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 and Best Available Retrofit Technology (BART) 

regulations and guidelines, CH2M 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 (NOx), 

sulfur dioxide (SO2), and particulate matter less than 10 micrometers in aerodynamic 

diameter (PM10). The Dave Johnston Station consists of four units with a total generating 

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

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

Johnston 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 (SIP) is approved by the EPA, and a compliance 

date of 2014 was assumed for this analysis. 

In completing the BART analysis, technology alternatives were investigated and potential 

reductions in NOx, SO2, and PM10 emissions rates were identified. The following technology 

alternatives were investigated, listed below by pollutant: 

• NOx emission controls: 

− Low-NOx burners (LNBs) with over-fire air (OFA) 

− Rotating opposed fire air (ROFA) 

− LNBs with selective non-catalytic reduction system (SNCR) 

− LNBs burners with selective catalytic reduction (SCR) system 

• SO2 emission controls: 

− Lime spray drying flue gas desulfurization (dry FGD) system 

− Wet FGD system 

• PM10 emission controls: 

− Electrostatic precipitator (ESP) 

− Fabric filter 

BART Engineering Analysis 

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

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

• The identification of available, technically feasible, retrofit 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 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

• The remaining useful life of the facility 

• The energy and non-air quality environmental 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, technically feasible, retrofit control options 

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

the applicability of options and their impacts) 

• Step 3 – Evaluate Control Effectiveness 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 environmental impacts of compliance 

• Step 5 – Evaluate Visibility Impacts 

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

use of BART 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs included 

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

2014 BART implementation date. 

Recommendations 

NOx Emission Control 

The BART presumptive NOx limit assigned by the EPA for tangentially-fired boilers burning 

sub-bituminous coal is 0.15 pound (lb) per million 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 NOx emissions, reasonable control costs, and the 

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

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

SO2 Emission Control 

CH2M HILL recommends a new dry FGD system as BART for Dave Johnston 4, based on 

the significant reduction in SO2 emissions, reasonable control costs, and the advantages of 

minimal additional power requirements and minimal 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 SO2 limit of 0.15 lb per 

MMBtu. 

PM10 Emission Control 

CH2M HILL recommends replacement 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 PM10 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 installing LNBs with OFA, a new lime spray drying 

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

downstream of the lime spray dryer, are identified as Scenario 1 throughout this report. 

BART Modeling Analysis 

CH2M HILL used the CALPUFF modeling system 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 the following national parks: 

• Wind Cave National Park 

• Badlands National Park 

Because Dave Johnston 4 will simultaneously control NOx, SO2, and PM10 emissions, four 

post-control atmospheric dispersion modeling scenarios were developed to cover the range of 

effectiveness for combining the individual NOx, SO2, and PM10 control technologies under 

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

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

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

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

BART recommendation. 

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

the Venturi particulate scrubber with a new fabric filter. 

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

replacement of the Venturi particulate scrubber 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. 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC ES-4

 

Visibility improvements for all emission control 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 Envelope Analysis Methodology as an accepted 

methodology for selecting the most reasonable, cost-effective controls. Incremental 

cost-effectiveness comparisons focus on annualized cost and emission reduction differences 

between dominant alternatives. The dominant set of control alternatives is determined by 

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

total annualized costs for a total emissions reductions for all control alternatives identified in 

the BART analysis. 

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

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

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

costs between relevant scenarios for the two Class I areas; the total annualized cost versus 

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

delta-deciview (ΔdV) reduction. 

Results of the least-cost envelope analysis validate the selection of Scenario 1, based on 

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

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

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

higher costs. Scenario 3 (LNB with OFA and SCR, dry FGD and 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 that demonstrate only dV differences 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 improvements at the Class I areas studied would 

be expected under any of the control scenarios. Thus, the results 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 visibility 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 NOx Analysis.................................................................... 3-2 

3.2.2 BART SO2 Analysis .................................................................. 3-10 

3.2.3 BART PM10 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 NOx Emission Control ................................................................. 5-7 

5.2.2 SO2 Emission Control.................................................................. 5-7 

5.2.3 PM10 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 NOx Control Technology Emission Rate Ranking 

3-2 NOx Control Cost Comparison 

3-3 SO2 Control Technology Emission Rate Ranking 

3-4 SO2 Control Cost Comparison 

3-5 PM10 Control Technology Emission Rates 

3-6 PM10 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 NOx Air Pollution Control Options 

3-2 First Year Control Cost for SO2 Air Pollution Control Options 

4-1 Dave Johnston Source-specific Class 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 98th Percentile Reduction 

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

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

Appendices 

A Economic Analysis 

B 2006 Wyoming BART Protocol 
Acronyms and Abbreviations 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CALDESK Program to display data and results 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing Program for Calculating Visibility Impacts 

CALPUFF Gaussian Puff Dispersion Model 

CO Carbon Monoxide 

oF Degrees Fahrenheit 

dV Deciview 

ΔdV 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-NOx 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 

N2 Nitrogen 

(NH4)2SO4 Ammonium Sulfate 

(NH4)HSO4 Ammonium Bisulfate 

NO2 Nitrogen Dioxide 

NOx 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 

PM2.5 Particulate Matter Less than 2.5 Micrometers in Aerodynamic Diameter 

PM10 Particulate Matter Less than 10 Micrometers 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 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

USGS U.S. Geological Survey 

WDEQ Wyoming Department of Environmental Quality 

WDEQ-AQD Wyoming Department of Environmental Quality—Air Quality Division 
1.0 Introduction 

Best Available Retrofit Technology (BART) guidelines were established 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 provide guidance for states when determining 

which facilities must install additional controls, and the type of controls that must be used. 

Facilities eligible for BART installation were built between 1962 and 1977, and have the 

potential to emit more than 250 tons per year of visibility-impairing pollutants. 

The Wyoming Department of Environmental Quality (WDEQ) BART regulations state that 

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

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

report for Dave Johnston Unit 4 (hereafter referred 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 formally 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 issue of emissions for the identified facilities: 

• Any existing pollution control technology in use at the source 

• The cost of the controls 

• The remaining useful life of the source 

• The energy and non-air quality environmental 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 (NOx), sulfur 

dioxide (SO2), and particulate matter less than 10 micrometers in aerodynamic diameter 

(PM10), because they are the primary criteria pollutants that affect visibility. 

Section 2 of this report provides a description of the present 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 methodology and results of the BART 

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

Section 6. Appendices provide more detail 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 (MW) pulverized coal unit located in central 

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

manufactured by Combustion Engineering (now Alstom). Concentric-firing low-NOx burners 

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

added to the scrubber liquor to achieve approximately 50-percent reduction in SO2. Table 2-1 

lists additional unit information and 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 Powder 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 analysis is based on a 20-year life for BART control 

technologies. Assuming a BART implementation 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-related equipment. This report does not attempt to quantify 

any additional life extension costs needed to allow Dave Johnston 4 to operate until 2034. 

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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 Factor (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 NOx Controls Concentric Firing Low NOx Burners 

NOx Emission Rate(pounds per million Btu)(b) 0.40 

Current Sulfur Dioxide Controls Venturi Scrubber with lime injection 

SO2 Emission Rate (pounds per million Btu)** 0.50 

Current PM10 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)PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter (d)Emission rate stated from test results 
JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 

TABLE 2-2 Coal Sources and Characteristics Dave Johnston 4 

Ultimate Analy

Mines 

Moisture 

(%) 

Ash 

(%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

units 

per 

pound 

(Btu/lb) 

Sulfur 

(%) 

Moisture 

and Ash 

Free 

(Btu/lb) Hydrogen Carbon Sulfu

Clovis Point Mine 32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.99 67.3 0.87 Maximum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.58 69.5 1.07 Minimum 29.9 4.5 30.0 29.0 7,901 0.36 12,744 3.82 64.4 0.63 Dry Fork Mine 32.1 5.2 29.5 33.0 8,036 0.39 12,818 4.56 68.7 0.57 Maximum 30.7 4.5 39.1 42.7 8,200 0.54 12,924 5.04 71.3 0.76 Minimum 33.2 7.8 28.9 31.9 7,650 0.26 12,726 4.07 65.8 0.34 Rawhide Mine 30.4 5.3 30.4 33.9 8,285 0.37 12,875 4.63 69.4 0.50 Maximum 31.6 6.6 32.7 37.1 8,480 0.53 13,000 5.41 71.1 0.63 Minimum 29.0 4.5 29.5 31.7 8,120 0.21 12,575 4.31 66.3 0.39 Other Northern PRB 30.1 5.9 30.8 33.2 8,122 0.39 12,843 4.73 68.4 0.65 Maximum 32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.99 67.3 0.87 Minimum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.58 69.5 1.07 
3.0 BART Engineering Analysis 

This section presents the required 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 analysis 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, technically feasible, retrofit 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 environmental impacts of compliance 

• The degree of visibility improvement that 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, technically feasible, retrofit control options 

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

the applicability of options and their impacts) 

• Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

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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 environmental 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, consideration was made of any pollution control 

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

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

control devices. In some cases, enhancing the performance of the existing control equipment 

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

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs included 

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

2014 BART implementation date. 

3.2.1 BART NOx Analysis 

NOx formation in coal-fired boilers is a complex process depends on a number of variables, 

including operating conditions, equipment design, and coal characteristics. 

