# Final Report



# BART Analysis for

Dave Johnston Unit 4

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 4

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 4 (hereafter referred to as Dave Johnston 4). A BART

analysis has been conducted for the following criteria pollutants: nitrogen oxides (NO

x 

# ),

sulfur dioxide (SO 2 

# ), and particulate matter less th an 10 micrometers in aerodynamic

diameter (PM 10 

# ). The Dave Johnston Station consists of four units with a total generating

capacity of 772 megawatts (MW). Therefore, si nce the total generati ng capacity of the

Dave Johnston plant exceeds 750 MW, pres umptive BART limits do apply to Dave

Johnston 4. Presumptive BART emission limits are referenced in this analysis, based on the

United States Environmental Protection Agency’s (EPA) guidelines for units greater than

200 MW at plants greater than 750 MW. BART emissions limits must be achieved within

5 years after the State Implementation Plan (S IP) 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)

− Rotating opposed fire air (ROFA)

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

− LNBs burners with selective ca talytic reduction (SCR) system

• SO 2 

# emission controls:

− Lime spray drying flue gas desu lfurization (dry FGD) system

− Wet FGD system

• PM 10 

# emission controls:

− Electrostatic precipitator (ESP)

− Fabric filter



# 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

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# • The remaining useful life of the facility

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

• The degree of visibility improvement which may 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 whic h 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.



# Recommendations

NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by the EPA for ta ngentially-fired boilers burning

sub-bituminous coal is 0.15 pound (lb) per millio n British thermal units (MMBtu). The Dave

Johnston 4 plant burns only Powder River Basin (PRB) coal, a sub-bituminous coal.

CH2M HILL recommends new LNBs with OFA as BART for Dave Johnston 4, based on the

projected significant reduction in NO

x 

# emissions, reasonable control costs, and the

advantages of no additional power requirement s or non-air quality environmental impacts.

These LNBs will be capable of meeting the presumptive BART limit of 0.15 lb per MMBtu.



# SO 2 

# Emission Control

CH2M HILL recommends a new dry FGD syst em as BART for Dave Johnston 4, 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.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# This upgrade approach is projected to meet the BART presumptive SO 2 

# limit of 0.15 lb per

MMBtu.



# PM 10



# Emission Control

CH2M HILL recommends replacement of the Ventur i particulate scrubber with a fabric filter

downstream of the lime spray dr yer as BART for Dave Johnst on 4, based on the significant

reduction in PM 10 

# emissions, reasonable control costs, and the advantages of minimal

additional power requirements and no non-air quality environmental impacts.



# Control Scenario 1

These BART selections, which include installi ng LNBs with OFA, a new lime spray drying

FGD system, and the replacement of the Ventur i particulate scrubber with a fabric filter

downstream of the lime spray dr yer, are identified as Scenario 1 thr oughout this report.



# BART Modeling Analysis

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

emissions from Dave Johnston 4 at Class I areas . The Class I areas potentially affected are

located more than 50 kilometers, but less than 300 kilometers, from the Dave Johnston 4

Plant.

The Class I areas include th e following national parks:

• Wind Cave National Park

• Badlands National Park

Because Dave Johnston 4 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four

post-control atmospheric dispersi on modeling scenarios were deve loped to cover the 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 LNB with OFA modi fications, a dry FGD system, and the replacement

of the Venturi particulate scrubber with a fabric filter downstream of the lime spray

dryer. As indicated previous ly, this scenario represents CH2M HILL’s preliminary

BART recommendation.

• Scenario 2 : New LNB with OFA modi fications, a wet FGD system, and replacement of

the Venturi particulate scrubbe r with a new fabric filter.

• Scenario 3 : New LNB with OFA modifications a nd SCR, a dry FGD system, and the

replacement of the Venturi particulate scrubb er with a new fabric filter downstream of

the lime spray dryer

.

• Scenario 4 : New LNB with OFA modifications and SCR, a wet FGD system, and

replacement of the Venturi particulate scrubber with a new fabric filter.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC ES-4 

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

were compared using a least-cost envelope, as outlined in the draft 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 a total emissions reducti ons 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, wet FGD and

fabric filter) is eliminated, b ecause 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 fabric filter) is not selected

because of very high incremental costs, 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 FGD and fabric

filter) provides some potential visibility advantage over Scenario 1, the projected

improvement is less than 0.5 dV, and the projected costs are excessive. Therefore, Scenario 1

represents BART for Dave Johnston 4.



# 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 spend many millions of dollars at this single unit, and over $1 billion when

considering its entire coal fleet , only minimal discernable visi bility improvements may result.

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

# 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......................................................................... 4-8

4.3.6 Receptor Grids ............................................................................. 4-8

4.4 CALPOST.............................................................................................. 4-10

4.5 Presentation of Modeling Results .......................................................... 4-11

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario............. 4-11

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\DAVEJOHNSTON4_FINALSUBMITTAL\BART_DJ4_OCT2007_FINAL.DOC 

# iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_DJ4_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 Ranking

3-4 SO 2 

# Control Cost Comparison

3-5 PM 10 

# Control Technology Emission Rates

3-6 PM 10 

# Control Cost Comparison

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

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

CO Carbon Monoxide

oF Degrees Fahrenheit

dV Deciview

Δ dV Delta Deciview, Change in Deciview

EIA Energy Information Administration

ESP Electrostatic Precipitator

EPA United States Environmental Protection Agency

FGD Flue Gas Desulfurization

f (RH) Relative Humidity Factors

kW Kilowatt

kWh Kilowatt-Hour

LAER Lowest Achievable Emission Rate

lb Pound

LNB Low-NO

x 

# Burner

LOI Loss on Ignition

MMBtu Million British Thermal Units

MM5 Mesoscale Meteorological Model, Version 5

MSL Mean Sea Level

MW Megawatt

MW-Hr Megawatt-Hour

N 2 

# Nitrogen

(NH 4 

# ) 2 

# SO 4 

# Ammonium Sulfate

(NH 4 

# )HSO 4 

# Ammonium Bisulfate

NO 2 

# Nitrogen Dioxide

NO

x 

# Nitrogen Oxides

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 

# v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 

# vi 

# OFA Over-Fire Air

PM 2.5 

# Particulate Matter Less than 2.5 Mi crometers in Aerodynamic Diameter

PM 10 

# Particulate Matter Less than 10 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Sargent & Lundy

SCR Selective Catalytic Reduction System

SIP State Implementation Plan

SNCR Selective Non-Catalytic Reduction System

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

USGS U.S. Geological Survey

WDEQ Wyoming Department of Environmental Quality

WDEQ-AQD Wyoming Department of Envi ronmental 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) regulations intended to reduce the

occurrence of regional haze in national parks (NPs) and other Class I protected air quality

areas in the United States. These guidelines pr ovide 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 Qu ality (WDEQ) BART re gulations state that

each source subject to BART must submit a BA RT 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 4 (hereafter refe rred to as Dave Johnston 4) by January 19,

2007. The BART report that was submitted to WDEQ in January 2007 included a BART

analysis, and a proposal and justification for 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 that are required to

reduce emissions under BART, and will set BART emissions limits for those facilities. This

information will be included in the State of Wyoming State Implementation Plan (SIP),

which the State has estimated will be forma lly submitted to the EPA by early 2008. The EPA

BART guidelines also state that the BART emission limits must be fully implemented within

5 years of EPA’s approval of the SIP.

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 may reasonably be anticipated from the use

of such technology

This report documents the BART analysis performed on Dave Johnston 4 by CH2M HILL

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

x 

# ), sulfur

dioxide (SO 2 

# ), and particulate matter less than 10 micrometers in aerodynamic diameter

(PM 10 

# ), because they are the primary criteria pollutants that a ffect 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 Analysis is provided

in Section 3, by pollutant type. Section 4 provides the met hodology and results of the BART

Modeling Analysis, followed by recommendations in Section 5. References are provided in

Section 6. Appendices provide more deta il on the Economic Analysis, and the 2006

Wyoming BART Protocol.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 1-1

# 2.0 Present Unit Operation

Dave Johnston 4 is a nominal 330-megawatts (M W) pulverized coal unit located in central

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

manufactured by Combustion Engineering ( now Alstom). Concentric-firing low-NO

x 

# burners

(LNBs) were installed in 1976. A Venturi scrubber is used for particulat e control, and lime is

added to the scrubber liquor to achieve approximately 50-percent reduction in SO 2 

# . Table 2-1

lists additional unit information a nd the basis of design assumptions.

The coal currently burned in Dave Johnston 4 is from the Rawhide Mine; however, coal from

Clovis Point, Dry Fork, and other northern Po wder River Basin (PRB) mines may also be

used. All of the coals are sub-bituminous rank from Wyoming. Coal sources and

characteristics are summarized in Table 2-2.

Dave Johnston 4 was placed in service in 1972. 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 4 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 4 to operate until 2034.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 2-2 

# TABLE 2-1



# Present Unit Operation

Dave Johnston 4

General Plant Data

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

Stack Height (feet) 250

Stack Exit Internal Diameter (feet) /Exit Area (square feet) 32 / 804.6

Stack Exit Temperature (degrees Fahrenheit) 120

Stack Exit Velocity (feet per second) 28

Stack Flow (actual cubic feet per minute) 1,351,680

Latitude (deg: min: sec) 42:50:17.03 north

Longitude (deg: min: sec) 105:46:38.66 west

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 330

Net Unit Heat Rate (British thermal units [Btu] per kilowatthour)(100 percent load) 10,904 (as measured by fuel throughput)

Boiler Heat Input (million Btu per hour)(100 percent load) 4,100 (as measured by CEM)

Type of Boiler Adjustable Tangential Fired

Boiler Fuel PRB Coal

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

Coal Heating Value (Btu per pound)* 7,784

Coal Sulfur Content (wt. %) (a) 

# 0.47

Coal Ash Content (wt. %) (a) 

# 5.01

Coal Moisture Content (wt. %) (a) 

# 30.40

Coal Nitrogen Content (wt. %) (a) 

# 0.97

Current NO

x 

# Controls Concentric Firing Low NO

x

# Burners

NO

x

# Emission Rate(pounds per million Btu) (b) 

# 0.40

Current Sulfur Dioxide Controls Venturi Scrubber with lime injection

SO 2 

# Emission Rate (pounds per million Btu)** 0.50

Current PM 10 

# Controls (c) 

# Venturi Scrubber

Particulate Matter Emission Rate (pounds per million Btu) (d) 

# 0.061

NOTES:

(a) 

# Coal characteristics vary between coal sources

(b) 

# Emission rates stated on annual average basis

(c) 

# PM 10 

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

(d) 

# Emission rate stated from test resultsBART ANALYSIS FOR DAVE JOHNSTON UNIT 4JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC2-3TABLE 2-2Coal Sources and CharacteristicsDave Johnston 4Ultimate Analysis (% dry basis)MinesMoisture(%)Ash(%)VolatileMatter(%)FixedCarbon(%)Britishthermalunitsperpound(Btu/lb)Sulfur(%)Moistureand AshFree(Btu/lb)Hydrogen Carbon Sulfur Nitrogen Oxygen AshClovis Point Mine32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.99 67.3 0.87 0.91 16.2 9.7Maximum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.5869.5 1.07 1.00 18.8 10.8Minimum 29.9 4.5 30.0 29.0 7,901 0.36 12,744 3.8264.4 0.63 0.83 14.3 8.7Dry Fork Mine32.1 5.2 29.5 33.0 8,036 0.39 12,818 4.56 68.7 0.57 1.00 17.7 7.4Maximum 30.7 4.5 39.1 42.7 8,200 0.54 12,924 5.0471.3 0.76 1.52 19.7 10.6Minimum 33.2 7.8 28.9 31.9 7,650 0.26 12,726 4.0765.8 0.34 0.60 15.6 5.3Rawhide Mine30.4 5.3 30.4 33.9 8,285 0.37 12,875 4.63 69.4 0.50 0.97 17.3 7.3Maximum 31.6 6.6 32.7 37.1 8,480 0.53 13,000 5.4171.1 0.63 1.10 18.7 8.5Minimum 29.0 4.5 29.5 31.7 8,120 0.21 12,575 4.3166.3 0.39 0.78 15.3 6.6Other NorthernPRB30.1 5.9 30.8 33.2 8,122 0.39 12,843 4.73 68.4 0.65 0.96 17.1 8.1Maximum 32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.9967.3 0.87 0.91 16.2 9.7Minimum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.5869.5 1.07 1.00 18.8 10.8

# 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. The evaluation must include the

following:

• 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

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# • 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

To minimize costs in the BART analysis, co nsideration was made of any pollution control

equipment in use at the source, the costs of compliance associated w ith the control options,

and the energy and non-air quality environmenta l impacts of compliance using these existing

control devices. In some cases, enhancing the pe rformance 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

NO

x 

# formation in coal-fired boilers is a comple x process depends on a number of variables,

including operating conditi ons, equipment design, and coal characteristics.

