531,954-584,840527,150-851,2321,963,2227,924,25810,419,4351,49818 2031 542,594-596,537537,693-868,2572,002,4867,924,25810,469,3381,50619 2032 553,445-608,467548,447-885,6222,042,5367,924,25810,520,2401,51320 2033 564,514-620,637559,415-903,3352,083,3877,924,25810,572,1591,520Present Worth4,734,418-5,205,1004,691,656-7,576,00517,472,76183,301,164105,508,343759(% of PW)4.5% 0.0% 4.9% 4.4% 0.0% 7.2% 16.6% 79.0% 100.0%EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls2 of 4Dave Johnston Unit 3Dry FGD w/ESPYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 1,697,23199,5661,351,845-701,072982,7413,135,2248,704,17113,536,6251,2512 2015 1,731,175101,5571,378,882-715,0931,002,3953,197,9288,704,17113,633,2741,2603 2016 1,765,799103,5881,406,460-729,3951,022,4433,261,8878,704,17113,731,8561,2704 2017 1,801,115105,6601,434,589-743,9831,042,8923,327,1258,704,17113,832,4101,2795 2018 1,837,137107,7731,463,281-758,8631,063,7503,393,6678,704,17113,934,9751,2886 2019 1,873,880109,9291,492,547-774,0401,085,0253,461,5408,704,17114,039,5911,2987 2020 1,911,358112,1271,522,398-789,5211,106,7263,530,7718,704,17114,146,2991,3088 2021 1,949,585114,3701,552,845-805,3111,128,8603,601,3878,704,17114,255,1421,3189 2022 1,988,576116,6571,583,902-821,4171,151,4373,673,4148,704,17114,366,1611,32810 2023 2,028,348118,9901,615,580-837,8461,174,4663,746,8838,704,17114,479,4011,33911 2024 2,068,915121,3701,647,892-854,6031,197,9553,821,8208,704,17114,594,9061,34912 2025 2,110,293123,7981,680,850-871,6951,221,9143,898,2578,704,17114,712,7201,36013 2026 2,152,499126,2741,714,467-889,1291,246,3533,976,2228,704,17114,832,8911,37114 2027 2,195,549128,7991,748,756-906,9111,271,2804,055,7468,704,17114,955,4661,38315 2028 2,239,460131,3751,783,731-925,0491,296,7054,136,8618,704,17115,080,4921,39416 2029 2,284,249134,0031,819,406-943,5501,322,6394,219,5988,704,17115,208,0181,40617 2030 2,329,934136,6831,855,794-962,4211,349,0924,303,9908,704,17115,338,0951,41818 2031 2,376,533139,4161,892,910-981,6701,376,0744,390,0708,704,17115,470,7741,43019 2032 2,424,064142,2051,930,768-1,001,3031,403,5964,477,8728,704,17115,606,1061,44320 2033 2,472,545145,0491,969,384-1,021,3291,431,6674,567,4298,704,17115,744,1441,456Present Worth20,736,5171,216,48216,516,649-8,565,59312,006,98038,305,70491,499,734150,541,955696(% of PW)13.8% 0.8% 11.0% 0.0% 5.7% 8.0% 25.4% 60.8% 100.0%Dave Johnston Unit 3Dry FGD w/Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 1,697,23199,5661,351,845151,563735,8251,529,4963,868,29513,222,76218,788,2881,5762 2015 1,731,175101,5571,378,882154,594750,5421,560,0863,945,66113,222,76218,899,5991,5853 2016 1,765,799103,5881,406,460157,686765,5531,591,2884,024,57513,222,76219,013,1351,5954 2017 1,801,115105,6601,434,589160,840780,8641,623,1134,105,06613,222,76219,128,9431,6055 2018 1,837,137107,7731,463,281164,056796,4811,655,5764,187,16713,222,76219,247,0671,6156 2019 1,873,880109,9291,492,547167,337812,4111,688,6874,270,91113,222,76219,367,5531,6257 2020 1,911,358112,1271,522,398170,684828,6591,722,4614,356,32913,222,76219,490,4481,6358 2021 1,949,585114,3701,552,845174,098845,2321,756,9104,443,45613,222,76219,615,8021,6469 2022 1,988,576116,6571,583,902177,580862,1371,792,0484,532,32513,222,76219,743,6631,65610 2023 2,028,348118,9901,615,580181,131879,3801,827,8894,622,97113,222,76219,874,0811,66711 2024 2,068,915121,3701,647,892184,754896,9671,864,4474,715,43113,222,76220,007,1071,67812 2025 2,110,293123,7981,680,850188,449914,9061,901,7364,809,73913,222,76220,142,7941,69013 2026 2,152,499126,2741,714,467192,218933,2051,939,7714,905,93413,222,76220,281,1951,70114 2027 2,195,549128,7991,748,756196,062951,8691,978,5665,004,05313,222,76220,422,3641,71315 2028 2,239,460131,3751,783,731199,984970,9062,018,1375,104,13413,222,76220,566,3561,72516 2029 2,284,249134,0031,819,406203,983990,3242,058,5005,206,21613,222,76220,713,2281,73817 2030 2,329,934136,6831,855,794208,0631,010,1312,099,6705,310,34113,222,76220,863,0371,75018 2031 2,376,533139,4161,892,910212,2241,030,3332,141,6645,416,54813,222,76221,015,8421,76319 2032 2,424,064142,2051,930,768216,4691,050,9402,184,4975,524,87813,222,76221,171,7041,77620 2033 2,472,545145,0491,969,384220,7981,071,9592,228,1875,635,37613,222,76221,330,6831,789Present