Formation of NOx

During coal combustion, NOx forms in three ways. The dominant source of NOx formation is 

the oxidation of fuel-bound nitrogen. 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 partially oxidized to nitrogen oxides (nitric 

oxide and nitrogen dioxide) and partially reduced to molecular nitrogen (N2). A smaller part 

of NOx formation is caused by high temperature fixation of atmospheric nitrogen in the 

combustion air (thermal NOx). A very small amount of NOx is called prompt NOx. Prompt 

NOx results from an interaction of hydrocarbon radicals, nitrogen, and oxygen. 

In a conventional pulverized coal burner, air is introduced with turbulence to promote good 

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

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

NOx. 

Coal characteristics directly and significantly affect NOx 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-bituminous to bituminous and on to anthracite. Lower 

rank coals, such as the sub-bituminous coals from the PRB, produce lower NOx 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 content, and rank are good 

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

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

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

with low-NOx burners (LNBs), sub-bituminous coals create a longer time for the kinetics to 

promote more stable molecular nitrogen, therefore resulting in lower NOx emissions. 

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

and low NOx production characteristics previously described. Based on data from the Energy 

Information Administration (EIA), PRB coals currently 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 and sub-bituminous coals are presumed to use 

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

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

facility. 

The BART Analysis for Dave Johnston 4 NOx emissions is described in the following 

section. 

Step 1: Identify All Available Retrofit Control Technologies 

The first step of the BART process is to evaluate NOx control technologies with practical 

potential for application to Dave Johnston 4, including those control technologies identified 

as Best Available Control Technology (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 potentially applicable emission-control technologies. 

Dave Johnston 4 NOx emissions are currently controlled through the use of good combustion 

practices and over-fire air (OFA). 

The following potential NOx control technology options were considered: 

• New/modified LNB with advanced OFA 

• Mobotec Rotating Opposed Fire Air (ROFA) 

• Conventional selective non-catalytic reduction (SNCR) system 

• Selective catalytic reduction (SCR) system 

Step 2: Eliminate Technically Infeasible Options 

For Dave Johnston 4, a tangential-fired burner configuration burning sub-bituminous coal, 

technical feasibility will primarily be determined by physical constraints, boiler configuration, 

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

0.15 pound (lb) of NOx per Million British Thermal Units (MMBtu). Dave Johnston 4’s 2003 

to 2005 NOx emission rate averaged 0.40 lb per MMBtu. 

For this BART analysis, information pertaining 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 ammonia, 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 NOx to nitrogen and water. NOx reductions of up to 60 percent have been 

achieved, although 20 to 40 percent is more realistic for most applications. SNCR is typically 

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

problematic. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

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

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

inherent uncertainties. 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 proposals must be qualified, and it 

must be recognized that contractual guarantees are established only after more detailed analysis 

has been completed. The following subsections describe the control technologies and the control 

effectiveness evaluated in this BART analysis. 

New LNBs with OFA System. The mechanism used to lower NOx with LNBs is to stage the 

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

combustion is not diverted to combine with nitrogen and form NOx. Fuel-rich conditions favor 

the conversion of fuel nitrogen to N2 instead of NOx. Additional air (or OFA) is then introduced 

downstream in a lower temperature zone to burn out the char. 

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

proposes to install their latest combustion-based NOx 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 NOx reductions. In addition to new LNBs, the system includes the addition of two 

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

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

dampers, and actuators. 

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

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

in an expected NOx emission rate of 0.15 lb per MMBtu. PacifiCorp has indicated that this 

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

emission rate can be sustained as an average between overhauls. This emission rate 

represents a reduction of 62 percent from the 2003 to 2005 average NOx emission rate, and is 

equivalent to the presumptive NOx emission rate of 0.15 lb per MMBtu for tangential fired 

boilers burning sub-bituminous coal. 

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

volume of the furnace is set in rotation by asymmetrically placed air nozzles located in 

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

laminar flow, so that the entire volume of the 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 ROFA system works in 

conjunction with and is dependant on the overall 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, and fuel quality data furnished to Mobotec by CH2M HILL, 

Mobotec has stated that they do not believe that burner modifications or burner replacements 

are required. In their proposal, Mobotec has stated a guaranteed NOx 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 technically feasible and provide expected or guaranteed emission 

rates; however, they include inherent uncertainties. 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 reduction is generally used to achieve modest NOx reductions 

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

urea—is injected into the furnace within a temperature range of 1,600°F to 2,100°F, where it 

reduces NOx to nitrogen and water. NOx reductions of up to 60 percent have been achieved, 

although 20 to 40 percent is more realistic for most applications. 

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NOx, 

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 ammonia to create problems 

downstream. The ammonia may render fly ash unsaleable, react with sulfur 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 NOx reduction generally resulting in 

lower reagent utilization and higher operating cost. 

Reductions from higher baseline concentrations (inlet NOx) 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 modifications including LNBs and advanced OFA, 

capable of achieving a projected NOx emission rate of 0.15 lb per MMBtu. At a further 

reduction of 20 percent in NOx, emission rates for SNCR would 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 NOx to nitrogen and 

water. Unlike the high temperatures required 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 configuration 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 catalyst to increase flue gas residence time. As a 

result of the higher removal rate, 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 NOx 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 NOx 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 

NOx emission rate of 0.07 lb per MMBtu. Additional catalyst surface was included in the 

SCR design to accommodate the quality characteristics of the PRB coal used at 

Dave Johnston 4. 

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

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

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

review, it was noted that NOx emissions can vary significantly around an average emissions 

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

load, boiler operation including excess 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 NOx emissions value from vendor 

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

3. Review and evaluate unit physical and operational characteristics and restrictions (the 

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

NOx emissions are) 

4. For each technology expected value, there is a corresponding potential for actual NOx

emissions to vary from this expected value (from the vendor information presented, along 

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

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

with projected NOx emission rates. 

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

TABLE 3-1 

NOx Control Technology Emission Rate Ranking 

Dave Johnston 4 

Technology Projected Emission Rate (pounds 

per million British thermal unit) 

Presumptive BART Limit 0.15 

Low-NOx 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 consideration 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 systems 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 gas fan systems due to the additional pressure 

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

costs—for fan upgrades and additional 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 estimated at approximately 2,290 kW, based on the 2002 

S&L Report. 

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

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

same or lower than previous levels for the ROFA system. 

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

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

visibility improvements. Other environmental impacts involve the storage of ammonia, 

especially if anhydrous ammonia is used, and the 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 proprietary database, and 

supplemented (as needed) by vendor-obtained price 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 NOx removed is summarized in Table 3-2, and the first year control costs in Figure 3-1. 

The complete Economic Analysis is contained in Appendix A. 

TABLE 3-2 

NOx Control Cost Comparison 

Dave Johnston 4 

Factor 

Low-NOx

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 million $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 million $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 

NOx Design Control Efficiency 62.5% 62.5% 70.0% 82.5% 

NOx Removed per Year (Tons) 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 NOx emissions, reasonable control cost, 

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

to meet the applicable EPA presumptive 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 A

FIGURE 3-1 First Year Control Cost for NOx Air Pollution Control Options 

Dave Johnston 4 

0

2,0004,0006,0008,000

10,00012,00014,000

LNB w/OFA ROFA LNB w/OFA & SNCR 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 
BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

3.2.2 BART SO2 Analysis 

SO2 forms in the boiler during the combustion process, and is primarily dependent on coal 

sulfur content. The BART analysis for SO2 emissions on Dave Johnston 4 is described 

below. 

Step 1: Identify All Available Retrofit Control Technologies 

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

applicable emission control technologies for SO2 at Dave Johnston 4; this included control 

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

The following potential SO2 control technology options were considered: 

• Dry flue gas desulfurization (FGD) with new fabric filter 

• Wet FGD with new fabric filter 

Step 2: Eliminate Technically Infeasible Options 

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

to this unit) of 95 percent reduction in SO2 emissions, or 0.15 lb per MMBtu. Dave 

Johnston 4 currently has an uncontrolled SO2 emission rate of 1.20 lbs per MMBtu. 

Therefore, 87.5 percent SO2 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 rapid speed of the atomizer wheel causes the lime 

slurry to separate into very fine droplets that intermix with the flue gas. The SO2 in the flue 

gas reacts with the calcium in the lime slurry to form calcium sulfate in the form of 

particulate matter. At Dave Johnston 4, this dry 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 SO2 removal. At Dave 

Johnston 4, this is projected to result in a controlled SO2 emission rate of 0.15 lb per MMBtu 

based on an average coal sulfur content of 0.47 percent by weight. Therefore, this option 

would meet the presumptive limit of 0.15 lb per MMBtu. 

Wet FGD. Wet SO2 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 across the scrubber vessel. The calcium in the 

reagent reacts with the SO2 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 calcium sulfate sludge is 

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

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

developers. These variations include using a jet bubbling reactor as a combination SO2

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 SO2 removal), which would meet the presumptive limit of 

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

new wet FGD system to achieve a 95 percent SO2 removal (0.06 lb per MMBtu) on a 

continuous basis. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

When evaluating the control effectiveness of SO2 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 point of reference. As indicated previously, 

the presumptive limit for SO2 on a BART-eligible coal-burning unit is 95 percent removal, or 

0.15 lb per MMBtu. 

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

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

capable of meeting the presumptive SO2 limit of 0.1 lb per MMBtu. 

TABLE 3-3 

SO2 Control Technology Emission Rate Ranking 

Dave Johnston 4 

Control Technology Short-Term Expected SO2

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 consideration 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 power 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 (SO3) in the flue gas, which condenses to liquid 

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

spray dryer system. Wet scrubbers capture less than 40 to 60 percent of SO3 and may 

require the addition of a wet electrostatic precipitator (ESP) or hydrated lime injection 

when medium to high sulfur coal is burned in a unit to remove the balance of SO3. 