Formation of NO

x



# During coal combustion, NO

x 

# forms in three ways. The dominant source of NO

x 

# formation is

the oxidation of fuel-bound nitr ogen. During combustion, part of the fuel-bound nitrogen is

released from the coal with the volatile matter, and part is retained in the solid portion (char).

The nitrogen chemically bound in the coal is pa rtially oxidized to nitrogen oxides (nitric

oxide and nitrogen dioxide) and partia lly reduced to molecular nitrogen (N 2 

# ). A smaller part

of NO

x 

# formation is caused by high temperature fi xation of atmospheric nitrogen in the

combustion air (thermal NO

x 

# ). A very small amount of NO

x 

# is called prompt NO

x 

# . Prompt

NO

x 

# results from an interaction of hydrocarbon 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

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

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# with low-NO

x 

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

promote more stable molecular nitrog en, therefore resulting 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 previously described. Base d on data from the Energy

Information Administration (EIA), PRB coals cu rrently represent 88 percent of total U.S.

sub-bituminous production and 73 percent of western coal production. Most references to

“western” coal and sub-bituminous coal infer PRB origin and characteristics. Emissions

standards differentiating between bituminous a nd sub-bituminous coals are presumed to use

PRB coal as the basis for the sub-bituminous st andards, because of their dominant market

presence and unique characteristics. Only P RB coals are burned at the Dave Johnston 4

facility.

The BART Analysis for Dave Johnston 4 NO

x 

# emissions is described in the following

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 4, 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 emissi on-control technologies.

Dave Johnston 4 NO

x 

# emissions are currently controlled through the use of good combustion

practices and over-fire air (OFA).

The following potential NO

x 

# control technology options were considered:

• New/modified LNB with advanced 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 4, a tangential-fired burne r configuration burning sub-bituminous coal,

technical feasibility will primar ily be determined by physical c onstraints, boiler configuration,

and the ability to achieve the regulatory presumptive limit (applicable to this unit) of

0.15 pound (lb) of NO

x 

# per Million British Thermal Units (MMBtu). Dave Johnston 4’s 2003

to 2005 NO

x 

# emission rate averaged 0.40 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). The cost estimates for SCR and SNCR were updated by S&L in October 2006.

PacifiCorp provided additional emissions data and costs developed by boiler vendors for

LNBs and OFA. Also, CH2M HILL solicited a proposal from Mobotec for their ROFA

technology.

With SNCR, an amine-based reagent such as a mmonia, or more commonly urea, is injected

into the furnace within a temperature range of 1,600 degrees Fahrenheit (°F) to 2,100°F,

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# 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 a pplications. SNCR is typically

applied on smaller units. Adequate reagent distri bution in the furnaces of large units can be

problematic.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

Preliminary vendor proposals, such as those used to support porti ons of this BART analysis, may

be technically feasible and provide expected or guaranteed emission rates; however, they include

inherent uncertainties. These proposals are usua lly prepared in a limited timeframe, may be

based on incomplete information, may contain ov er-optimistic conclusions, and are non-binding.

Therefore, emission rate values obtained in su ch preliminary proposals must be qualified, and it

must be recognized that contractual guarantees ar e established only after mo re detailed analysis

has been completed. The following subsections describe the contro l 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 nitrogen to N 2 

# instead of NO

x 

# . Additional air (or OFA) is then introduced

downstream in a lower temperatur e zone to burn out the char.

Both LNBs and OFA are considered to be capita l cost, combustion technology retrofits. Alstom

proposes to install their latest combustion-based NO

x 

# reduction firing system, TFS 2000 R, at

Dave Johnston 4. This system is Alstom’s most expensive offering, but is purported to achieve

the lowest NO

x 

# reductions. In addition to new LNBs, the system includes the addition of two

elevations of separated OFA. The separate d OFA system includes boiler pressure part

modifications to create the separated OFA port openings and instal lation of OFA ductwork,

dampers, and actuators.

Information provided to CH2M HILL by P acifiCorp, based on the 2002 S&L Report and

data from Alstom, indicates th at new LNB and OFA retrofit at Dave Johnston 4 would result

in an expected NO

x 

# emission rate of 0.15 lb per MMBtu. P acifiCorp has indicated that this

rate corresponds to a vendor guarantee, not a ve ndor prediction, and they believe that this

emission rate can be sustained as an aver age between overhauls. This emission rate

represents a reduction of 62 per cent from the 2003 to 2005 average NO

x 

# emission rate, and is

equivalent to the presumptive NO

x 

# emission rate of 0.15 lb per MMBtu for tangential fired

boilers burning sub-bituminous coal.

ROFA. Mobotec markets ROFA as an improved sec ond generation OFA system. The flue gas

volume of the furnace is set in rotation by asym metrically placed ai r nozzles located in

ROFA boxes strategically placed along the furn ace walls. Rotation is reported to prevent

laminar flow, so that the entire volume of th e furnace can be used more effectively for the

combustion process. Mobotec indicates that the swirling action reduces the maximum

temperature of the flames and increases heat absorption. They also state that combustion air

is mixed more effectively. The performance and functionality of the RO FA system works in

conjunction with and is dependant on the ove rall furnace geometry and operation. A typical

ROFA installation has a booster fan(s) to supply the high velocity air to the ROFA boxes.

Mobotec proposes one 5,200–5,800 horsepower fan for Dave Johnston 4.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# Based on the design, operating, a nd fuel quality data furnishe d to Mobotec by CH2M HILL,

Mobotec has stated that they do not believe that burner modifica tions or burner replacements

are required. In their proposal, Mobotec has stated a guaranteed NO

x 

# emission rate of 0.15 lb

per MMBtu.

Note. Preliminary vendor proposals—such as those from Mobotec—used for portions of this

BART Analysis may be techni cally feasible and provide ex pected or guaranteed emission

rates; however, they include inherent uncertainti es. These proposals are usually prepared in a

limited timeframe, may be based on incomplete information, may contain over-optimistic

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

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

guarantees are established only after more detailed analysis has been completed.

SNCR. Selective non-catalytic re duction is generally used to achieve modest NO

x 

# reductions

on smaller units. With SNCR, an amine-based reagent such as ammonia—or more commonly

urea—is injected into the fu rnace within a temperature rang e 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 re alistic 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

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 because of greater reagent consumption. To reduce reagent

costs, S&L has assumed that combustion modifi cations including LNBs and advanced OFA,

capable of achieving a projected NO

x 

# emission rate of 0.15 lb per MMBtu

. At a further

reduction of 20 percent in NO

x 

# , emission rates for SNCR wo uld result in a projected

emission rate of 0.12 lb per MMBtu.

SCR. SCR works on the same principle as SNCR but a catalyst is used 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 require d for SNCR, the reaction takes place 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 than SNCR. The most common

type of SCR is the high-dust configuration, where the catalyst is located upstream of the air

heater and downstream from the economizer. The high-dust configurat ion is assumed for

Dave Johnston 4. In a full-scale SCR, the flue ducts are routed to a separate 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 catalys t to increase flue gas residence time. As a

result of the higher removal ra te, a full-scale SCR was used as the basis for analysis at

Dave Johnston 4.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# S&L prepared the design conditions and cost estimates for SCR at Dave Johnston 4. They

used boiler heat input at full load, and the anticipated NO

x 

# emission rate of 0.15 lb per

MMBtu, after retrofit with new LNBs and OFA modifications. As with SNCR, it is generally

more cost effective to reduce NO

x 

# emission levels as much as possible through combustion

modifications to minimize the catalyst surface area and ammonia requirements of the SCR.

The S&L design basis includes an 82.5 percent removal rate, which results in a projected

NO

x 

# emission rate of 0.07 lb per MMBtu. Add itional catalyst surface was included in the

SCR design to accommodate the quality char acteristics of the PRB coal used at

Dave Johnston 4.

Level of Confidence for Vendor Post-Control Emissions Estimates. To determine the level of

NO

x 

# emissions needed to consistently achieve co mpliance with an established goal, a review

of typical NO

x 

# emissions from coal-fired generating units was completed. As a result of this

review, it was noted that NO

x 

# emissions can vary significan tly around an average emissions

level. This variance can be attributed to many reasons, including coal characteristics, unit

load, boiler operation including ex cess air, boiler slagging, burner equipment condition, coal

mill fineness, and so forth.

The following steps are used to determine a level of confidence for the vendor expected

value:

1. Establish expected NO

x 

# emissions value from vendor

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

3. Review and evaluate unit physical and operati onal characteristics and restrictions (the

fewer variations in operations, coal supply, et c., 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 valu e (from the vendor information presented, along

with anticipated unit operational data, an adju stment to the expected value can be made)

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

with projected NO

x 

# emission rates.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# TABLE 3-1



# NO

x 

# Control Technology Emission Rate Ranking

Dave Johnston 4

Technology Projected Emission Rate (pounds

per million British thermal unit)

Presumptive BART Limit 0.15

Low-NO

x

# Burner (LNB) with

Over-Fire Air (OFA) 0.15

Rotating Opposed Fire Air 0.15

LNB with OFA and Selective

Non-Catalytic Reduction

System 0.12

LNB with OFA and Selective

Catalytic Reduction System 0.07



# 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. Installation of LNBs and OFA system s are not expected to significantly

impact the boiler efficiency or forced-draft fan power usage. Therefore, these technologies

would not have energy impacts.

The Mobotec ROFA system would require 4,330 kilowatts (kW) of auxiliary power, or

approximately 1.2 percent of the unit rating of 360 MW, for operation of the

5,800-horsepower ROFA fan. This would equate to an annual power usage of approximately

34.1 million kilowatt-hours (kWh), based on a 90 percent annual plant capacity factor.