Worth20,736,5171,216,48216,516,6491,851,7708,990,20818,687,15847,262,266138,999,942206,998,725868(% of PW)10.0% 0.6% 8.0% 0.9% 4.3% 9.0% 22.8% 67.2% 100.0%EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls3 of 4Dave Johnston Unit 3Wet FGD w/ESPYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 2,780,782132,3711,134,609-884,9241,359,9903,511,89413,726,98920,019,6651,5912 2015 2,836,398135,0181,157,301-902,6231,387,1903,582,13213,726,98920,145,5181,6013 2016 2,893,125137,7191,180,447-920,6751,414,9343,653,77413,726,98920,273,8891,6114 2017 2,950,988140,4731,204,056-939,0891,443,2323,726,85013,726,98920,404,8271,6225 2018 3,010,008143,2821,228,137-957,8701,472,0973,801,38713,726,98920,538,3841,6326 2019 3,070,208146,1481,252,700-977,0281,501,5393,877,41513,726,98920,674,6121,6437 2020 3,131,612149,0711,277,754-996,5681,531,5703,954,96313,726,98920,813,5641,6548 2021 3,194,244152,0531,303,309-1,016,5001,562,2014,034,06213,726,98920,955,2951,6659 2022 3,258,129155,0941,329,375-1,036,8301,593,4454,114,74313,726,98921,099,8621,67710 2023 3,323,292158,1951,355,963-1,057,5661,625,3144,197,03813,726,98921,247,3191,68911 2024 3,389,758161,3591,383,082-1,078,7181,657,8204,280,97913,726,98921,397,7261,70112 2025 3,457,553164,5871,410,744-1,100,2921,690,9774,366,59913,726,98921,551,1401,71313 2026 3,526,704167,8781,438,958-1,122,2981,724,7964,453,93113,726,98921,707,6231,72514 2027 3,597,238171,2361,467,738-1,144,7441,759,2924,543,00913,726,98921,867,2361,73815 2028 3,669,183174,6611,497,092-1,167,6391,794,4784,633,86913,726,98922,030,0411,75116 2029 3,742,566178,1541,527,034-1,190,9911,830,3674,726,54713,726,98922,196,1021,76417 2030 3,817,418181,7171,557,575-1,214,8111,866,9754,821,07813,726,98922,365,4841,77718 2031 3,893,766185,3511,588,726-1,239,1071,904,3144,917,49913,726,98922,538,2541,79119 2032 3,971,641189,0581,620,501-1,263,8891,942,4015,015,84913,726,98922,714,4801,80520 2033 4,051,074192,8391,652,911-1,289,1671,981,2495,116,16613,726,98922,894,2291,820Present Worth33,975,1851,617,28813,862,485-10,811,87316,616,15842,907,804144,300,464221,183,453879(% of PW)15.4% 0.7% 6.3% 0.0% 4.9% 7.5% 19.4% 65.2% 100.0%Dave Johnston Unit 3Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 112,540--151,563-545,179696,7412,834,3863,643,66822,0082 2015 114,791--154,594-556,082710,6762,834,3863,659,85422,1053 2016 117,087--157,686-567,204724,8902,834,3863,676,36322,2054 2017 119,429--160,840-578,548739,3872,834,3863,693,20322,3075 2018 121,817--164,056-590,119754,1752,834,3863,710,37922,4116 2019 124,254--167,337-601,921769,2592,834,3863,727,89922,5167 2020 126,739--170,684-613,960784,6442,834,3863,745,76922,6248 2021 129,274--174,098-626,239800,3372,834,3863,763,99722,7349 2022 131,859--177,580-638,764816,3432,834,3863,782,58922,84710 2023 134,496--181,131-651,539832,6702,834,3863,801,55322,96111 2024 137,186--184,754-664,570849,3242,834,3863,820,89623,07812 2025 139,930--188,449-677,861866,3102,834,3863,840,62623,19713 2026 142,728--192,218-691,418883,6362,834,3863,860,75123,31914 2027 145,583--196,062-705,247901,3092,834,3863,881,27823,44315 2028 148,495--199,984-719,352919,3352,834,3863,902,21623,56916 2029 151,465--203,983-733,739937,7222,834,3863,923,57323,69817 2030 154,494--208,063-748,413956,4762,834,3863,945,35723,83018 2031 157,584--212,224-763,382975,6062,834,3863,967,57623,96419 2032 160,735--216,469-778,649995,1182,834,3863,990,24024,10120 2033 163,950--220,798-794,2221,015,0202,834,3864,013,35724,241Present Worth1,375,002--1,851,770-6,660,9128,512,68329,795,55539,683,24011,984(% of PW)3.5% 0.0% 0.0% 4.7% 0.0% 16.8% 21.5% 75.1% 100.0%EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls4 of 4EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 1First Year Cost for Air Pollution Control Options05,000,00010,000,00015,000,00020,000,00025,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRDry FGDw/ESPDry FGDw/Fabric FilterWet FGDw/ESPFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls1 of 1Present Worth Cost for Air Pollution Control Options050,000,000100,000,000150,000,000200,000,000250,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRDry FGDw/ESPDry FGDw/Fabric FilterWet FGDw/ESPFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B 

# 2006 Wyoming BART Protocol