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 system 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 flue 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 loop. In some cases, a wastewater treatment 

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

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

contaminated with toxic metals (including mercury), requiring proper disposal. 

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

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

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

gypsum market is available, reducing the quantity 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 water in the absorber. Given 

that water is a valuable commodity in western 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 SO2 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 

SO2 Control Cost Comparison 

Dave Johnston 4 

Factor 

Dry Flue Gas Desulfurization 

(FGD) with Fabric Filter Wet 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 SO2 emissions, reasonable control 

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

quality environmental impacts. This upgrade approach is projected to meet the 

BART-presumptive SO2 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 A

FIGURE 3-2 First Year Control Cost for SO2 Air Pollution Control Options 

Dave Johnston 4 

0

2,0004,0006,0008,000

10,00012,000

Dry FGD w/Fabric Filter Wet FGD w/Fabric Filter

Air Pollution Control Option

Control Cost ($/Ton SO2 Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 
BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

3.2.3 BART PM10 Analysis 

Dave Johnston 4 is equipped with a Venturi particulate scrubber. Venturi scrubbers operate 

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

high-pressure water spray forces the polluted gas stream through a constricted throat. Like 

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

Venturi scrubber becomes less effective as a control 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 greatly increases the pump and/or motor power requirements and 

operating costs for electricity. The PM10 emissions from 2001 to 2006 indicate that the 

Dave Johnston 4 Venturi particulate scrubber controls PM10 emissions to 0.061 lb per 

MMBtu. 

The BART Analysis for PM10 emissions on Dave Johnston 4 is described below. 

Step 1: Identify All Available Retrofit Control Technologies 

Two retrofit control technologies have been identified for additional particulate 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 particles to grounded collection plates. A layer of 

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

plates. The collected ash particles drop into hoppers below the precipitator 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 filtering elements (bags) along with a bag cleaning 

system and dust hoppers contained in a main shell structure. Fabric filters 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 dislodged 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 control technology of choice on projects where LAER 

review is required. Unlike precipitators, fabric 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 Effectiveness of Remaining Control Technologies 

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

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

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

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

carry a strong enough electrical charge to result in complete collection. 

The fabric filter is also more effective at collecting flyash generated from western low-sulfur 

coals, such as those combusted at the Dave 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 operating temperature of approximately 250°F used 

on most ESPs. The electrical resistivity of the flyash is lower 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 western power plants. A fabric filter is also the 

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

The existing Venturi particulate scrubber at Dave Johnston 4 is achieving a PM10 emission 

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

PM10 emissions to approximately 0.015 lb per MMBtu. 

The PM10 control technology emission rates are summarized in Table 3-5. 

TABLE 3-5 

PM10 Control Technology Emission Rates 

Dave Johnston 4 

Control Technology 

Short-Term Expected PM10

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 consideration of energy, environmental, and economic impacts 

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

considered during the evaluation. 

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

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

internal-diameter fan upgrade and upgrade 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 require 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 particulate matter removed for the fabric 

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

TABLE 3-6 

PM10 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 Design 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 replacement 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 PM10 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 dispersion (CALPUFF) modeling system 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 kilometers 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 the CALMET meteorological model, CALPUFF 

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

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

modeling system was applied in a full, refined 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 generate 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 kilometers of the facility. Grid resolution was 

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

instructed otherwise by the Wyoming Department 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 origin and the longitude of the 

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

were drawn to represent one-sixth 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 4-1
Badlands NP

Wind Cave NP

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

0 

Dave Jo

Class 

Sta

Sta

Dom

114° 5' 20.40" Longitude39° 3' 53.37" Latitude

100° 56' 34.08" Longitude45° 51' 57.22" Latitude

101° 54' 25.88" Longitude38° 54' 0.04" Latitude

114° 28' 37.96" Longitude46° 6' 26.20" Latitude

Dave Johnston

SLC \\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, Inc.’s (TRC) current example 

CALMET.inp file were used for CALMET. Vertical 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 set to values established by WDEQ-AQD, which 

appear in Table 3 of Appendix B. Table 4-1 lists the key user-specified 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 produce 3 years of analysis: 2001, 2002, and 2003. 

WDEQ-AQD provided 12-kilometer resolution Mesoscale Meteorological Model, Version 5 

(MM5) meteorological data fields 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 they 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 refined 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 National 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 available from the TRC 

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

SMERGE preprocessor and CALMET. 

Land use and terrain data were obtained from the 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, roughness length, and leaf area index were computed 

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

Model data, which 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 for 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 CALMET 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 NP

Wind Cave NP

RAP (UA)

P60

WRL

TOR

SHR

RKS

RIW (UA)

RWL

LAR

LND

GEY

GCC

EVW

DGW

CYS

CPR

BYG

BPI

VEL

SLC (UA)

PUC

OGD

LGU

DLN

RXE

PIH

IDA

LLJ

BYI

RIL

EEO

LIC LXV

GJT

DEN (UA)

APA

CAG

ITR

ASE

AKO

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

IEN

PHP

D07

2WX

SNY

BFF

CDR

AIA

LVM

DLN

BTM

BZN BIL

0 

Surface and Upper A

Dave J

Sta

Sta

Dom

114° 5' 20.40" Longitude39° 3' 53.37" Latitude

100° 56' 34.08" Longitude45° 51' 57.22" Latitude

101° 54' 25.88" Longitude38° 54' 0.04" Latitude

114° 28' 37.96" Longitude46° 6' 26.20" Latitude

Dave Johnston

SLC \\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 Weather 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 provided 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 for comparison to the predicted 

impacts for post-control scenarios for Dave Johnston 4. 

4.3.1 Background Ozone and Ammonia 

Hourly values of background ozone concentrations were used by CALPUFF for the 

calculation of SO2 and NOx 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 ammonia 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 Assessments for BART Control Analyses 

(WDEQ-AQD 2006). 

4.3.2 Stack Parameters 

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

current permit for Dave Johnston 4. Post-control stack parameters reflect the anticipated 

changes associated with installation of the control technology alternatives being evaluated. 

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

emission rate. Measured velocities 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. The emission rates reflect actual emissions 

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

Regulations and Guidelines for Best Available Retrofit Technology Determinations; Final 

Rule (40 CFR Part 51). 

CH2M HILL used available continuous emission 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: 

• SO2

• NOx

• Coarse particulate (particulate matter less than 2.5 micrometers in aerodynamic diameter 

[PM2.5]<diameter<PM10) 

• Fine particulate (diameter<PM2.5) 

• Sulfates 

Post-control emission rates reflect the effects 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 developed to cover the range of effectiveness for 

the combination of the individual NOx, SO2, and particulate matter control technologies 

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

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

presumptive BART levels for each pollutant. 

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

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

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

BART recommendation. 

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

the Venturi particulate scrubber with a new fabric filter. 

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

replacement of the Venturi particulate scrubber 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 NOx, SO2, and particulate matter controls alone was not performed because any 

final BART solution will include a combination of control technologies for NOx, SO2, 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 modeling. In accordance with the WDEQ BART 

modeling protocol, elemental carbon stack emissions and organic aerosol emissions were not 

modeled. 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology 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 area 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 receptors, meteorological stations, and source 

locations. 
TABLE 4-2 

BART Model Input Data Dave Johnston 4 

Baseline Post-control Scenario 1 Post-co

Existing Operations with 

Venturi Scrubber 

Low-NOx Burner (LNB) with OverFire Air (OFA), Dry Flue Gas 

Desulfurization (FGD), Fabric Filter 

LNB with 

Fa

Sulfur Dioxide (SO2) Stack Emissions 

(pounds per hour [lb/hr]) 2,050 615 

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,640 615 

PM10 Stack Emissions (lb/hr) 250 61.5 

Coarse Particulate (PM2.5 <diameter< PM10) Stack Emissions (lb/hr)(a) 107.5 35.1 

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 142.6 26.4 Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 37.7 3.69 

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 37.0 3.61 

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

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

(NH4)HSO4 Stack Emissions (lb/hr) 

(NH4)HSO4 as SO4 Stack Emissions (lb/hr) 

Total Sulfate (SO4) (lb/hr) 37.0 3.6 

Stack Conditions

Stack Height (meters) 76 152 Stack Exit Diameter (meters) 9.75 5.79 Stack Exit Temperature (Kelvin) 322 350 Stack Exit Velocity (meters per second) 8.53 25.7 

NOTES: (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) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack Emissions (lb/hr) 
BART ANALYSIS FOR DAVE JOHNSTON UNIT 4 

4.4 CALPOST 

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

output specified in deciview (dV) units. Calculations of light extinction were made for each 

pollutant modeled. The sum of all extinction values were used to calculate the 

delta-dV (ΔdV) change relative to natural background. The following default extinction 

coefficients for each pollutant were used: 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

CALPOST Visibility Method 6 was used to determine the visibility impacts. Monthly 

relative humidity factors [f (RH)] were used in the light extinction 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 ΔdV change 

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

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

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

concentrations corresponding to the 20 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 derived for each Class I area such that, when 

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

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

Visibility Improvement Modeling Analysis in North Dakota (North Dakota Department of 

Health, 2005). However, the Wyoming BART Air 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 Wyoming BART Air Modeling Protocol 

4.5 Presentation of Modeling Results 

This section presents the results 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 baseline and four post-control scenarios. The 

post-control scenarios included emission rates for SO2, NOx, and PM10 that would be 

achieved if BART state-of-the-art technology were installed on Dave Johnston 4. 