SCR retrofit would impact the existing flue ga s fan systems due to the additional pressure

drop associated with the catalyst, which is ty pically a 6-to 8-inch increase. The capital

costs—for fan upgrades and a dditional operating cost for increased power usage—are

included in the economic analysis for SCR. Total additional power requirements for SCR

installation at Dave Johnston 4 are estimat ed at approximately 2,290 kW, based on the 2002

S&L Report.

Environmental Impacts. Mobotec has predicted that car bon monoxide (CO) emissions, and

unburned carbon in the ash, commonly referred to as LOI (loss on igni tion), would be the

same or lower than previous levels for the ROFA system.

SNCR and SCR installation could impact the sa leability and disposal of fly ash due to

ammonia levels, and could potentially create a visible stack plume, which may negate other

visibility improvements. Other environmenta l impacts involve the storage of ammonia,

especially if anhydrous ammonia is used, and th e transportation of the ammonia to the power

plant site.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-8 

# Economic Impacts. Costs and schedules for the LNBs, OFA, and SCR were furnished to

CH2M HILL by PacifiCorp, developed using S&L’s internal proprie tary database, and

supplemented (as needed) by vendor-obtained pr ice quotes. The relative accuracy of these

cost estimates is stated by S&L to be in the range of ± 20 percent. Cost for the ROFA system

was obtained from Mobotec.

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, and th e first year control costs in Figure 3-1.

The complete Economic Analysis is contained in Appendix A.

TABLE 3-2



# NO

x 

# Control Cost Comparison

Dave Johnston 4

Factor Low-NO

x 

# Burner (LNB)

with OverFire Air

(OFA) Rotating

Opposed Fire

Air LNB with

OFA &

Selective

NonCatalytic

Reduction

System LNB with OFA

& Selective

Catalytic

Reduction

System

Total Installed Capital Costs $7.8 mil lion $14.7 million $17.9 million $106.7 million

Total First Year Fixed & Variable Operation

and Maintenance Costs $0.1 million $1.8 million $1.0 million $2.0 million

Total First Year Annualized Cost $0.8 mi llion $3.2 million $2.7 million $12.1 million

Power Consumption (megawatts)

-- 4.3 0.33 2.3

Annual Power Usage (1000 megawatthours per year) -- 34.1 2.6 18.1

NO

x

# Design Control Efficiency 62.5% 62.5% 70.0% 82.5%

NO

x

# Removed per Year (T ons) 4,041 4,041 4,526 5,334

First Year Average Control Cost

($ per Ton of Nitrogen Oxides removed) $206/ton $802/ton $598/ton $2,274/ton

Incremental Control Cost

($ per Ton of Nitrogen Oxides Removed) $206/ton $802/ton $3, 867/ton $11,659/ton



# Preliminary BART Selection. PacifiCorp selects LNBs with OFA as BART for

Dave Johnston 4 based on its significant reduction in NO

x 

# emissions, reasonable control cost,

and no additional power requireme nts or environmental impacts. LNB with OFA is projected

to meet the applicable EPA presumptiv e limit of 0.15 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 4FIGURE 3-1First Year Control Cost for NOxAir Pollution Control OptionsDave Johnston 402,0004,0006,0008,00010,00012,00014,000LNB 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_DJ4_OCT2007_FINAL.DOC3-9

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# 3.2.2 BART SO 2 

# Analysis

SO 2 

# forms in the boiler during the combustion pr ocess, and is primarily dependent on coal

sulfur content. The BART analysis for SO 2 

# emissions on Dave Johnston 4 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 4; 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 (F GD) with new fabric filter

• Wet FGD with new fabric filter

Step 2: Eliminate Technically Infeasible Options

Technical feasibility will primarily be base d on the regulatory presumptive limit (applicable

to this unit) of 95 percent reduction in SO 2 

# emissions, or 0.15 lb per MMBtu. Dave

Johnston 4 currently has an uncontrolled SO 2 

# emission rate of 1.20 lbs per MMBtu.

Therefore, 87.5 percent SO 2 

# removal is required to meet the presumptive limit of 0.15 lb per

MMBtu.

Dry FGD. The lime spray dryer typically injects lime slurry in the top of the absorber vessel

with a rapidly rotating atomizer wheel. The ra pid speed of the atomizer wheel causes the lime

slurry to separate into very fine droplet s that intermix with the flue gas. The SO 2 

# in the flue

gas reacts with the calcium in the lime slu rry to form calcium sulfate in the form of

particulate matter. At Dave Johnston 4, this dr y particulate matter would be captured in the

new downstream fabric filter, along with the fly ash. A lime spray dryer system typically

produces a dry waste product suitable for landfill disposal.

Dry FGD with a new fabric filter is projected to achieve 87.5 percent SO 2 

# removal. At Dave

Johnston 4, this 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 weight. Th erefore, this option

would meet the presumptiv e limit of 0.15 lb per MMBtu.

Wet FGD. Wet SO 2 

# scrubbers operate by treating the flue gas in large scrubber vessels with a

lime or limestone slurry. The scrubber mixes the flue gas and alkaline reagent using a series

of spray nozzles to distribute the reagent ac ross the scrubber vessel. The calcium in the

reagent reacts with the SO 2 

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

are removed from the scrubber with the sludge, and disposed.

Most wet FGD systems use forced oxidation to assure that only calci um sulfate sludge is

produced. The wet lime/limestone forced oxidation process is used in most new wet FGD

installations. Several variations on wet F GD technology are offered by various process

developers. These variations include using a jet bubbling reactor as a combination SO 2 

# absorber and calcium sulfite oxidation vessel, and using magnesium-enhanced lime as the

alkaline reagent.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# A new wet lime/limestone FGD system is projected to achieve an outlet emission rate of

0.10 lb per MMBtu (91.7 percent SO 2 

# removal), which would meet the presumptive limit of

0.15 lb per MMBtu for Dave Johnston 4. It is cons idered to be technically infeasible for a

new wet FGD system to achieve a 95 percent SO 2 

# removal (0.06 lb per MMBtu) on a

continuous basis.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

When evaluating the control effectiveness of SO 2 

# reduction technologies, each option can be

compared against benchmarks of performance. One such benchmark is the presumptive

BART emission limit. Dave Johnston 4 is not required to meet the presumptive BART limit;

however, this presumptive limit may serve as a po int of reference. As indicated previously,

the presumptive limit for SO 2 

# on a BART-eligible coal-burning un it is 95 percent removal, or

0.15 lb per MMBtu.

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

for Dave Johnston 4. The dry FGD with new fa bric filter and wet FGD technologies are

capable of meeting the presumptive SO 2 

# limit of 0.1 lb per MMBtu.

TABLE 3-3



# SO 2 

# Control Technology Emission Rate Ranking

Dave Johnston 4

Control Technology Short-Term Expected SO 2 

# Emission Rate (pounds per

million British thermal unit

Presumptive Best Available Retrofit

Technology Limit 0.15

Dry Flue Gas Desulfurization (FGD)

with Fabric Filter 0.15

Wet FGD with Fabric Filter 0.10



# 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 has the advantage of requiring less electric power for its

operation compared to a wet FGD system. A dry FGD system at Dave Johnston 4 with a new

fabric filter would require approximately 4.5 MW of power, compared to approximately

6.3 MW for wet FGD with a new fabric filter . Based on a 90 percent annual plant capacity

factor, this would equate to an annual pow er savings of approximately 13.8 million kWh for

dry FGD versus wet FGD for Dave Johnston 4.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# 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 electrostatic precipitator (ESP) or hydrated lime injection

when medium to high sulfur coal is burn ed in a unit 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.

• 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 saturated with water, which would require a gas-gas

heat exchanger to reheat the fl ue gas if it were to operate as a dry stack. Because of 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 dispos al challenge. This sludge mu st be handled properly to

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

gypsum market is available, reducing the quant ity of solid waste from the power plant 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 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 the first year control costs in Figure 3-2.

The complete Economic Analysis is contained in Appendix A.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-12

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-13 

# TABLE 3-4



# SO 2 

# Control Cost Comparison

Dave Johnston 4

Factor Dry Flue Gas Desulfurization

(FGD) with Fabric Filter We t FGD with Fabric Filter

Total Installed Capital Costs $222.8 million $289.2 million

Total First Year Fixed & Variable

Operation and Maintenance Costs $5.6 million $7.0 million

Total First Year Annualized Cost $26.8 million $34.5 million

Power Consumption (megawatts) 4.54 6.29

Annual Power Usage (kilowatts per

year) 35.8 49.6

Incremental Sulfur Dioxide Design

Control Efficiency 70.0% (87.5% based on

Uncontrolled Sulfur Dioxide) 80.0% (91.7% based on

Uncontrolled Sulfur Dioxide)

Incremental Tons Sulfur Dioxide

Removed per Year 5,657 6,466

First Year Average Control Cost

($ per Ton of Sulfur Dioxide Removed) $4,743 per ton $5,344 per ton

Incremental Control Cost

($ per Ton of Sulfur Dioxide Removed) $4,743 per ton $9,547 per ton



# Preliminary BART Selection. CH2M HILL recommends a dry FGD system as BART for

Dave Johnston 4, based on the significant reduction in SO 2 

# emissions, reasonable control

costs, and the advantages of minimal addi tional power requirements and minimal non-air

quality environmental impacts. This upgr ade approach is projected to meet the

BART-presumptive SO 2 

# limit of 0.15 lb per MMBtu that is applicable to this unit.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR DAVE JOHNSTON UNIT 4FIGURE 3-2First Year Control Cost for SO2Air Pollution Control OptionsDave Johnston 402,0004,0006,0008,00010,00012,000Dry FGD w/Fabric FilterWet FGD w/Fabric FilterAir Pollution Control Option

Control Cost ($/Ton SO2 Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC3-14

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# 3.2.3 BART PM 10



# Analysis

Dave Johnston 4 is equipped with a Venturi pa rticulate scrubber. Vent uri scrubbers operate

by mechanically forcing partic les and water droplets together. In these scrubbers, a

high-pressure water spray forces the polluted ga s stream through a cons tricted throat. Like

cyclone systems, Venturi scrubbers require that the particles gain a lot of momentum, so a

Venturi scrubber becomes less effective as a cont rol device as the particles become smaller.

Venturi scrubber efficiency can be increased by increasing either the water-side or air-side

pressure drop, but this grea tly increases the pump and/or motor power requirements and

operating costs for electricity. The PM 10 

# emissions from 2001 to 2006 indicate that the

Dave Johnston 4 Venturi part iculate scrubber controls PM 10 

# emissions to 0.061 lb per

MMBtu.

The BART Analysis for PM 10 

# emissions on Dave Johnston 4 is described below.

Step 1: Identify All Availabl e Retrofit Control Technologies

Two retrofit control t echnologies have been identified for additional pa rticulate matter

control:

• ESP

• Fabric filter

Step 2: Eliminate Technically Infeasible Options

ESP. ESP technology is applicable to a variety of coal combustion sources. ESPs remove

particulate matter from the flue gas stream by charging flyash particles with a very high

direct current voltage and attracting these par ticles to grounded collecti on plates. A layer of

collected particulate matter forms on the coll ecting plates and is removed by rapping the

plates. The collected ash particles drop into hoppers below the precip itator and are removed

periodically by the flyash-handling system.

Fabric Filter. Fabric filtration has been applied widely to coal combustion sources since the

early 1970s, and consists of a number of filte ring elements (bags) along with a bag cleaning

system and dust hoppers contained in a main shell structure. Fabric filt ers use fiberglass bags

as filters to collect particulate matter. The particulate-laden gas enters a fabric filter

compartment and passes through the bags and through a layer of accumulated particulate

matter collected on the fabric of the filter bags . The collected particulate matter forms a filter

cake layer on the bag that enhances the bag’s filtering efficiency. However, excessive caking

will increase the pressure drop across the fabric filter. When this occurs, the fabric filter is

placed into a cleaning cycle and the dislodge d particulate matter is removed by the

ash-handling system.

Fabric filters are effective in meeting NSPS emission requirements on coal-fired boilers.

Fabric filters have been used as a contro l technology of choice on projects where LAER

review is required. Unlike precipitators, fabr ic filter design is not based on any physical

properties of the flyash.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



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

The fabric filter is more effective at capturing fine particulate than an ESP because ESPs tend

to collect larger particles se lectively. Large particles have a high mass-to-surface area ratio,

which allows a charged particle to be dragge d efficiently through the flue gas stream for

collection on a grounded plate. Ul trafine particles have a low terminal velocity and cannot

carry a strong enough electrical charge to result in co mplete collection.

The fabric filter is also more effective at colle cting flyash generated fr om western low-sulfur

coals, such as those combusted at the Da ve Johnston station. ESPs operate by first

electrostatically charging for collection and then discharging the flyash particles for removal

in the ash-handling system. Western low-sulfur coal flyash has a very high electrical

resistivity, making it difficult for the ESP to first charge and then discharge the particles. One

solution attempted on western power plants is the use of a hotside precipitator that operates at

approximately 800oF, as opposed to the operatin g temperature of approximately 250°F used

on most ESPs. The electrical resi stivity of the flyash is lowe r at the higher temperature.

However, even with this change in operating temperature, the ESP is still less effective than

is the fabric filter at collecting flyash in west ern power plants. A fabric filter is also the

preferred particulate control device for use following a dry FGD system.

The existing Venturi particulate scrubb er at Dave Johnston 4 is achieving a PM 10 

# emission

rate of 0.061 lb per MMBtu. Replacing the scrubber with a fabric filter is projected to reduce

PM 10 

# 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 4

Control Technology Short-Term Expected PM 10 

# Emission Rate (pounds per

million British thermal units

Venturi Scrubber 0.061

Electrostatic Precipitator 0.030

Fabric Filter 0.015



# 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 addi tional pressure drop from the fabric

filter and associated ductwork. Therefore, a fabric filter retrofit will require an

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

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-17 

# A fabric filter at Dave Johnston 4 would re quire approximately 2.4 MW of power, equating

to an annual power usage of approximately 18.5 million kWh, based on a 90 percent annual

plant capacity factor.

Environmental Impacts. There are only minor negative environmental impacts from the

addition of a fabric filter, such as an increase in the amount of ash for disposal.

Economic Impacts. A summary of the costs and particul ate matter removed for the fabric

filter is provided in Table 3-6. The complete Economic Analysis is contained in Appendix A.

TABLE 3-6



# PM 10



# Control Cost Comparison

Dave Johnston 4

Factor Fabric Filter

Total Installed Capital Costs $50.1 million

Total First Year Fixed & Variable Operation and Maintenance

Costs $1.3 million

Total First Year Annualized Cost $6.0 million

Power Consumption (megawatts) 2.35

Annual Power Usage (kilowatt-hours per year) 18.5

Incremental Particulate Matter De sign Control Efficiency 75.4%

Incremental Tons Particulate Matter Removed per Year 744

First Year Average Control Cost

($/Ton of PM Removed) $8,133/ton

Incremental Control Cost

($/Ton of Particulate Matter Removed) $8,133/ton



# Preliminary BART Selection. CH2M HILL recommends replacemen t of the Venturi particulate

scrubber with a fabric filter downstream of the lime spray dryer as BART for

Dave Johnston 4, based on the significant reduction in PM 10 

# emissions, reasonable control

costs, and the advantages of minimal 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 a Gaussian puff dispersi on (CALPUFF) modeling sy stem to assess the

visibility impacts of emissions from Dave Johnston 4 at nearby Class I areas. The Class I

areas potentially affected are located more than 50 kilomete rs but less than 300 kilometers

from the Dave Johnston facility. These areas include:

• Wind Cave National Park

• Badlands National Park

The CALPUFF modeling system includes th e CALMET meteorological model, CALPUFF

with algorithms for chemical transformation a nd deposition, and a post processor capable of

calculating concentrations, visibility impact s, and deposition (CALPOST). The CALPUFF

modeling system was applied in a full, refine d mode. The following version numbers of the

various programs in the CALPUFF system were used by CH2M HILL:

• 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 kilometer. 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_DJ4_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 4



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

CALMET.inp file were used for CALMET. Ver tical resolution of the wind field included

10 layers, with vertical face heights 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 4

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.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-4 

# 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

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

website was used to convert the DATSAV3 f iles to CD-144 format for input into the

SMERGE preprocessor and CALMET.

Land use and terrain data were obtained from the U.S. Geological Survey (USGS). Land use

data were obtained in Composite Theme Grid format from the USGS, and the Level I USGS

land use categories were mapped into the 14 primary CALMET land use categories. Surface

properties such as albedo, Bowen ratio, roughne ss length, and leaf area index were computed

from the land use values. Terrain data were taken from USGS 1-degr ee Digital Elevation

Model data, which primarily 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 4



# 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-air weather maps from the National Oceanic and

Atmospheric Administration Central Library U.S. Daily Weat her Maps Project (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 provide d in the document titled BART Air Modeling Protocol—

Individual Source Visibility Assessments for BART Control Analyses (WDEQ-AQD, 2006).

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

over the modeling domain previously described. The CALPUFF model was 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 4.



# 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 WDEQ-AQD document BART Air Modeling

Protocol—Individual Source Visibility A ssessments for BART Control Analyses

(WDEQ-AQD 2006).



# 4.3.2 Stack Parameters

The stack parameters used for the baseline mode ling reflect those that are in place under the

current permit for Dave Johnston 4. Post-contro l stack parameters re flect the anticipated

changes associated with insta llation of the control technology alternativ es being evaluated.

The maximum heat input rate of 4,100 MMBtu per hour was used to calculate a maximum

emission rate. Measured veloci ties and stack flow rates were used in the modeling to

represent a worst- case situation.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# 4.3.3 Emission Rates

Pre-control emission rates for Dave Johnston 4 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 (particulate matter less th an 2.5 micrometers in aerodynamic diameter

[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 particulate matter control technologies

being evaluated. The selection of each contro l device was made based on the engineering

analyses performed in Section 3 for reasonabl e technologies that would meet or exceed the

presumptive BART levels for each pollutant.

• Scenario 1 : New LNB with OFA modi fications, a dry FGD system, and the replacement

of the Venturi particulate scrubber with a fabric filter downstream of the lime spray

dryer. As indicated previous ly, this scenario represents CH2M HILL’s preliminary

BART recommendation.

• Scenario 2 : New LNB with OFA modi fications, a wet FGD system, and replacement of

the Venturi particulate scrubbe r with a new fabric filter.

• Scenario 3 : New LNB with OFA modifications a nd SCR, a dry FGD system, and the

replacement of the Venturi particulate scrubb er with a new fabric filter downstream of

the lime spray dryer

.

• Scenario 4 : New LNB with OFA modifications and SCR, a wet FGD system, and

replacement of the Venturi particulate scrubber with a new fabric filter.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-7

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-8 

# Modeling of NO

x 

# , SO 2 

# , and particulate matter controls al one was not performed because any

final BART solution will include a comb ination of control technologies for NO

x 

# , SO 2 

# , and

particulate matter.

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

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.



# 4.3.5 Modeling Process

The CALPUFF modeling for the control techno logy options for Dave Johnston 4 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 BART “five-step” evaluation



# 4.3.6 Receptor Grids

Discrete receptors for the CALPUFF modeling 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.TABLE 4-2BART Model Input DataDave Johnston 4BaselinePost-control Scenario 1Post-control Scenario 2 Post-control Scenario 3 Post-control Scenario 4Existing Operations withVenturi ScrubberLow-NOxBurner (LNB) with OverFire Air (OFA), Dry Flue GasDesulfurization (FGD), Fabric FilterLNB with OFA, Wet FGD,Fabric FilterLNB with OFA and SelectiveCatalytic Reduction System(SCR), Dry FGD, Fabric FilterLNB with OFA and SCR, WetFGD, Fabric FilterSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])2,050 615 410 615 410Nitrogen Oxide (NOx) Stack Emissions (lb/hr)1,640615615287287PM10Stack Emissions (lb/hr)250 61.5 61.5 61.5 61.5Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)107.5 35.1 35.1 35.1 35.1Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)142.6 26.4 26.4 26.4 26.4Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 37.7 3.69 37.7 5.33 64.1H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 37.0 3.61 37.0 5.22 63.1Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)0.984.84(NH4)2SO4as SO4Stack Emissions (lb/hr)0.713.51(NH4)HSO4Stack Emissions (lb/hr)1.648.45(NH4)HSO4as SO4Stack Emissions (lb/hr)1.377.05Total Sulfate (SO4) (lb/hr)37.0 3.6 37.0 7.3 73.6Stack ConditionsStack Height (meters)76 152 152 152 152Stack Exit Diameter (meters)9.75 5.79 7.01 5.79 7.01Stack Exit Temperature (Kelvin)322 350 322 350 322Stack Exit Velocity (meters persecond)8.5325.7 16.5 25.7 16.5NOTES:(a)Based on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 72 percent scrubber and 57 percent baghouse.(b)Based on AP-42, Table 1.1-6, the fine particulates are counted as a percentage of PM10. This equates to 28 percent scrubber 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 4



# 4.4 CALPOST

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

output specified in deciview (dV) units. Calcul ations 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 back ground. 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 Me thod 6 was used to determine th e visibility impacts. Monthly

relative humidity factors [ f (RH)] were used in the light ex tinction calculations to account for

the hygroscopic characteristics of nitrate and sulfate particles. Table 5 of the Wyoming

BART Air Modeling Protocol (Appendix B) lists the monthly f (RH) factors for the Class I

areas. These values were used for the particular 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 dV values for the 10 percent best da ys for each Class I area, but did not provide

individual species concentration data for th e 20 percent best background conditions. Species

concentrations corresponding to the 20 percent best days were calculated for each 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 deri ved for each Class I area such that, when

multiplied by the Guidance table annual concentr ations, the 20 percent best days dV value

for that area would be calculate d. 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 Modeling Protocol (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.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-10

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 4-11 

# TABLE 4-3



# Average Natural Levels of Aerosol Components

Dave Johnston 4

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Wind Cave National Park and Badlands National

Park 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

NOTES:

Taken from Table 6 of the Wyom ing 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 4.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Dave Johnston 4 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-t he-art technology were inst alled on Dave Johnston 4.