Baseline (and post-control) 98th percentile results were greater than 0.5 ΔdV for both the 

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

percentile results for each Class I area are presented in Table 4-4. 
TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Dave Johnston 4

Modeling Results 

Scenario First Year Cost Class I Area 

Highest 

Visibility 

Impact- 

(deciview [dV]) 

98th Percentile 

Visibility 

Impact- (dV) 

No. of Days 

Above 

0.5 dV 

Cost 

De

Re

2001 

Badlands 3.610 1.347 50 

Baseline: current operation with Venturi scrubber 

Wind Cave 4.304 1.527 47 

$27,665,203 Badlands 1.291 0.456 6 $31

Scenario 1: Low-NOx Burner (LNB) with Over-Fire Air (OFA), dry flue 

Gas Desulfurization (FGD), fabric filter $27,665,203 Wind Cave 1.727 0.467 7 $26

$35,381,111 Badlands 1.232 0.454 7 $39

Scenario 2: LNB with OFA, wet FGD, fabric filter 

$35,381,111 Wind Cave 1.661 0.551 9 $36

$38,962,883 Badlands 0.936 0.326 4 $38

Scenario 3: LNB with OFA and Selective Catalytic Reduction System (SCR), dry FGD, fabric filter $38,962,883 Wind Cave 1.259 0.353 3 $33

$46,678,791 Badlands 0.977 0.409 4 $49

Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter 

$46,678,791 Wind Cave 1.306 0.443 4 $43

2002 

Badlands 1.747 1.100 29 

Baseline: current operation with Venturi scrubber 

Wind Cave 3.052 1.344 37 

$27,665,203 Badlands 0.698 0.340 3 $36

Scenario 1: LNB with OFA, dry FGD, fabric filter 

$27,665,203 Wind Cave 0.807 0.465 7 $31

$35,381,111 Badlands 0.554 0.336 2 $46

Scenario 2: LNB with OFA, wet FGD, fabric filter 

$35,381,111 Wind Cave 0.912 0.460 5 $40$38,962,883 Badlands 0.525 0.230 1 $44

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter 

$38,962,883 Wind Cave 0.561 0.347 3 $39$46,678,791 Badlands 0.446 0.262 0 $55

Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter 

$46,678,791 Wind Cave 0.670 0.339 3 $46

JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_DJ4_OCT2007_FINAL.DOC 

TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Dave Johnston 4

Modeling Results 

Scenario First Year Cost Class I Area 

Highest 

Visibility 

Impact- 

(deciview [dV]) 

98th Percentile 

Visibility 

Impact- (dV) 

No. of Days 

Above 

0.5 dV 

Cost 

De

Re

2003 

Badlands 2.274 1.449 45 

Baseline: current operation with Venturi scrubber 

Wind Cave 4.009 2.078 40 

$27,665,203 Badlands 0.864 0.480 7 $28

Scenario 1: LNB with OFA, dry FGD, fabric filter 

$27,665,203 Wind Cave 1.504 0.751 10 $20

$35,381,111 Badlands 0.740 0.437 5 $34

Scenario 2: LNB with OFA, wet FGD, fabric filter 

$35,381,111 Wind Cave 1.375 0.663 10 $25$38,962,883 Badlands 0.652 0.329 1 $34

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter 

$38,962,883 Wind Cave 1.109 0.492 7 $24$46,678,791 Badlands 0.599 0.327 1 $41

Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter 

$46,678,791 Wind Cave 1.084 0.518 8 $29

3-year averages 

Badlands 1.299 41.3 

Baseline: current operation with Venturi scrubber 

Wind Cave 1.650 41.3 

$27,665,203 Badlands 0.425 5.3 $31

Scenario 1: LNB with OFA, dry FGD, fabric filter 

$27,665,203 Wind Cave 0.561 8.0 $25

$35,381,111 Badlands 0.409 4.7 $39

Scenario 2: LNB with OFA, wet FGD, fabric filter 

$35,381,111 Wind Cave 0.558 8.0 $32$38,962,883 Badlands 0.295 2.0 $38

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter 

$38,962,883 Wind Cave 0.397 4.3 $31

$46,678,791 Badlands 0.333 1.7 $48

Scenario 4: LNB with OFA and SCR, wet FGD, fabric filter 

$46,678,791 Wind Cave 0.433 5.0 $38

NOTES:Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $27,665,203 / (1.347 - 0.456) = $31,049,611 

Sample Calculations: Cost per Reduction in No. of Days Exceeding 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 economic evaluations, and consideration of the 

modeling analysis for Dave Johnston 4, the preliminary recommended BART controls for 

NOx, SO2, and PM10 are as follows:

• New LNBs and modifications to the OFA system for NOx control

• Dry FGD for SO2 control

• New fabric filter for PM10 control

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

Section 4. Visibility improvements for all emission control scenarios were 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 Section 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 total annualized cost versus 98th percentile ΔdV 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 focus 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 annualized costs for a total emissions reductions for all control 

alternatives identified in the BACT analysis...” 

An analysis of incremental cost effectiveness has been conducted. This analysis was 

performed in the following way. First, the control 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 (cost 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 incremental costs, the 

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

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

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

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

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

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

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

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

difference in total annual costs between two contiguous scenarios divided by the difference 

in emissions reduction. 

TABLE 5-1 

Badlands Class I Agent Control Data 

Dave Johnston 4 

Scenario Controls 

98th

Percentile 

ΔdV 

Reduction 

Average 

Number of 

Days Above 

0.5 Deciview 

(dV) (Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

ΔdV 

Reduction 

(Million$ 

per Delta 

Deciview 

(ΔdV) 

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-NOx 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 

98th

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-NOx 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 98th 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 98th 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 Tables 5-1 to 5-4 and Figures 5-1 to 5-4 on the 

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

improvements. Scenario 2 is eliminated because it is to the left of the curve formed by the 

“dominant” control alternative scenarios, which 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 improvement 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 National Park Class I Area in Tables 5-1 and 5-3 and 

Figures 5-1 and 5-2 illustrates the previously stated conclusions. The greatest reduction in 

98th 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 incremental cost effectiveness for Scenario 1 

compared to the Baseline is reasonable at about $800,000 per day and $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 NOx Emission Control 

The BART presumptive NOx limit assigned by the EPA for tangentially-fired boilers burning 

sub-bituminous coal is 0.15 lb per MMBtu. The 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 significant reduction in NOx emissions, reasonable control costs, and 

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

impacts. This upgrade approach is projected to meet the BART presumptive NOx limit of 

0.15 lb per MMBtu. 

5.2.2 SO2 Emission Control 

CH2M HILL recommends a Dry FGD system as BART for Dave Johnston 4, based on the 

significant reduction in SO2 emissions, reasonable control costs, and the advantages of 

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

This upgrade approach is projected to meet the BART presumptive SO2 limit of 0.15 lb per 

MMBtu. 

5.2.3 PM10 Emission Control 

CH2M HILL recommends replacement 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 PM10 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 only 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 modeling analysis results indicate that only 

minimal, if any, visibility improvements at the 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 visibility improvements may result. 

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

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

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

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

facility, it would increase the costs per deciview reduction that are presented in this report. 
6.0 References 

40 CFR Part 51. Regional Haze Regulations and Guidelines 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 Visibility Conditions Under the Regional Haze 

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

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

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

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

http://docs.lib.noaa.gov/rescue/dwm/data_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—Individual 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 Analysis 
PacifiCorp BART Analysis Scenarios

2

Index No. Name of Unit

1 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 3

10 Wyodak Unit 1

Scenario First Year Cost Scenario

 First Year 

Cost Scenario First Year Cost Scenar

 N/A $ 27,665,203 N/A 

 N/A $ 27,665,203 N/A 

 N/A $ 35,381,111 N/A 

 N/A $ 35,381,111 N/A 

 N/A $ 38,962,883 N/A 

 N/A $ 38,962,883 N/A 

 N/A $ 46,678,791 N/A 

 N/A $ 46,678,791 N/A 

Scenario First Year Cost Scenario First Year Scenario First Year Cost Scenar

 N/A N/A N/A 

 N/A N/A N/A  N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A  N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A  N/A N/A N/A 

Scenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric Filter

Scenario 1 - LNB with OFA, Dry FGD, Fabric Filter

Baseline - Current Operation with ESPScenario 1 - LNB with OFA, Dry FGD, Existing ESPScenario 2 - LNB with OFA, Dry FGD, New Fabric Filter

Jim Bridger

Select Unit:

Scenario 2 - LNB with OFA, Wet FGD, New Fabric FilterScenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric FilterScenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

DJ Unit 4

Scenario 4 - LNB with OFA and SCR, Wet FGD, Existing ESP, New Stack

Dave Johnston

DJ Unit 3

Baseline - Current Operation with Venturi Scrubber 

JB Unit 1 JB Unit 2 JB Unit 3 

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current OWet FGD and ESP

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Scenario 2 - LNB witFGD, Fabric Filter

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB witFGD, ESP

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB witSCR, Wet FGD, Fab

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB witSCR, Wet FGD, ESP

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Baseline - Current Operation with ESP