Baseline (and post-control) 98 th 

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

Badlands National Park and Wind Cave Na tional Park 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 4TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasDave Johnston 4ModelingResultsScenarioFirst Year CostClass I AreaHighestVisibilityImpact-(deciview [dV])98thPercentileVisibilityImpact- (dV)No. of DaysAbove0.5 dVCost per DeltaDeciview(ΔdV)ReductionCost perReduction inNo. of DaysAbove0.5 dVIncremental CostperΔdVReductionIncremental Costper Reduction inNo. of Days Above0.5 dV2001Badlands3.6101.34750----Baseline: current operation with Venturi scrubberWind Cave4.3041.52747----$27,665,203Badlands1.2910.4566$31,049,611$628,755Scenario 1: Low-NOxBurner (LNB) with Over-Fire Air (OFA), dry flueGas Desulfurization (FGD), fabric filter$27,665,203Wind Cave1.7270.4677$26,099,248$691,630$35,381,111Badlands1.2320.4547$39,620,505$822,817$3,857,954,000n/aScenario 2: LNB with OFA, wet FGD, fabric filter$35,381,111Wind Cave1.6610.5519$36,251,138$931,082n/an/a$38,962,883Badlands0.9360.3264$38,161,492$847,019$27,982,594$1,193,924Scenario 3: LNB with OFA and Selective Catalytic Reduction System(SCR), dry FGD, fabric filter$38,962,883Wind Cave1.2590.3533$33,188,146$885,520$18,089,758$596,962$46,678,791Badlands0.9770.4094$49,764,170$1,014,756n/an/aScenario 4: LNB with OFA and SCR, wet FGD, fabric filter$46,678,791Wind Cave1.3060.4434$43,061,615$1,085,553n/an/a2002Badlands1.7471.10029----Baseline: current operation with Venturi scrubberWind Cave3.0521.34437----$27,665,203Badlands0.6980.3403$36,401,583$1,064,046Scenario 1: LNB with OFA,dry FGD, fabric filter$27,665,203Wind Cave0.8070.4657$31,473,496$922,173$35,381,111Badlands0.5540.3362$46,310,355$1,310,412$1,928,977,000$7,715,908Scenario 2: LNB with OFA, wet FGD, fabric filter$35,381,111Wind Cave0.9120.4605$40,023,881$1,105,660$1,543,181,600$3,857,954$38,962,883Badlands0.5250.2301$44,784,923$1,391,532$33,790,302$3,581,772Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$38,962,883Wind Cave0.5610.3473$39,080,123$1,145,967$31,697,097$1,790,886$46,678,791Badlands0.4460.2620$55,702,615$1,609,613n/a$7,715,908Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter$46,678,791Wind Cave0.6700.3393$46,446,558$1,372,906$964,488,500n/aJMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC4-12BART ANALYSIS FOR DAVE JOHNSTON UNIT 4JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC4-13TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasDave Johnston 4ModelingResultsScenarioFirst Year Cost Class I AreaHighestVisibilityImpact-(deciview [dV])98thPercentileVisibilityImpact- (dV)No. of DaysAbove0.5 dVCost per DeltaDeciview(ΔdV)ReductionCost perReduction inNo. of DaysAbove0.5 dVIncremental CostperΔdVReductionIncremental Costper Reduction inNo. of Days Above0.5 dV2003Badlands2.2741.44945----Baseline: current operation with Venturi scrubberWind Cave4.0092.07840----$27,665,203Badlands0.8640.4807$28,550,261$728,032Scenario 1: LNB with OFA,dry FGD, fabric filter$27,665,203Wind Cave1.5040.75110$20,847,930$922,173$35,381,111Badlands0.7400.4375$34,961,572$884,528$179,439,721$3,857,954Scenario 2: LNB with OFA, wet FGD, fabric filter$35,381,111Wind Cave1.3750.66310$25,004,319$1,179,370$87,680,773NA$38,962,883Badlands0.6520.3291$34,788,288$885,520$33,164,556$895,443Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$38,962,883Wind Cave1.1090.4927$24,566,761$1,180,693$20,946,035$1,193,924$46,678,791Badlands0.5990.3271$41,603,201$1,060,882$3,857,954,000NAScenario 4: LNB with OFA and SCR, wet FGD, fabric filter$46,678,791Wind Cave1.0840.5188$29,922,302$1,458,712NANA3-year averagesBadlands1.29941.3Baseline: current operation with Venturi scrubberWind Cave1.65041.3$27,665,203Badlands0.4255.3$31,677,713$768,478Scenario 1: LNB with OFA,dry FGD, fabric filter$27,665,203Wind Cave0.5618.0$25,412,005$829,956$35,381,111Badlands0.4094.7$39,768,952$964,939$472,402,531$11,573,862Scenario 2: LNB with OFA, wet FGD, fabric filter$35,381,111Wind Cave0.5588.0$32,410,178$1,061,433$2,571,969,333NA$38,962,883Badlands0.2952.0$38,820,541$990,582$31,419,053$1,343,165Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$38,962,883Wind Cave0.3974.3$31,112,230$1,053,051$22,293,187$976,847$46,678,791Badlands0.3331.7$48,321,730$1,176,776NA$23,147,724Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter$46,678,791Wind Cave0.4335.0$38,376,644$1,284,737NANANOTES:Sample Calculations: Cost per dV Reduction for Scenario1 for 2001: = $27,665,203 / (1.347 - 0.456) = $31,049,611Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $27,665,203 / (50 - 6) = $628,755

# 5.0 Preliminary Assessment and

Recommendations

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

modeling analysis for Dave Johnston 4, the pr eliminary recommended BART controls for

NO

x 

# , SO 2 

# , and PM 10 

# are as follows:

• 

# New LNBs and modifications to the OFA system for NO

x 

# control

• 

# Dry FGD for SO 2 

# control

• 

# New fabric filter for PM 10 

# 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, using a least-cost envelope, as outlined in the draft New Source

Review Workshop Manual—Prevention of Significant Deterioration and Nonattainment Area

Permitting (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 and 5- 2. A comparison of the incremental costs between

relevant scenarios is shown in Tables 5-3 and 5-4. The total annualized cost versus number of

days above 0.5 dV, and the tota l annualized cost versus 98 th 

# percentile Δ dV reduction are

shown in Figures 5-1 to 5- 4 for the two Class I areas.



# 5.1.1 Analysis Methodology

On page B-41 of the New Source Review Workshop Manual—Prevention of Significant

Deterioration and Nonattainment Area Permitting 

# , 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 were ranked in ascending

order of annualized total costs as shown in Tables 5-1 and 5-2. The incremental costeffectiveness data, expressed per day and per dV, 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 option scenarios were plotted for each

analysis. Figures 5-1 through 5- 4 present the two analyses (c ost per dV reduction and cost

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# per reduction in number of days above 0.5 dV) for each of the two Class I areas impacted by

the operation of Dave Johnston 4.

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

number of days above 0.5 dV. The EPA states that “in calculating in cremental costs, the

analysis should only be conducted for contro l options that are dominant among all possible

options.” In Figures 5-1 through 5-4, the dominant set of contro l options (Scenarios 1 and 3)

represent the least-cost envel ope depicted by the curvilinear line connecting them. Scenarios

2 and 4 are inferior options and should not be co nsidered in the derivation of incremental cost

effectiveness. Scenarios 2 and 4 represent infe rior controls, because Scenario 1 provides

approximately same amount of visibility imp act reduction for less cost than Scenario 2, and

similarly, Scenario 3 provides approximately th e same amount of visibility impact reduction

for less cost than Scenario 4. The incrementa l cost effectiveness is determined by the

difference in total annual costs between two contiguous scenarios di vided by the difference

in emissions reduction.

TABLE 5-1



# Badlands Class I Agent Control Data

Dave Johnston 4

Scenario Controls 98 th



# Percentile

Δ dV

Reduction Average

Number of

Days Above

0.5 Deciview

(dV) (Days) Total

Annualized

Cost

(Million$) Cost per

Δ dV

Reduction

(Million$

per Delta

Deciview

( Δ dV)

Reduced) Cost per

Reduction in

No. of Days

Above 0.5 dV

(Million$ per

Day Reduced)

Base Current Operation with

Venturi Scrubber 0.00 0.0 $0.0 $0.0 $0.0

1 Low-NO

x 

# Burner (LNB)

with Over-Fire Air (OFA),

DRY Flue Gas

Desulfurization (FGD),

New Fabric Filter 0.87 36.0 $27. 7 $31.7 $0.8

2 LNB with OFA, Wet

FGD, New Fabric Filter 0.89 36.7 $35. 4 $39.8 $1.0

3 LNB with OFA and

Selective Catalytic

Reduction System

(SCR), Dry FGD, New

Fabric Filter 1.00 39.3 $39. 0 $38.8 $1.0

4 LNB with OFA and SCR,

Wet FGD, New Fabric

Filter 0.97 39.7 $46. 7 $48.3 $1.2

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# TABLE 5-2



# Wind Caves Class I Area Control Data

Dave Johnston 4

Scenario Controls 98 th



# Percentile

Deciview

(dV)

Reduction Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualized

Cost

(Million$) Cost per dV

Reduction

(Million$ per

dV Reduced) Cost per

Reduction in

No. of Days

Above 0.5 dV

(Million$ per

Day Reduced)

Base Current Operation

with Venturi

Scrubber 0.00 0.0 $0.0 $0.0 $0.0

1 Low-NO

x

# Burner

(LNB) with OverFire Air (OFA),

DRY Flue Gas

Desulfurization

(FGD), Fabric Filter 1.09 33.3 $27. 7 $25.4 $0.8

2 LNB with OFA,

Wet FGD, New

Fabric Filter 1.09 33.3 $35. 4 $32.4 $1.1

3 LNB with OFA and

Selective Catalytic

Reduction System

(SCR), Dry FGD,

New Fabric Filter 1.25 37.0 $39. 0 $31.1 $1.1

4 LNB with OFA and

SCR, Wet FGD,

Fabric Filter 1.22 36.3 $46. 7 $38.4 $1.3

TABLE 5-3



# Badlands Class I Area Incremental Data

Dave Johnston 4

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$ per Day) Incremental Cost

Effectiveness

(Million$ per dV)

Baseline and Scenario 1 36.0 0.87 $0.8 $31.7

Scenario 1 and Scenario 2 0.7 0.02 $11.6 $472.4

Scenario 1 and Scenario 3 3.3 0.13 $3.4 $86.7

Scenario 1 and Scenario 4 3.7 0.09 $5.2 $205.2

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# TABLE 5-4



# Wind Caves Class I Agent Incremental Data

Dave Johnston 4

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$ per Days) Incremental Cost

Effectiveness

(Million$ per dV)

Baseline and Scenario 1 33.3 1.09 $0.8 $25.4

Baseline and Scenario 2 0.0 0.00 NA $2,572.0

Scenario 1 and Scenario 3 3.7 0.16 $3.1 $69.0

Baseline and Scenario 4 3.0 0.13 $6.3 $148.9

FIGURE 5-1



# Least-cost Envelope Badlands Class I Area Days Reduction

Dave Johnston 4

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 $40.0 $45.0 $50.0

0 5 10 15 20 25 30 35 40 45



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



# JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# FIGURE 5-2



# Least-cost Envelope Badlands Class I Area 98 th



# Percentile Reduction

Dave Johnston 4

Series 4

Baseline Scenario 1 Scenario 2 Scenario 3

$0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0 $40.0 $45.0 $50.0

0.00 0.20 0.40 0.60 0.80 1.00



# 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 4

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 $40.0 $45.0 $50.0

0 5 10 15 20 25 30 35 40



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



# JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4



# FIGURE 5-4



# Least-cost Envelope Badlands Class I Area 98 th



# Percentile Reduction

Dave Johnston 4

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 $40.0 $45.0 $50.0

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 $)



# 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 scenarios, whic h indicates a scenario with lower improvement

and/or higher costs. Scenario 3 is not selected as a result of very high incremental costs on

the basis of both a cost per day of improvement and a cost per dV reduction. Scenario 4 is

also not selected because it is to the left of the curve formed by the dominant control

alternative scenarios in three of the four categories plotted. This placement to the left of the

curve indicates a scenario with lower improveme nt and/or higher costs. While Scenario 3

provides some potential visibility advantage over Scenario 4, the projected improvement over

Scenario 1 is less than 0.2 dV and the cost increment is excessive.

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

Figures 5-1 and 5-2 illustrates the previously stated conclusi ons. 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 about $800,000 per day a nd $31.7 million per dV.

However, the incremental cost effectiveness for Scenario 3 compared to Scenario 1 is

excessive at $3.4 million per day and $86.7 million per dV. A similar conclusion is reached

for improving visibility at Wind Caves National Park using Table 5-4. Therefore, Scenario 1

represents BART for Dave Johnston 4.

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR DAVE JOHNSTON UNIT 4

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 5-7 

# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by the EPA for ta ngentially-fired boilers burning

sub-bituminous coal is 0.15 lb per MMBtu. Th e Dave Johnston 4 plant burns PRB coal, a

sub-bituminous coal.

CH2M HILL recommends LNBs with OFA (LNB with OFA) as BART for Dave Johnston 4,

based on the projected si gnificant reduction in NO

x 

# emissions, reasonable control costs, and

the advantages of no additional power requi rements or non-air quality environmental

impacts. This upgrade approach is proj ected to meet the BART presumptive NO

x 

# limit of

0.15 lb per MMBtu.



# 5.2.2 SO 2 

# Emission Control

CH2M HILL recommends a Dry FGD system as BART for Dave Johnston 4, 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.

This upgrade approach is projected to meet the BART presumptive SO 2 

# limit of 0.15 lb per

MMBtu.



# 5.2.3 PM 10



# Emission Control

CH2M HILL recommends replacement of the Ventur i particulate scrubber with a fabric filter

downstream of the lime spray dr yer as BART for Dave Johnst on 4, based on the significant

reduction in PM 10 

# emissions, reasonable control costs, and the advantages of minimal

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” by Dr. Ronald Henry (2002), state that onl y dV differences of approximately 1.5 to

2.0 dVs or more are perceivable by the human eye. The average person cannot distinguish

dV changes of less than 1.5. Therefore, the m odeling analysis result s indicate that only

minimal, if any, visibility improvements at th e Class I areas studied would be expected under

any of the scenarios. Thus, the results indicate that even though many millions of dollars will

be spent, only minimal visibi lity 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

several days and could have had a significant imp act of visibility in these Class I areas. If

natural obscuration were to reduce the visibi lity impacts modeled for the Dave Johnston 4