Baseline - Current OESP

NTN Unit 1 

Scenario 2 - LNB with OFA, Dry FGD, New Fabric Filter

Scenario 2 - LNB witFGD, New Fabric Fil

Scenario 1 - LNB with OFA, Dry FGD, ESP

Scenario 1 - LNB witFGD, ESP

Scenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric Filter

Scenario 3 - LNB witSCR, Dry FGD, New 

Dave Johnston Unit 4

Scenario 4 - LNB with OFA and SCR, Wet FGD, ESP, New Stack

Scenario 4 - LNB witSCR, Wet FGD, ESP

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
ECONOMIC ANALYSIS SUMMARY

Dave Johnston Unit 4 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR 

w

Case 1 2 3 4 5 

NOx Emission Control System Windbox Mods. LNB w/OFA ROFA

LNB w/OFA & 

SNCR

LNB w/OFA & 

SCR 

SO2 Emission Control System

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber Dry 

PM Emission Control System Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber 

TOTAL INSTALLED CAPITAL COST ($) 0 7,800,001 14,719,868 17,905,780 106,683,603 FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 Maintenance Material ($) 0 36,000 54,000 105,000 166,000 Maintenance Labor ($) 0 54,000 81,000 157,500 249,000 Administrative Labor ($) 0 0 0 0 0 TOTAL FIXED O&M COST 0 90,000 135,000 262,500 415,000 Makeup Water Cost 0 0 0 0 0 Reagent Cost 0 0 0 611,037 293,591 SCR Catalyst / FF Bag Cost 0 0 0 0 369,000 Waste Disposal Cost 0 0 0 0 0 Electric Power Cost 0 0 1,704,939 130,086 903,506 TOTAL VARIABLE O&M COST 0 0 1,704,939 741,123 1,566,098 

TOTAL FIRST YEAR O&M COST 0 90,000 1,839,939 1,003,623 1,981,098 

FIRST YEAR DEBT SERVICE ($) 0 741,997 1,400,269 1,703,338 10,148,579 TOTAL FIRST YEAR COST ($) 0 831,997 3,240,208 2,706,961 12,129,677 

Power Consumption (MW) 0.0 0.0 4.3 0.3 2.3 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 34.1 2.6 18.1 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 62.5% 62.5% 70.0% 82.5% NOx Removed (Tons/Yr) 0 4,041 4,041 4,526 5,334 First Year Average Control Cost ($/Ton NOx Rem.) 0 206 802 598 2,274 

Incremental Control Cost ($/Ton NOx Removed) 0 206 802 3,867 11,659 

2-1 3-1 4-2 5-4

SO2 Removal Rate (%) 58.3% 0.0% 0.0% 0.0% 0.0% 

SO2 Removed (Tons/Yr) 0 0 0 0 0 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 

PM Removal Rate (%) 98.82% 0.00% 0.00% 0.00% 0.00% PM Removed (Tons/Yr) 0 0 0 0 0 First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 

PRESENT WORTH COST ($) 0 8,899,607 37,199,968 30,167,902 130,888,366 

NOx Control 

Parameter Current Operation

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
INPUT CALCULATIONS

Dave Johnston Unit 4 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/F

Filter 

Case 1 2 3 4 5 7 

NOx Emission Control System Windbox Mods. LNB w/OFA ROFA

LNB w/OFA & 

SNCR LNB w/OFA & SCR Windbox Mo

SO2 Emission Control System

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber

Lime Added to 

Venturi Scrubber Dry FGD w/Fabr

PM Emission Control System Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi Scrubber Venturi ScruUnit Design and Coal CharacteristicsType of Unit PC PC PC PC PC PC Net Power Output (kW) 360,000 360,000 360,000 360,000 360,000 360,000 

Net Plant Heat Rate (Btu/kW-Hr) 11,390 11,390 11,390 11,390 11,390 11,390 Boiler Fuel Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork P

Coal Heating Value (Btu/Lb) 7,784 7,784 7,784 7,784 7,784 7,784 

Coal Sulfur Content (wt.%) 0.47% 0.47% 0.47% 0.47% 0.47% 0.47% 

Coal Ash Content (wt.%) 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 Coal Flow Rate (Lb/Hr) 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 2,076,53 (MMBtu/Yr) 32,327,554 32,327,554 32,327,554 32,327,554 32,327,554 32,327,55EmissionsUncontrolled SO2 (Lb/Hr) 4,920 2,050 2,050 2,050 2,050 2,050  (Lb/MMBtu) 1.20 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  (Tons/Yr) 19,396 8,082 8,082 8,082 8,082 8,082 SO2 Removal Rate (%) 58.3% 0.0% 0.0% 0.0% 0.0% 70.0%  (Lb/Hr) 2,870 0 0 0 0 1,435  (Ton/Yr) 11,314 0 0 0 0 5,657 SO2 Emission Rate (Lb/Hr) 2,050 2,050 2,050 2,050 2,050 615  (Lb/MMBtu) 0.50 0.50 0.50 0.50 0.50 0.15 

 (Ton/Yr) 8,082 8,082 8,082 8,082 8,082 2,425 Uncontrolled NOx (Lb/Hr) 1,640 1,640 1,640 1,640 1,640 1,640  (Lb/MMBtu) 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  (Tons/Yr) 6,466 6,466 6,466 6,466 6,466 6,466 NOx Removal Rate (%) 0.0% 62.5% 62.5% 70.0% 82.5% 0.0% 

 (Lb/Hr) 0 1,025 1,025 1,148 1,353 0  (Lb Moles/Hr) 0.00 34.16 34.16 38.26 45.09 0.00  (Ton/Yr) 0 4,041 4,041 4,526 5,334 0 NOx Emission Rate (Lb/Hr) 1,640 615 615 492 287 1,640  (Lb/MMBtu) 0.40 0.15 0.15 0.12 0.07 0.40 

 (Ton/Yr) 6,466 2,425 2,425 1,940 1,131 6,466 Uncontrolled Fly Ash (Lb/Hr) 21,113 250 250 250 250 250  (Lb/MMBtu) 5.149 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  (Tons/Yr) 83,228 986 986 986 986 986 Fly Ash Removal Rate (%) 98.82% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 20,863 0 0 0 0 0  (Ton/Yr) 82,242 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 250 250 250 250 250 250  (Lb/MMBtu) 0.061 0.061 0.061 0.061 0.061 0.061 

 (Ton/Yr) 986 986 986 986 986 986 

Parameter 

Current Operation NOx Control 

SO

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/F

Filter 

Case 1 2 3 4 5 7 

Parameter 

Current Operation NOx Control 

SO

General Plant DataAnnual Operation (Hours/Year) 7,884 7,884 7,884 7,884 7,884 7,884 Annual On-Site Power Plant Capacity Factor 0.90 0.90 0.90 0.90 0.90 0.90 

Economic Factors

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

Installed Capital Costs

NOx Emission Control System ($2006) 0 7,800,001 14,719,868 17,905,780 106,683,603 0 

SO2 Emission Control System ($2006) 0 0 0 0 0 222,776,1

PM Emission Control System ($2006) 0 0 0 0 0 0 

Total Emission Control Systems ($2006) 0 7,800,001 14,719,868 17,905,780 106,683,603 222,776,1

NOx Emission Control System ($/kW) 0 22 41 50 296 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 619 PM Emission Control System ($/kW) 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 22 41 50 296 619 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 0 0 0 0 0 506,128 Maintenance Material ($) 0 36,000 54,000 105,000 166,000 1,102,28

Maintenance Labor ($) 0 54,000 81,000 157,500 249,000 734,858 

Administrative Labor ($) 00000 0 

Total Fixed O&M Cost ($) 0 90,000 135,000 262,500 415,000 2,343,27

Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Water CostMakeup Water Usage (Gpm) 0 0 0 0 0 248 Unit Price ($/1000 Gallons) 1.22 1.22 1.22 0.00 1.22 1.22 

First Year Water Cost ($) 0 0 0 0 0 142,730 

Annual Water Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Reagent Cost None None None Urea Anhydrous NH3 Lime 

Unit Cost ($/Ton) 0.00 0.00 0.00 370 400 91.25  ($/Lb) 0.000 0.000 0.000 0.185 0.200 0.046 Molar Stoichiometry 0.00 0.00 0.00 0.45 1.00 1.10 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 90% 

Reagent Usage (Lb/Hr) 0 0 0 419 186 2,194 First Year Reagent Cost ($) 0 0 0 611,037 293,591 789,014 Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% SCR Catalyst / FF Bag Replacement Cost SCR Catalyst Bags Annual SCR Catalyst (m3) / No. FF Bags 0000 123 1,798 

SCR Catalyst ($/m3) / Bag Cost ($/ea.) 3,000 3,000 3,000 3,000 3,000 104 

First Year SCR Catalyst / Bag Replace. Cost ($) 0 0 0 0 369,000 186,992 

Annual SCR Catalyst / Bag Cost Esc. Rate (%) 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 FGD Waste Disposal Unit Cost ($/Dry Ton) 24.33 24.33 24.33 24.33 24.33 24.33 

First Year FGD Waste Disposal Cost ($) 0 0 0 0 0 388,534 

Annual Waste Disposal Cost Esc. Rate (%) 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%  (MW) 0.00 0.00 4.33 0.33 2.29 4.54 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 1,704,939 130,086 903,506 1,790,45

Annual Power Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Input Tables

Table 1 - Cases

Existing

1 2 3 4 5 6 7 8 

1 Dave Johnston Unit 3 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

2 Dave Johnston Unit 4 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A 

Dry FGD w/Fabric 

Filter

Wet FGD w/Fa

Filter 

3 Jim Bridger Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

4 Jim Bridger Unit 2 Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A

 Upgraded W

FGD 

5 Jim Bridger Unit 3 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

6 Jim Bridger Unit 4 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

7 Naughton Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

8 Naughton Unit 2 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

9 Naughton Unit 3 Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A

 Upgraded W

FGD 

10 Wyodak Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

LNB w/OFA & 

SCR Upgraded Dry FGD N/A Wet FGD 

Table 2 - Unit Design and Coal Characteristics

NOx SO2 PM Boiler Design

Net Power 

Output (kW)