facility, it would increase the costs per deciview reduction that are presen ted 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_DJ4_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios2Index 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 CostN/A $ 27,665,203 N/A N/A N/AN/A $ 27,665,203 N/A N/A N/AN/A $ 35,381,111 N/A N/A N/AN/A $ 35,381,111 N/A N/A N/AN/A $ 38,962,883 N/A N/A N/AN/A $ 38,962,883 N/A N/A N/AN/A $ 46,678,791 N/A N/A N/AN/A $ 46,678,791 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 - N/ADave Johnston Unit 4Scenario 3 - LNB with OFA and SCR, WetFGD, Fabric Filter, New StackScenario 2 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 1 - LNB with OFA, Dry FGD,Fabric FilterBaseline - Current Operation with DryFGD, Fabric FilterWDK Unit 1WyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYDave Johnston Unit 4Boiler Design: Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGDw/Fabric FilterWet FGDw/Fabric FilterFabric FilterCase1 2 3 4 5 7 8 10NOx Emission Control SystemWindbox Mods. LNB w/OFA ROFALNB w/OFA &SNCRLNB w/OFA &SCR Windbox Mods. Windbox Mods. Windbox Mods.SO2 Emission Control SystemLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi Scrubber Dry FGD w/Fabric FilterWet FGD w/FabricFilterLime Added to VenturiScrubberPM Emission Control SystemVenturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Fabric FilterTOTAL INSTALLED CAPITAL COST ($)0 7,800,001 14,719,868 17,905,780 106,683,603 222,776,105 289,166,335 50,073,428FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 506,128 809,804 0Maintenance Material ($) 0 36,000 54,000 105,000 166,000 1,102,288 1,430,784 68,133Maintenance Labor ($) 0 54,000 81,000 157,500 249,000 734,858 953,856 102,199Administrative Labor ($) 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 90,000 135,000 262,500 415,000 2,343,273 3,194,444 170,331Makeup Water Cost 0 0 0 0 0 142,730 189,923 0Reagent Cost 0 0 0 611,037 293,591 789,014 583,010 0SCR Catalyst / FF Bag Cost 0 0 0 0 369,000 186,992 186,992 186,992Waste Disposal Cost 0 0 0 0 0 388,534 407,463 0Electric Power Cost 0 0 1,704,939 130,086 903,506 1,790,456 2,479,518 926,764TOTAL VARIABLE O&M COST0 0 1,704,939 741,123 1,566,098 3,297,727 3,846,906 1,113,756TOTAL FIRST YEAR O&M COST 0 90,000 1,839,939 1,003,623 1,981,098 5,641,000 7,041,350 1,284,088FIRST YEAR DEBT SERVICE ($)0 741,997 1,400,269 1,703,338 10,148,579 21,192,206 27,507,764 4,763,376TOTAL FIRST YEAR COST ($)0 831,997 3,240,208 2,706,961 12,129,677 26,833,206 34,549,114 6,047,464Power Consumption (MW) 0.0 0.0 4.3 0.3 2.3 4.5 6.3 2.4Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 34.1 2.6 18.1 35.8 49.6 18.5CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0% 62.5% 62.5% 70.0% 82.5% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 4,041 4,041 4,526 5,334 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 206 802 598 2,274 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 206 802 3,867 11,659 0 0 02-1 3-1 4-2 5-4SO2 Removal Rate (%)58.3% 0.0% 0.0% 0.0% 0.0% 70.0% 80.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 5,657 6,466 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 4,743 5,344 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 4,743 9,547 07-1 8-7PM Removal Rate (%) 98.82% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 75.41%PM Removed (Tons/Yr) 0 0 0 0 0 0 0 744First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 0 8,133Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 0 8,13310-1PRESENT WORTH COST ($)0 8,899,607 37,199,968 30,167,902 130,888,366 291,697,018 375,196,516 65,762,222PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls1 of 1INPUT CALCULATIONSDave Johnston Unit 4Boiler Design:Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/FabricFilterWet FGDw/Fabric FilterFabric FilterCase1 2 3 4 5 7 8 10NOx Emission Control SystemWindbox Mods. LNB w/OFA ROFALNB w/OFA &SNCR LNB w/OFA & SCRWindbox Mods. Windbox Mods. Windbox Mods.SO2 Emission Control SystemLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi ScrubberLime Added toVenturi ScrubberDry FGD w/Fabric FilterWet FGD w/FabricFilterLime Added to VenturiScrubberPM Emission Control SystemVenturi ScrubberVenturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi ScrubberFabric FilterUnit Design and Coal CharacteristicsType of UnitPC PC PC PC PC PC PC PCNet Power Output (kW)360,000360,000 360,000 360,000 360,000 360,000 360,000 360,000Net Plant Heat Rate (Btu/kW-Hr)11,39011,390 11,390 11,390 11,390 11,390 11,390 11,390Boiler FuelDry Fork PRBDry 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 7,784Coal Sulfur Content (wt.%)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%Boiler Heat Input, each (MMBtu/Hr)4,100 4,100 4,100 4,100 4,100 4,100 4,100 4,100Coal Flow Rate (Lb/Hr)526,773 526,773 526,773 526,773 526,773 526,773 526,773 526,773(Ton/Yr)2,076,539 2,076,539 2,076,539 2,076,539 2,076,539 2,076,539 2,076,539 2,076,539(MMBtu/Yr)32,327,55432,327,55432,327,55432,327,55432,327,55432,327,55432,327,55432,327,554EmissionsUncontrolled SO2 (Lb/Hr)4,920 2,050 2,050 2,050 2,050 2,050 2,050 2,050(Lb/MMBtu)1.20 0.50 0.50 0.50 0.50 0.50 0.50 0.50(Lb Moles/Hr)76.80 32.00 32.00 32.00 32.00 32.00 32.00 32.00(Tons/Yr)19,396 8,082 8,082 8,082 8,082 8,082 8,082 8,082SO2 Removal Rate (%)58.3%0.0%0.0%0.0%0.0%70.0%80.0%0.0%(Lb/Hr)2,870 0 0 0 0 1,435 1,640 0(Ton/Yr)11,314 0 0 0 0 5,657 6,466 0SO2 Emission Rate (Lb/Hr)2,050 2,050 2,050 2,050 2,050 615 410 2,050(Lb/MMBtu)0.500.50 0.50 0.50 0.500.15 0.100.50(Ton/Yr)8,082 8,082 8,082 8,082 8,082 2,425 1,616 8,082Uncontrolled NOx (Lb/Hr)1,640 1,640 1,640 1,640 1,640 1,640 1,640 1,640(Lb/MMBtu)0.400.40 0.40 0.40 0.40 0.40 0.40 0.40(Lb Moles/Hr)54.65 54.65 54.65 54.65 54.65 54.65 54.65 54.65(Tons/Yr)6,466 6,466 6,466 6,466 6,466 6,466 6,466 6,466NOx Removal Rate (%)0.0%62.5%62.5%70.0%82.5%0.0%0%0%(Lb/Hr)0 1,025 1,025 1,148 1,353 0 0 0(Lb Moles/Hr)0.00 34.16 34.16 38.26 45.09 0.00 0.00 0.00(Ton/Yr)0 4,041 4,041 4,526 5,334 0 0 0NOx Emission Rate (Lb/Hr)1,640 615 615 492 287 1,640 1,640 1,640(Lb/MMBtu)0.400.15 0.15 0.12 0.070.40 0.40 0.40(Ton/Yr)6,466 2,425 2,425 1,940 1,131 6,466 6,466 6,466Uncontrolled Fly Ash (Lb/Hr)21,113 250 250 250 250 250 250 250(Lb/MMBtu)5.149 0.061 0.061 0.061 0.061 0.061 0.061 0.061(Lb Moles/Hr)703.5 8.3 8.3 8.3 8.3 8.3 8.3 8.3(Tons/Yr)83,228 986 986 986 986 986 986 986Fly Ash Removal Rate (%)98.82%0.00%0.00%0.00%0.00%0.00%0.00%75.41%(Lb/Hr)20,863 0 0 0 0 0 0 189(Ton/Yr)82,242 0 0 0 0 0 0 744Fly Ash Emission Rate (Lb/Hr)250 250 250 250 250 250 250 62(Lb/MMBtu)0.0610.061 0.061 0.061 0.061 0.061 0.0610.015(Ton/Yr)986 986 986 986 986 986 986 242ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls1 of 2LNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/FabricFilterWet FGDw/Fabric FilterFabric FilterCase1 2 3 4 5 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 7,884Annual On-Site Power Plant Capacity Factor0.900.90 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%Discount Rate (%)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 20Installed Capital CostsNOx Emission Control System ($2006)07,800,001 14,719,868 17,905,780 106,683,603 0 0 0SO2 Emission Control System ($2006)00 0 0 0 222,776,105289,166,3350PM Emission Control System ($2006)00 0 0 0 0 0 50,073,428Total Emission Control Systems ($2006)0 7,800,001 14,719,868 17,905,780 106,683,603 222,776,105289,166,33550,073,428NOx Emission Control System ($/kW)0 22 41 50 296 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 619 803 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 139Total Emission Control Systems ($/kW)0 22 41 50 296 619 803 139Total Fixed Operating & Maintenance CostsOperating Labor ($)0 0 0 0 0 506,128 809,804 0Maintenance Material ($)0 36,000 54,000 105,000 166,000 1,102,288 1,430,78468,133Maintenance Labor ($)0 54,000 81,000 157,500 249,000 734,858 953,856 102,199Administrative Labor ($)00000 0 0 0Total Fixed O&M Cost ($)0 90,000 135,000 262,500 415,000 2,343,273 3,194,444170,331Annual Fixed O&M Cost Escalation Rate (%)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 0 248 330 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 142,730 189,923 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Lime Lime NoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 91.25 91.25 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.046 0.046 0.000Molar Stoichiometry0.00 0.00 0.00 0.45 1.00 1.10 1.02 0.00Reagent Purity (Wt.%)100%100%100%100%100%90%90%90%Reagent Usage (Lb/Hr)0 0 0 419 186 2,194 1,621 0First Year Reagent Cost ($)0 0 0 611,037 293,591 789,014 583,010 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000123 1,798 1,798 1,798SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000 104 104 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 369,000 186,992 186,992 186,992Annual SCR Catalyst / Bag Cost Esc. Rate (%)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 4,051 4,248 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 388,534 407,463 0Annual Waste Disposal Cost Esc. Rate (%)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%1.20%0.09%0.64%1.26%1.75%0.65%(MW)0.00 0.00 4.33 0.33 2.29 4.54 6.29 2.35Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 1,704,939 130,086 903,506 1,790,456 2,479,518 926,764Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.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/AUpgraded WetFGDFlue GasConditioning Fabric Filter4 Jim Bridger Unit 2Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter5 Jim Bridger Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter6 Jim Bridger Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/AUpgraded WetFGDFlue 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/AUpgraded WetFGDFlue 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)NetPlantHeatRate (Btu/kWHr) 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_PCorp DJ4 BART Economic Analysis_01-16-07.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 0.200 0.27 0.210.200.07 0.210.150.10N/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_PCorp DJ4 BART Economic Analysis_01-16-07.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$$ --None-5.22Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 98,000$ 147,000$ -$ -Urea 0.41 0.232 Dave Johnston Unit 4-$ 105,000$ 157,500$ $ - -Urea 0.45 0.333 Jim Bridger Unit 1-$ 123,000$ 184,500$ $ - -Urea 0.45 0.534 Jim Bridger Unit 2-$ 95,000$ 142,500$ $ - -Urea 0.45 0.535 Jim Bridger Unit 3-$ 122,000$ 183,000$ $ - -Urea 0.45 0.526 Jim Bridger Unit 4-$ 123,000$ 184,500$ $ - -Urea 0.45 0.537 Naughton Unit 1-$ 83,000$ 124,500$ $ - -Urea 0.45 0.168 Naughton Unit 2-$ 93,000$ 139,500$ $ - -Urea 0.51 0.229 Naughton Unit 3-$ 75,000$ 112,500$ $ - -Urea 0.45 0.3310 Wyodak Unit 1-$ 93,000$ 139,500$--Urea0.450.34Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.AnnualSCRCatalystReplace. (m3)Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 155,000$ 232,500$ -$ -Anhydrous NH31.00 1281.572 Dave Johnston Unit 4-$ 166,000$ 249,000$ $ - -Anhydrous NH31.00 1232.293 Jim Bridger Unit 1-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 1983.284 Jim Bridger Unit 2-$ 162,000$ 243,000$ $ - -Anhydrous NH31.00 1983.255 Jim Bridger Unit 3-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2003.226 Jim Bridger Unit 4-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2143.367 Naughton Unit 1-$ 132,000$ 198,000$ $ - -Anhydrous NH31.00 670.988 Naughton Unit 2-$ 160,000$ 240,000$ $ - -Anhydrous NH31.00 1011.349 Naughton Unit 3-$ 156,000$ 234,000$ $ - -Anhydrous NH31.00 1671.9910 Wyodak Unit 1-$ 181,000$ 271,500$$ --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_PCorp DJ4 BART Economic Analysis_01-16-07.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$$ -82Lime1.02-1.75Variable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsEY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur67 -0.0510 Wyodak Unit 1-$ -$ 10,000$--Elemental Sulfur63-0.05Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak Unit 1-$ 48,666$ 72,999$$ --None-1,7982.06Table 14 - Major Materials Design and Supply Costs2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3$ 3,221,912 $ 3,556,617 $ 5,773,000 $ 49,355,000 $ 83,871,000 $ 142,077,000 $ 108,865,669$ - $ 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_PCorp DJ4 BART Economic Analysis_01-16-07.xls5 of 5CAPITAL COSTDave Johnston Unit 4CaseNOx 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 $2,673,501Vendor $4,343,192Vendor $2,673,501Vendor $2,673,501Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$2,281,39985.3%$3,706,20985.3%$2,281,39985.3%$2,281,39985.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$1,381,99051.7%$2,245,08951.7%$1,381,99051.7%$1,381,99051.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$1,302,9580.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$354,19413.2%$575,40113.2%$354,19413.2%$354,19413.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$439,13616.4%$713,39016.4%$439,13616.4%$439,13616.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$326,66112.2%$530,67112.2%$326,66112.2%$326,66112.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal $7,456,882 $13,416,910 $7,456,882 $7,456,882 $0 $0 $0 $0 $0Contingency12.8%$343,11930.0%$1,302,95812.8%$343,11912.8%$343,11912.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $7,800,001 $14,719,868 $7,800,001 $7,800,001 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $7,171,085S&L Report $66,200,000 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%$1,434,21720.0%$13,240,00020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$401,0795.6%$3,702,5665.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$5,591,9148.4%$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%$79,0251.1%$729,5241.1%$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%$201,2922.8%$1,858,2342.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$819,08111.4%$7,561,36411.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $10,105,779 $98,883,602 $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 $0 S&L Report $137,267,000S&L Report $178,174,384S&L Report $0 S&L Report $30,853,530Contingency20.0%$020.0%$020.0%$020.0%$020.0%$020.0%$27,453,40020.0%$35,634,87720.0%$020.0%$6,170,706Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$05.6%$7,677,3435.6%$9,965,2935.6%$05.6%$1,725,638EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$08.4%$11,594,9438.4%$15,050,3908.4%$08.4%$2,606,198Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$3,862,6932.8%$5,013,8272.8%$02.8%$868,218Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$01.1%$1,512,6821.1%$1,963,4821.1%$01.1%$340,006Escalation10.1%$010.1%$010.1%$010.1%$010.1%$010.1%$13,876,32110.1%$18,011,64810.1%$010.1%$3,118,983Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$3,853,0852.8%$5,001,3552.8%$02.8%$866,059Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$011.4%$15,678,63711.4%$20,351,07811.4%$011.4%$3,524,090Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 $222,776,105 $289,166,335 $0 $50,073,428Fabric Filter8Windbox Mods.Fabric Filter10Windbox Mods.Lime Added to Venturi ScrubberWindbox Mods.Lime Added to Venturi ScrubberN/ADry FGD w/Fabric FilterN/ALNB w/OFA & SNCRSO2 ControlWet FGD w/Fabric FilterWet FGD w/Fabric FilterVenturi ScrubberLNB w/OFALime Added to Venturi ScrubberVenturi Scrubber Venturi ScrubberROFALime Added to Venturi ScrubberWindbox Mods.Dry FGD w/Fabric FilterParameterLNB w/OFA ROFA LNB w/OFA & SCRVenturi ScrubberWindbox Mods.N/AVenturi ScrubberLNB w/OFA & SNCRLime Added to Venturi ScrubberVenturi Scrubber Venturi ScrubberLNB w/OFA & SCRLime Added to Venturi ScrubberPM ControlN/ANOx Control45 76293EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls1 of 1Dave Johnston Unit 4LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 90,000------741,997831,9972062 2015 91,800------741,997833,7972063 2016 93,636------741,997835,6332074 2017 95,509------741,997837,5062075 2018 97,419------741,997839,4162086 2019 99,367------741,997841,3642087 2020 101,355------741,997843,3522098 2021 103,382------741,997845,3792099 2022 105,449------741,997847,44621010 2023 107,558------741,997849,55521011 2024 109,709------741,997851,70721112 2025 111,904------741,997853,90121113 2026 114,142------741,997856,13921214 2027 116,425------741,997858,42221215 2028 118,753------741,997860,75021316 2029 121,128------741,997863,12521417 2030 123,551------741,997865,54821418 2031 126,022------741,997868,01921519 2032 128,542------741,997870,53921520 2033 131,113------741,997873,110216Present Worth1,099,607------7,800,0018,899,607110(% of PW)12.4% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 87.6% 100.0%Dave Johnston Unit 4ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 135,000----1,704,9391,704,9391,400,2693,240,2088022 2015 137,700----1,739,0371,739,0371,400,2693,277,0068113 2016 140,454----1,773,8181,773,8181,400,2693,314,5418204 2017 143,263----1,809,2951,809,2951,400,2693,352,8278305 2018 146,128----1,845,4801,845,4801,400,2693,391,8788396 2019 149,051----1,882,3901,882,3901,400,2693,431,7108497 2020 152,032----1,920,0381,920,0381,400,2693,472,3398598 2021 155,073----1,958,4391,958,4391,400,2693,513,7808709 2022 158,174----1,997,6071,997,6071,400,2693,556,05088010 2023 161,337----2,037,5602,037,5601,400,2693,599,16689111 2024 164,564----2,078,3112,078,3111,400,2693,643,14490212 2025 167,856----2,119,8772,119,8771,400,2693,688,00191313 2026 171,213----2,162,2742,162,2741,400,2693,733,75692414 2027 174,637----2,205,5202,205,5201,400,2693,780,42693615 2028 178,130----2,249,6302,249,6301,400,2693,828,02994716 2029 181,692----2,294,6232,294,6231,400,2693,876,58495917 2030 185,326----2,340,5152,340,5151,400,2693,926,11097218 2031 189,033----2,387,3262,387,3261,400,2693,976,62798419 2032 192,813----2,435,0722,435,0721,400,2694,028,15499720 2033 196,670----2,483,7742,483,7741,400,2694,080,7121,010Present Worth1,649,410----20,830,69020,830,69014,719,86837,199,968460(% of PW)4.4% 0.0% 0.0% 0.0% 0.0% 56.0% 56.0% 39.6% 100.0%EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls1 of 4Dave Johnston Unit 4LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 262,500-611,037--130,086741,1231,703,3382,706,9615982 2015 267,750-623,258--132,688755,9461,703,3382,727,0346033 2016 273,105-635,723--135,341771,0651,703,3382,747,5086074 2017 278,567-648,438--138,048786,4861,703,3382,768,3916125 2018 284,138-661,406--140,809802,2161,703,3382,789,6926166 2019 289,821-674,635--143,625818,2601,703,3382,811,4196217 2020 295,618-688,127--146,498834,6251,703,3382,833,5816268 2021 301,530-701,890--149,428851,3181,703,3382,856,1866319 2022 307,561-715,928--152,416868,3441,703,3382,879,24263610 2023 313,712-730,246--155,465885,7111,703,3382,902,76164111 2024 319,986-744,851--158,574903,4251,703,3382,926,74964712 2025 326,386-759,748--161,746921,4941,703,3382,951,21765213 2026 332,913-774,943--164,981939,9241,703,3382,976,17565814 2027 339,572-790,442--168,280958,7221,703,3383,001,63266315 2028 346,363-806,251--171,646977,8961,703,3383,027,59766916 2029 353,290-822,376--175,079997,4541,703,3383,054,08367517 2030 360,356-838,823--178,5801,017,4031,703,3383,081,09868118 2031 367,563-855,600--182,1521,037,7521,703,3383,108,65368719 2032 374,915-872,712--185,7951,058,5071,703,3383,136,75969320 2033 382,413-890,166--189,5111,079,6771,703,3383,165,427699Present Worth3,207,186-7,465,564--1,589,3729,054,93617,905,78030,167,902333(% of PW)10.6% 0.0% 24.7% 0.0% 0.0% 5.3% 30.0% 59.4% 100.0%Dave Johnston Unit 4LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 415,000-293,591369,000-903,5061,566,09810,148,57912,129,6772,2742 2015 423,300-299,463376,380-921,5771,597,42010,148,57912,169,2992,2813 2016 431,766-305,453383,908-940,0081,629,36810,148,57912,209,7132,2894 2017 440,401-311,562391,586-958,8081,661,95610,148,57912,250,9362,2975 2018 449,209-317,793399,417-977,9841,695,19510,148,57912,292,9832,3056 2019 458,194-324,149407,406-997,5441,729,09910,148,57912,335,8712,3137 2020 467,357-330,632415,554-1,017,4951,763,68110,148,57912,379,6172,3218 2021 476,705-337,244423,865-1,037,8451,798,95410,148,57912,424,2382,3299 2022 486,239-343,989432,342-1,058,6021,834,93310,148,57912,469,7512,33810 2023 495,963-350,869440,989-1,079,7741,871,63210,148,57912,516,1742,34611 2024 505,883-357,886449,809-1,101,3691,909,06510,148,57912,563,5262,35512 2025 516,000-365,044458,805-1,123,3971,947,24610,148,57912,611,8252,36413 2026 526,320-372,345467,981-1,145,8651,986,19110,148,57912,661,0902,37414 2027 536,847-379,792477,341-1,168,7822,025,91510,148,57912,711,3402,38315 2028 547,584-387,388486,888-1,192,1582,066,43310,148,57912,762,5952,39316 2029 558,535-395,135496,625-1,216,0012,107,76210,148,57912,814,8762,40217 2030 569,706-403,038506,558-1,240,3212,149,91710,148,57912,868,2022,41218 2031 581,100-411,099516,689-1,265,1272,192,91510,148,57912,922,5942,42319 2032 592,722-419,321527,023-1,290,4302,236,77310,148,57912,978,0752,43320 2033 604,577-427,707537,563-1,316,2382,281,50910,148,57913,034,6642,444Present Worth5,070,409-3,587,0584,508,388-11,038,90919,134,354106,683,603130,888,3661,227(% of PW)3.9% 0.0% 2.7% 3.4% 0.0% 8.4% 14.6% 81.5% 100.0%EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls2 of 4Dave Johnston Unit 4Dry FGD w/Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 2,343,273142,730789,014186,992388,5341,790,4563,297,72721,192,20626,833,2064,7432 2015 2,390,139145,585804,795190,732396,3041,826,2663,363,68121,192,20626,946,0264,7633 2016 2,437,942148,497820,891194,546404,2301,862,7913,430,95521,192,20627,061,1034,7834 2017 2,486,701151,467837,308198,437412,3151,900,0473,499,57421,192,20627,178,4804,8045 2018 2,536,435154,496854,055202,406420,5611,938,0483,569,56521,192,20627,298,2064,8256 2019 2,587,163157,586871,136206,454428,9721,976,8093,640,95721,192,20627,420,3264,8477 2020 2,638,907160,738888,558210,583437,5522,016,3453,713,77621,192,20627,544,8884,8698 2021 2,691,685163,952906,330214,795446,3032,056,6723,788,05121,192,20627,671,9424,8919 2022 2,745,518167,231924,456219,091455,2292,097,8053,863,81221,192,20627,801,5374,91410 2023 2,800,429170,576942,945223,473464,3342,139,7613,941,08921,192,20627,933,7234,93811 2024 2,856,437173,987961,804227,942473,6202,182,5564,019,91021,192,20628,068,5544,96112 2025 2,913,566177,467981,040232,501483,0932,226,2074,100,30921,192,20628,206,0814,98613 2026 2,971,837181,0171,000,661237,151492,7552,270,7324,182,31521,192,20628,346,3585,01114 2027 3,031,274184,6371,020,674241,894502,6102,316,1464,265,96121,192,20628,489,4415,03615 2028 3,091,900188,3301,041,088246,732512,6622,362,4694,351,28021,192,20628,635,3865,06216 2029 3,153,738192,0961,061,910251,667522,9152,409,7194,438,30621,192,20628,784,2505,08817 2030 3,216,812195,9381,083,148256,700533,3732,457,9134,527,07221,192,20628,936,0905,11518 2031 3,281,149199,8571,104,811261,834544,0412,507,0714,617,61421,192,20629,090,9685,14219 2032 3,346,772203,8541,126,907267,071554,9222,557,2134,709,96621,192,20629,248,9435,17020 2033 3,413,707207,9311,149,445272,412566,0202,608,3574,804,16521,192,20629,410,0785,199Present Worth28,629,7721,743,8589,640,0622,284,6414,747,04621,875,53440,291,141222,776,105291,697,0182,578(% of PW)9.8% 0.6% 3.3% 0.8% 1.6% 7.5% 13.8% 76.4% 100.0%Dave Johnston Unit 4Wet 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 3,194,444189,923583,010186,992407,4632,479,5183,846,90627,507,76434,549,1145,3442 2015 3,258,333193,722594,670190,732415,6122,529,1083,923,84427,507,76434,689,9415,3653 2016 3,323,499197,596606,564194,546423,9242,579,6914,002,32127,507,76434,833,5855,3884 2017 3,389,969201,548618,695198,437432,4032,631,2844,082,36827,507,76434,980,1015,4105 2018 3,457,769205,579631,069202,406441,0512,683,9104,164,01527,507,76435,129,5485,4336 2019 3,526,924209,691643,690206,454449,8722,737,5884,247,29527,507,76435,281,9835,4577 2020 3,597,463213,885656,564210,583458,8692,792,3404,332,24127,507,76435,437,4685,4818 2021 3,669,412218,162669,695214,795468,0472,848,1874,418,88627,507,76435,596,0625,5069 2022 3,742,800222,526683,089219,091477,4082,905,1514,507,26427,507,76435,757,8285,53110 2023 3,817,656226,976696,751223,473486,9562,963,2544,597,40927,507,76435,922,8295,55611 2024 3,894,009231,516710,686227,942496,6953,022,5194,689,35727,507,76436,091,1305,58212 2025 3,971,889236,146724,900232,501506,6293,082,9694,783,14427,507,76436,262,7985,60913 2026 4,051,327240,869739,398237,151516,7613,144,6284,878,80727,507,76436,437,8985,63614 2027 4,132,354245,686754,186241,894527,0973,207,5214,976,38327,507,76436,616,5015,66315 2028 4,215,001250,600769,269246,732537,6383,271,6715,075,91127,507,76436,798,6765,69216 2029 4,299,301255,612784,655251,667548,3913,337,1055,177,42927,507,76436,984,4945,72017 2030 4,385,287260,724800,348256,700559,3593,403,8475,280,97827,507,76437,174,0295,75018 2031 4,472,993265,939816,355261,834570,5463,471,9245,386,59727,507,76437,367,3545,77919 2032 4,562,452271,257832,682267,071581,9573,541,3625,494,32927,507,76437,564,5465,81020 2033 4,653,702276,683849,335272,412593,5963,612,1905,604,21627,507,76437,765,6815,841Present Worth39,029,2462,320,4567,123,1302,284,6414,978,32030,294,38747,000,934289,166,335375,196,5162,902(% of PW)10.4% 0.6% 1.9% 0.6% 1.3% 8.1% 12.5% 77.1% 100.0%EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls3 of 4Dave Johnston Unit 4Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 170,331--186,992-926,7641,113,7564,763,3766,047,4648,1332 2015 173,738--190,732-945,2991,136,0314,763,3766,073,1468,1683 2016 177,213--194,546-964,2051,158,7524,763,3766,099,3418,2034 2017 180,757--198,437-983,4901,181,9274,763,3766,126,0608,2395 2018 184,372--202,406-1,003,1591,205,5664,763,3766,153,3148,2766 2019 188,060--206,454-1,023,2231,229,6774,763,3766,181,1138,3137 2020 191,821--210,583-1,043,6871,254,2704,763,3766,209,4678,3518 2021 195,657--214,795-1,064,5611,279,3564,763,3766,238,3898,3909 2022 199,570--219,091-1,085,8521,304,9434,763,3766,267,8898,43010 2023 203,562--223,473-1,107,5691,331,0424,763,3766,297,9808,47011 2024 207,633--227,942-1,129,7201,357,6634,763,3766,328,6728,51212 2025 211,786--232,501-1,152,3151,384,8164,763,3766,359,9788,55413 2026 216,021--237,151-1,175,3611,412,5124,763,3766,391,9108,59714 2027 220,342--241,894-1,198,8681,440,7624,763,3766,424,4808,64015 2028 224,749--246,732-1,222,8461,469,5784,763,3766,457,7038,68516 2029 229,244--251,667-1,247,3031,498,9694,763,3766,491,5898,73117 2030 233,829--256,700-1,272,2491,528,9494,763,3766,526,1538,77718 2031 238,505--261,834-1,297,6941,559,5284,763,3766,561,4098,82519 2032 243,275--267,071-1,323,6471,590,7184,763,3766,597,3708,87320 2033 248,141--272,412-1,350,1201,622,5324,763,3766,634,0498,922Present Worth2,081,084--2,284,641-11,323,06913,607,71050,073,42865,762,2224,422(% of PW)3.2% 0.0% 0.0% 3.5% 0.0% 17.2% 20.7% 76.1% 100.0%EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls4 of 4EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 1 of 1First Year Cost for Air Pollution Control Options05,000,00010,000,00015,000,00020,000,00025,000,00030,000,00035,000,00040,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRDry FGD w/FabricFilterWet FGDw/Fabric FilterFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options050,000,000100,000,000150,000,000200,000,000250,000,000300,000,000350,000,000400,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRDry FGD w/FabricFilterWet FGDw/Fabric FilterFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B 

# 2006 Wyoming BART Protocol