Net Plant Heat 

Rate (Btu/kWHr) Coal Heating Val

HHV (Btu/L

1 Dave Johnston Unit 3 None None ESP

3-Cell Burner, Opposed 

Wall-Fired PC 250,000 11,200 Dry Fork PRB 7,7

2 Dave Johnston Unit 4 Windbox Mods.

Lime Added to Venturi 

Scrubber Venturi Scrubber Tangential-Fired PC 360,000 11,390 Dry Fork PRB 7,7

3 Jim Bridger Unit 1

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

4 Jim Bridger Unit 2 LNB - TFS 2000 Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

5 Jim Bridger Unit 3

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

6 Jim Bridger Unit 4

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

7 Naughton Unit 1 None None ESP Tangential-Fired PC 173,000 10,694 Kemmerer Mine 9,98 Naughton Unit 2 None None ESP Tangential-Fired PC 226,000 10,574 Kemmerer Mine 9,99 Naughton Unit 3 LNCFS II LNB Wet FGD ESP Tangential-Fired PC 356,000 10,336 Kemmerer Mine 9,9

10 Wyodak Unit 1 LNB Dry FGD ESP Opposed Wall-Fired PC 335,000 12,087 Clovis Point Mine 7,9

Current Emission Control Systems Unit Design Co

Index No. Name of UnitIndex No. Name of Unit | Case --->

NOx Control SO2 Control 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Table 3 - Emissions

Controlled 

SO2 Controlled NOx

Controlled 

PM Case 2 Case 3 Case 4 Case 5 Case 6 

1 Dave Johnston Unit 3 1.20 0.70 0.200 0.27 0.21 0.20 0.07 0

 

2 Dave Johnston Unit 4 0.50 0.40 0.061 0.15 0.15 0.12 0.07 N3 Jim Bridger Unit 1 0.27 0.45 0.045 0.24 0.22 0.20 0.07 N

4 Jim Bridger Unit 2 0.27 0.24 0.074 0.24 0.22 0.20 0.07 N5 Jim Bridger Unit 3 0.27 0.45 0.057 0.24 0.22 0.20 0.07 N6 Jim Bridger Unit 4 0.17 0.45 0.030 0.24 0.22 0.20 0.07 N7 Naughton Unit 1 1.20 0.58 0.056 0.24 0.28 0.18 0.07 0

 

8 Naughton Unit 2 1.20 0.54 0.064 0.24 0.28 0.18 0.07 0

 

9 Naughton Unit 3 0.50 0.45 0.094 0.35 0.30 0.25 0.07 N

10 Wyodak Unit 1 0.50 0.50 0.030 0.23 0.18 0.22 0.07 

0

Table 4 - Case 1 O&M Costs (Current Operation)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (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. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (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 Con

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

Current Emission Rates (Lb/MMBtu) NOx Control Emission Rates (Lb/MMBtu)

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Table 6 - Case 3 O&M Costs (Mobotec ROFA)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (MW

1 Dave Johnston Unit 3 $ 60,000 - $ 90,000 $ - $ - None - 22 Dave Johnston Unit 4 $ 54,000 - $ 81,000 $ $ - - None - 43 Jim Bridger Unit 1 $ 42,000 - $ 63,000 $ $ - - None - 64 Jim Bridger Unit 2 $ 42,000 - $ 63,000 $ $ - - None - 65 Jim Bridger Unit 3 $ 42,000 - $ 63,000 $ $ - - None - 66 Jim Bridger Unit 4 $ 42,000 - $ 63,000 $ $ - - None - 67 Naughton Unit 1 $ 48,000 - $ 72,000 $ $ - - None - 18 Naughton Unit 2 $ 48,000 - $ 72,000 $ $ - - None - 29 Naughton Unit 3 $ 48,000 - $ 72,000 $ $ - - None - 4

10 Wyodak Unit 1 $ 36,000 - $ 54,000 $ $ - None - - 5

Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (MW

1 Dave Johnston Unit 3 $ 98,000 - $ 147,000 $ - $ - Urea 0.41 02 Dave Johnston Unit 4 $ 105,000 - $ 157,500 $ $ - - Urea 0.45 03 Jim Bridger Unit 1 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 04 Jim Bridger Unit 2 $ 95,000 - $ 142,500 $ $ - - Urea 0.45 05 Jim Bridger Unit 3 $ 122,000 - $ 183,000 $ $ - - Urea 0.45 06 Jim Bridger Unit 4 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 07 Naughton Unit 1 $ 83,000 - $ 124,500 $ $ - - Urea 0.45 08 Naughton Unit 2 $ 93,000 - $ 139,500 $ $ - - Urea 0.51 09 Naughton Unit 3 $ 75,000 - $ 112,500 $ $ - - Urea 0.45 0

10 Wyodak Unit 1 $ 93,000 - $ 139,500 $ - Urea - 0.45 0

Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual SC

Catalyst 

Replace. (m

1 Dave Johnston Unit 3 $ 155,000 - $ 232,500 $ - $ - Anhydrous NH3 1.00 1

 

2 Dave Johnston Unit 4 $ 166,000 - $ 249,000 $ $ - - Anhydrous NH3 1.00 1

 

3 Jim Bridger Unit 1 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 1

 

4 Jim Bridger Unit 2 $ 162,000 - $ 243,000 $ $ - - Anhydrous NH3 1.00 1

 

5 Jim Bridger Unit 3 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 2

 

6 Jim Bridger Unit 4 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 2

 

7 Naughton Unit 1 $ 132,000 - $ 198,000 $ $ - - Anhydrous NH3 1.00 

 

8 Naughton Unit 2 $ 160,000 - $ 240,000 $ $ - - Anhydrous NH3 1.00 1

 

9 Naughton Unit 3 $ 156,000 - $ 234,000 $ $ - - Anhydrous NH3 1.00 1

 

10 Wyodak Unit 1 $ 181,000 - $ 271,500 $ $ - - Anhydrous NH3 1.00 

1

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of UnitIndex No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Table 9 - Case 6 O&M Costs (Dry FGD)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 714,175 506,128 $ 476,928 $ - $ 173 Lime 1.15 - 

2 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 1 $ 587,643 506,128 $ 391,762 $ $ - 120 Lime 1.40 - 

8 Naughton Unit 2 $ 860,17 506,128 $ 573,04 4 $ $ - 165 4 Lime 1.40 - 9 Naughton Unit 3 $ - - $ - $ $ - - Lime - - 

10 Wyodak Unit 1 $ 21,900 - $ 14,600 $ - 25 Lime 1.10 

-

Table 10 - Case 7 O&M Costs (Dry FGD w/Fabric Filter)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 714,175 506,128 $ 476,928 $ - $ 173 Lime 1.15 1,4

 

2 Dave Johnston Unit 4 $ 1,102,288 506,128 $ 734,858 $ $ - 248 Lime 1.10 1,7

 

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 1 $ 632,660 506,128 $ 459,286 $ $ - 120 Lime 1.15 8

 

8 Naughton Unit 2 $ 905,190 506,128 $ 640,568 $ $ - 165 Lime 1.15 1,1

 

9 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. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 1,182,587 809,804 $ 788,391 $ - $ 230 Lime 1.02 - 

2 Dave Johnston Unit 4 $ 1,430,78 809,804 $ 953,856 4 $ $ - 330 Lime 1.02 1,7

 

3 Jim Bridger Unit 1 $ 25,550 - $ 17,033 $ $ - 53 Soda Ash 1.02 - 4 Jim Bridger Unit 2 $ 25,550 - $ 17,033 $ $ - 53 Soda Ash 1.02 - 5 Jim Bridger Unit 3 $ 25,550 - $ 17,033 $ $ - 52 Soda Ash 1.02 - 6 Jim Bridger Unit 4 $ 25,550 - $ 17,033 $ $ - 27 Soda Ash 1.02 - 7 Naughton Unit 1 $ 963,589 809,804 $ 642,393 $ $ - 160 Lime 1.05 - 8 Naughton Unit 2 $ 1,226,386 809,804 $ 817,591 $ $ - 220 Lime 1.05 - 9 Naughton Unit 3 $ 21,900 - $ 14,600 $ $ - 66 Soda Ash 1.02 - 

10 Wyodak Unit 1 $ 328,496 303,677 $ 218,998 $ $ - 82 Lime 1.02 

-

Variable Operating RequirementsVariable Operating RequirementsVariable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent 

Usage (Lb/Hr)

Annual FF B

Replace

1 Dave Johnston Unit 3 $ - - $ - $ - $ - None - - 2 Dave Johnston Unit 4 $ - - $ - $ $ - - None - - 3 Jim Bridger Unit 1 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 

4 Jim Bridger Unit 2 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 5 Jim Bridger Unit 3 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 6 Jim Bridger Unit 4 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 7 Naughton Unit 1 $ - - $ 10,000 $ $ - - Elemental Sulfur 33 - 8 Naughton Unit 2 $ - - $ 10,000 $ $ - - Elemental Sulfur 43 - 9 Naughton Unit 3 $ - - $ 10,000 $ $ - - Elemental Sulfur 67 - 

10 Wyodak Unit 1 $ - - $ 10,000 $ - - Elemental Sulfur 63 

-

Table 13 - Case 10 O&M Costs (Fabric Filter)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 45,016 - $ 67,524 $ - $ - None - 1,4

 

2 Dave Johnston Unit 4 $ 68,133 - $ 102,199 $ $ - - None - 1,7

 

3 Jim Bridger Unit 1 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

4 Jim Bridger Unit 2 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

5 Jim Bridger Unit 3 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

6 Jim Bridger Unit 4 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

7 Naughton Unit 1 $ 45,016 - $ 67,524 $ $ - - None - 8

 

8 Naughton Unit 2 $ 45,016 - $ 67,524 $ $ - - None - 1,1

 

9 Naughton Unit 3 $ 48,666 - $ 72,999 $ $ - - None - 1,7

 

10 Wyodak Unit 1 $ 48,666 - $ 72,999 $ $ - - None - 

1,7

Table 14 - Major Materials Design and Supply Costs

2 3 4 5 6 7 8 9 

1 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 $ 

2 Dave Johnston Unit 4 $ 2,673,501 $ 4,343,192 $ 7,171,085 $ 66,200,000 $ - $ 137,267,000 $ 178,174,384 $ 

3 Jim Bridger Unit 1 $ 2,981,982 $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 4 Jim Bridger Unit 2 $ - $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 

5 Jim Bridger Unit 3 $ 2,981,982 $ 6,056,955 $ 9,419,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 

6 Jim Bridger Unit 4 $ 2,981,982 $ 6,056,955 $ 9,528,000 $ 93,009,000 $ - $ - $ 3,549,000 $ 7 Naughton Unit 1 $ 2,502,123 $ 2,675,792 $ 7,257,000 $ 37,292,000 $ 26,819,000 $ 42,301,000 $ 44,000,000 $ 800,0

8 Naughton Unit 2 $ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 39,262,000 $ 57,621,000 $ 56,000,000 $ 800,0

9 Naughton Unit 3 $ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $ - $ 2,963,000 $ 800,0

10 Wyodak Unit 1 $ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 996,100 $ - $ 178,174,384 $ 1,247,0

Variable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

NOx Control SO2 Control P

Index No. Name of Unit | Case --->

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
CAPITAL COST

Dave Johnston Unit 4

CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control System

CAPITAL COST COMPONENT Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Sour

LNB w/OFA or ROFA LNB w/OFA ROFA LNB w/OFA LNB w/OFA

Major Materials Design and Supply Vendor $2,673,501 Vendor $4,343,192 Vendor $2,673,501 Vendor $2,673,501 Vendor $0 Vendor 

Construction 85.3% $2,281,399 85.3% $3,706,209 85.3% $2,281,399 85.3% $2,281,399 85.3% $0 85.3% 

Balance of Plant 51.7% $1,381,990 51.7% $2,245,089 51.7% $1,381,990 51.7% $1,381,990 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $1,302,958 0.0% $0 0.0% $0 0.0% $0 0.0% 

Owner's Costs 13.2% $354,194 13.2% $575,401 13.2% $354,194 13.2% $354,194 13.2% $0 13.2% 

Surcharge 16.4% $439,136 16.4% $713,390 16.4% $439,136 16.4% $439,136 16.4% $0 16.4% AFUDC 12.2% $326,661 12.2% $530,671 12.2% $326,661 12.2% $326,661 12.2% $0 12.2% Subtotal $7,456,882 $13,416,910 $7,456,882 $7,456,882 $0 Contingency 12.8% $343,119 30.0% $1,302,958 12.8% $343,119 12.8% $343,119 12.8% $0 12.8% Total Capital Cost for LNB w/OFA or ROFA $7,800,001 $14,719,868 $7,800,001 $7,800,001 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $7,171,085 S&L Report $66,200,000 S&L Report $0 S&L Repor

Contingency 20.0% $0 20.0% $0 20.0% $1,434,217 20.0% $13,240,000 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $401,079 5.6% $3,702,566 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $5,591,914 8.4% $0 8.4% Boiler Reinforcement (Allowance) 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% Sales Tax 1.1% $0 1.1% $0 1.1% $79,025 1.1% $729,524 1.1% $0 1.1% 

Escalation 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% Contingency on Adders 2.8% $0 2.8% $0 2.8% $201,292 2.8% $1,858,234 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $819,081 11.4% $7,561,364 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $10,105,779 $98,883,602 $0 

Dry or Wet FGD, FGC or Fabric Filter Dry FGD 

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Repor

Contingency 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% 

EPC Premium 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% 

Boiler Reinforcement (Allowance) 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% 

Sales Tax 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% 

Escalation 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% 

Contingency on Adders 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% 

Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 

LNB w/OFA & SNCR N/A Dry FGD 

SO2 

LNB w/OFA

Lime Added to Venturi Scrubber

Venturi Scrubber Venturi Scrubber

ROFA

Lime Added to Venturi Scrubber

Wind

Dry FGD 

Parameter

LNB w/OFA ROFA LNB w/OFA & SCR

Vent

Windbox Mods.

N/A

Venturi Scrubber

LNB w/OFA & SNCR

Lime Added to Venturi Scrubber

Venturi Scrubber Venturi Scrubber

LNB w/OFA & SCR

Lime Added to Venturi Scrubber

NOx Control

2 3 45 

6 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Dave Johnston Unit 4 LNB w/OFA

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 90,000 - - - - - - 

 

2 2015 91,800 - - - - - - 

 

3 2016 93,636 - - - - - - 

 

4 2017 95,509 - - - - - - 

 

5 2018 97,419 - - - - - - 

 

6 2019 99,367 - - - - - - 

 

7 2020 101,355 - - - - - - 

 

8 2021 103,382 - - - - - - 

 

9 2022 105,449 - - - - - - 

 

10 2023 107,558 - - - - - - 

 

11 2024 109,709 - - - - - - 

 

12 2025 111,904 - - - - - - 

 

13 2026 114,142 - - - - - - 

 

14 2027 116,425 - - - - - - 

 

15 2028 118,753 - - - - - - 

 

16 2029 121,128 - - - - - - 

 

17 2030 123,551 - - - - - - 

 

18 2031 126,022 - - - - - - 

 

19 2032 128,542 - - - - - - 

 

20 2033 131,113 - - - - - - 

 

Present Worth - 1,099,607 - - - - - 

 

(% of PW) 12.4% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Dave Johnston Unit 4 ROFA

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 135,000 - - - - 1,704,939 1,704,939 

 

2 2015 137,700 - - - - 1,739,037 1,739,037 

 

3 2016 140,454 - - - - 1,773,818 1,773,818 

 

4 2017 143,263 - - - - 1,809,295 1,809,295 

 

5 2018 146,128 - - - - 1,845,480 1,845,480 

 

6 2019 149,051 - - - - 1,882,390 1,882,390 

 

7 2020 152,032 - - - - 1,920,038 1,920,038 

 

8 2021 155,073 - - - - 1,958,439 1,958,439 

 

9 2022 158,174 - - - - 1,997,607 1,997,607 

 

10 2023 161,337 - - - - 2,037,560 2,037,560 

 

11 2024 164,564 - - - - 2,078,311 2,078,311 

 

12 2025 167,856 - - - - 2,119,877 2,119,877 

 

13 2026 171,213 - - - - 2,162,274 2,162,274 

 

14 2027 174,637 - - - - 2,205,520 2,205,520 

 

15 2028 178,130 - - - - 2,249,630 2,249,630 

 

16 2029 181,692 - - - - 2,294,623 2,294,623 

 

17 2030 185,326 - - - - 2,340,515 2,340,515 

 

18 2031 189,033 - - - - 2,387,326 2,387,326 

 

19 2032 192,813 - - - - 2,435,072 2,435,072 

 

20 2033 196,670 - - - - 2,483,774 2,483,774 

 

Present Worth - 1,649,410 - - - 20,830,690 20,830,690 1

 

(% of PW) 4.4% 0.0% 0.0% 0.0% 0.0% 56.0% 56.0% 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Dave Johnston Unit 4 LNB w/OFA & SNCR

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 262,500 - 611,037 - - 130,086 741,123 

 

2 2015 267,750 - 623,258 - - 132,688 755,946 

 

3 2016 273,105 - 635,723 - - 135,341 771,065 

 

4 2017 278,567 - 648,438 - - 138,048 786,486 

 

5 2018 284,138 - 661,406 - - 140,809 802,216 

 

6 2019 289,821 - 674,635 - - 143,625 818,260 

 

7 2020 295,618 - 688,127 - - 146,498 834,625 

 

8 2021 301,530 - 701,890 - - 149,428 851,318 

 

9 2022 307,561 - 715,928 - - 152,416 868,344 

 

10 2023 313,712 - 730,246 - - 155,465 885,711 

 

11 2024 319,986 - 744,851 - - 158,574 903,425 

 

12 2025 326,386 - 759,748 - - 161,746 921,494 

 

13 2026 332,913 - 774,943 - - 164,981 939,924 

 

14 2027 339,572 - 790,442 - - 168,280 958,722 

 

15 2028 346,363 - 806,251 - - 171,646 977,896 

 

16 2029 353,290 - 822,376 - - 175,079 997,454 

 

17 2030 360,356 - 838,823 - - 178,580 1,017,403 

 

18 2031 367,563 - 855,600 - - 182,152 1,037,752 

 

19 2032 374,915 - 872,712 - - 185,795 1,058,507 

 

20 2033 382,413 - 890,166 - - 189,511 1,079,677 

 

Present Worth - 3,207,186 7,465,564 - - 1,589,372 9,054,936 1

 

(% of PW) 10.6% 0.0% 24.7% 0.0% 0.0% 5.3% 30.0% 

Dave Johnston Unit 4 LNB w/OFA & SCR

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 415,000 - 293,591 369,000 - 903,506 1,566,098 1

 

2 2015 423,300 - 299,463 376,380 - 921,577 1,597,420 1

 

3 2016 431,766 - 305,453 383,908 - 940,008 1,629,368 1

 

4 2017 440,401 - 311,562 391,586 - 958,808 1,661,956 1

 

5 2018 449,209 - 317,793 399,417 - 977,984 1,695,195 1

 

6 2019 458,194 - 324,149 407,406 - 997,544 1,729,099 1

 

7 2020 467,357 - 330,632 415,554 - 1,017,495 1,763,681 1

 

8 2021 476,705 - 337,244 423,865 - 1,037,845 1,798,954 1

 

9 2022 486,239 - 343,989 432,342 - 1,058,602 1,834,933 1

 

10 2023 495,963 - 350,869 440,989 - 1,079,774 1,871,632 1

 

11 2024 505,883 - 357,886 449,809 - 1,101,369 1,909,065 1

 

12 2025 516,000 - 365,044 458,805 - 1,123,397 1,947,246 1

 

13 2026 526,320 - 372,345 467,981 - 1,145,865 1,986,191 1

 

14 2027 536,847 - 379,792 477,341 - 1,168,782 2,025,915 1

 

15 2028 547,584 - 387,388 486,888 - 1,192,158 2,066,433 1

 

16 2029 558,535 - 395,135 496,625 - 1,216,001 2,107,762 1

 

17 2030 569,706 - 403,038 506,558 - 1,240,321 2,149,917 1

 

18 2031 581,100 - 411,099 516,689 - 1,265,127 2,192,915 1

 

19 2032 592,722 - 419,321 527,023 - 1,290,430 2,236,773 1

 

20 2033 604,577 - 427,707 537,563 - 1,316,238 2,281,509 1

 

Present Worth - 5,070,409 3,587,058 4,508,388 - 11,038,909 19,134,354 10

 

(% of PW) 3.9% 0.0% 2.7% 3.4% 0.0% 8.4% 14.6% 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Dave Johnston Unit 4 Dry FGD w/Fabric Filte

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 2,343,273 142,730 789,014 186,992 388,534 1,790,456 3,297,727 2

 

2 2015 2,390,139 145,585 804,795 190,732 396,304 1,826,266 3,363,681 2

 

3 2016 2,437,942 148,497 820,891 194,546 404,230 1,862,791 3,430,955 2

 

4 2017 2,486,701 151,467 837,308 198,437 412,315 1,900,047 3,499,574 2

 

5 2018 2,536,435 154,496 854,055 202,406 420,561 1,938,048 3,569,565 2

 

6 2019 2,587,163 157,586 871,136 206,454 428,972 1,976,809 3,640,957 2

 

7 2020 2,638,907 160,738 888,558 210,583 437,552 2,016,345 3,713,776 2

 

8 2021 2,691,685 163,952 906,330 214,795 446,303 2,056,672 3,788,051 2

 

9 2022 2,745,518 167,231 924,456 219,091 455,229 2,097,805 3,863,812 2

 

10 2023 2,800,429 170,576 942,945 223,473 464,334 2,139,761 3,941,089 2

 

11 2024 2,856,437 173,987 961,804 227,942 473,620 2,182,556 4,019,910 2

 

12 2025 2,913,566 177,467 981,040 232,501 483,093 2,226,207 4,100,309 2

 

13 2026 2,971,837 181,017 1,000,661 237,151 492,755 2,270,732 4,182,315 2

 

14 2027 3,031,274 184,637 1,020,674 241,894 502,610 2,316,146 4,265,961 2

 

15 2028 3,091,900 188,330 1,041,088 246,732 512,662 2,362,469 4,351,280 2

 

16 2029 3,153,738 192,096 1,061,910 251,667 522,915 2,409,719 4,438,306 2

 

17 2030 3,216,812 195,938 1,083,148 256,700 533,373 2,457,913 4,527,072 2

 

18 2031 3,281,149 199,857 1,104,811 261,834 544,041 2,507,071 4,617,614 2

 

19 2032 3,346,772 203,854 1,126,907 267,071 554,922 2,557,213 4,709,966 2

 

20 2033 3,413,707 207,931 1,149,445 272,412 566,020 2,608,357 4,804,165 2

 

Present Worth 1,743,858 28,629,772 9,640,062 2,284,641 4,747,046 21,875,534 40,291,141 22

 

(% of PW) 9.8% 0.6% 3.3% 0.8% 1.6% 7.5% 13.8% 

Dave Johnston Unit 4 Wet FGD w/Fabric Filt

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 3,194,444 189,923 583,010 186,992 407,463 2,479,518 3,846,906 2

 

2 2015 3,258,333 193,722 594,670 190,732 415,612 2,529,108 3,923,844 2

 

3 2016 3,323,499 197,596 606,564 194,546 423,924 2,579,691 4,002,321 2

 

4 2017 3,389,969 201,548 618,695 198,437 432,403 2,631,284 4,082,368 2

 

5 2018 3,457,769 205,579 631,069 202,406 441,051 2,683,910 4,164,015 2

 

6 2019 3,526,924 209,691 643,690 206,454 449,872 2,737,588 4,247,295 2

 

7 2020 3,597,463 213,885 656,564 210,583 458,869 2,792,340 4,332,241 2

 

8 2021 3,669,412 218,162 669,695 214,795 468,047 2,848,187 4,418,886 2

 

9 2022 3,742,800 222,526 683,089 219,091 477,408 2,905,151 4,507,264 2

 

10 2023 3,817,656 226,976 696,751 223,473 486,956 2,963,254 4,597,409 2

 

11 2024 3,894,009 231,516 710,686 227,942 496,695 3,022,519 4,689,357 2

 

12 2025 3,971,889 236,146 724,900 232,501 506,629 3,082,969 4,783,144 2

 

13 2026 4,051,327 240,869 739,398 237,151 516,761 3,144,628 4,878,807 2

 

14 2027 4,132,354 245,686 754,186 241,894 527,097 3,207,521 4,976,383 2

 

15 2028 4,215,001 250,600 769,269 246,732 537,638 3,271,671 5,075,911 2

 

16 2029 4,299,301 255,612 784,655 251,667 548,391 3,337,105 5,177,429 2

 

17 2030 4,385,287 260,724 800,348 256,700 559,359 3,403,847 5,280,978 2

 

18 2031 4,472,993 265,939 816,355 261,834 570,546 3,471,924 5,386,597 2

 

19 2032 4,562,452 271,257 832,682 267,071 581,957 3,541,362 5,494,329 2

 

20 2033 4,653,702 276,683 849,335 272,412 593,596 3,612,190 5,604,216 2

 

Present Worth 2,320,456 39,029,246 7,123,130 2,284,641 4,978,320 30,294,387 47,000,934 28

 

(% of PW) 10.4% 0.6% 1.9% 0.6% 1.3% 8.1% 12.5% 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
Dave Johnston Unit 4 Fabric Filter

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 170,331 - - 186,992 - 926,764 1,113,756 

 

2 2015 173,738 - - 190,732 - 945,299 1,136,031 

 

3 2016 177,213 - - 194,546 - 964,205 1,158,752 

 

4 2017 180,757 - - 198,437 - 983,490 1,181,927 

 

5 2018 184,372 - - 202,406 - 1,003,159 1,205,566 

 

6 2019 188,060 - - 206,454 - 1,023,223 1,229,677 

 

7 2020 191,821 - - 210,583 - 1,043,687 1,254,270 

 

8 2021 195,657 - - 214,795 - 1,064,561 1,279,356 

 

9 2022 199,570 - - 219,091 - 1,085,852 1,304,943 

 

10 2023 203,562 - - 223,473 - 1,107,569 1,331,042 

 

11 2024 207,633 - - 227,942 - 1,129,720 1,357,663 

 

12 2025 211,786 - - 232,501 - 1,152,315 1,384,816 

 

13 2026 216,021 - - 237,151 - 1,175,361 1,412,512 

 

14 2027 220,342 - - 241,894 - 1,198,868 1,440,762 

 

15 2028 224,749 - - 246,732 - 1,222,846 1,469,578 

 

16 2029 229,244 - - 251,667 - 1,247,303 1,498,969 

 

17 2030 233,829 - - 256,700 - 1,272,249 1,528,949 

 

18 2031 238,505 - - 261,834 - 1,297,694 1,559,528 

 

19 2032 243,275 - - 267,071 - 1,323,647 1,590,718 

 

20 2033 248,141 - - 272,412 - 1,350,120 1,622,532 

 

Present Worth - 2,081,084 - 2,284,641 - 11,323,069 13,607,710 5

 

(% of PW) 3.2% 0.0% 0.0% 3.5% 0.0% 17.2% 20.7% 

EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 
EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 

First Year Cost for Air Pollution Control Options

0

5,000,000

10,000,00015,000,00020,000,00025,000,00030,000,00035,000,00040,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Dry FGD w/Fabric

Filter

Wet FG

w/Fabric F

Air Pollution Control Option

First Year Cost ($)
EY102007001SLC\App A_PCorp DJ4 BART Economic Analysis_01-16-07.xls 

Present Worth Cost for Air Pollution Control Options

0

50,000,000

100,000,000150,000,000200,000,000250,000,000300,000,000350,000,000400,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Dry FGD w/Fabric

Filter

Wet FG

w/Fabric F

Air Pollution Control Options

Present Worth Cost Over Year Plant Life ($)
APPENDIX B 

2006 Wyoming BART Protocol