Final Report 

BART Analysis for 

Dave Johnston Unit 3 

Prepared For: 

PacifiCorp 

1407 West North Temple 

Salt Lake City, Utah 84116 

December 2007 

Prepared By: 

215 South State Street, Suite 1000 

Salt Lake City, Utah 84111 
Final Report 

BART Analysis for 

Dave Johnston Unit 3 

Submitted to 

PacifiCorp 

December 2007 
Executive Summary 

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

regulations and guidelines, CH2M HILL was requested to perform a BART analysis for 

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

Retrofit Technology 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 3 unless it is determined that an alternative control level is justified, based on 

a careful consideration of the statutory factors. 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. 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) 

− LNBs with rotating opposed fire air (ROFA) 

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

− LNBs with selective catalytic reduction (SCR) system 

• SO2 emission controls: 

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

(ESP) 

− Dry FGD system with new polishing fabric filter 

− Wet FGD system and new stack with existing ESP 

• PM10 emission controls: 

− Sulfur trioxide (SO3) injection flue gas conditioning system on existing ESP 

− Polishing fabric filter 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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 

• 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 

• 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 

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. 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

Recommendations 

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

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

identified as Scenario 1 throughout this report. 

NOx Emission Control 

The BART presumptive NOx limit assigned by EPA for wall-fired cell burner boilers 

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

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

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

Johnston 3, based on the projected significant reduction in NOx emissions, reasonable control 

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

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

of 0.45 pound (lb) per MMBtu. 

SO2 Emission Control 

CH2M HILL recommends a dry FGD system as BART for Dave Johnston 3, 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. 

Although this approach is projected to not meet the BART presumptive SO2 limit of 0.15 lb 

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

impacts on the environment demonstrate compelling objective reasons why this 

recommendation is valid. 

PM10 Emission Control 

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

based on the significant reduction in PM10 emissions, reasonable control costs, and the 

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

impacts. 

BART Modeling Analysis 

CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of 

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

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

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

• Wind Cave NP 

• Badlands NP 

Because Dave Johnston 3 will simultaneously control NOx, SO2, and PM10 emissions, 

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

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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 LNBs and OFA system, dry FGD system, and the existing ESP. As 

indicated previously, this scenario represents CH2M HILL’s preliminary BART 

recommendation. 

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

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

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

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

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

maintaining the existing ESP. 

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

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

Workshop Manual1. 

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 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, dry FGD, and 

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

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

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

selected due to very high incremental 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 

 

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

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC ES-5

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

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

Therefore, Scenario 1 represents BART for Dave Johnston 3. 

Just-Noticeable Differences in Atmospheric Haze 

Studies have been conducted 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 be spending many millions of dollars at this single unit—and over a billion 

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

improvements may result. 
Contents 

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

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

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

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

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

3.2.1 BART 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......................................................................... 4-9 

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

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

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

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

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

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

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

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

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

5.2.1 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\DAVEJOHNSTON3_FINALSUBMITTAL\BART_DJ3_OCT2007_FINAL.DOC iii
CONTENTS (CONTINUED) 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC iv

Tables 

2-1 Present Unit Operation 

2-2 Coal Sources and Characteristics 

3-1 NOx Control Technology Emission Rate Ranking 

3-2 NOx Control Cost Comparison 

3-3 SO2 Control Technology Emission Rate 

3-4 SO2 Control Cost Comparison 

3-5 PM10 Control Technology Emission Rates 

3-6 PM10 Control Cost 

4-1 User-specified CALMET Options 

4-2 BART Model Input Data 

4-3 Average Natural Levels of Aerosol Components 

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

Class I Areas 

5-1 Badlands Class I Agent Control Data 

5-2 Wind Caves Class I Area Control Data 

5-3 Badlands Class I Area Incremental Data 

5-4 Wind Caves Class I Agent Incremental Data 

Figures 

3-1 First Year Control Cost for 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 

°F Degree Fahrenheit 

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 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

EPA United States Environmental Protection Agency 

ESP Electrostatic Precipitator 

f (RH) Relative Humidity Factors 

FGC Flue Gas Conditioning 

FGD Flue Gas Desulfurization 

H2SO4 Sulfuric Acid 

kW Kilowatt 

kWh Kilowatt-hour 

LAER Lowest Achievable Emission Rate 

lb Pound(s) 

LNB Low-NOx Burner 

LOI Loss on Ignition 

MM5 Mesoscale Meteorological Model, Version 5 

MMBtu Million British Thermal Units 

MW Megawatt 

N2 Nitrogen 

NH4 Ammonium 

(NH4)2SO4 Ammonium Sulfate 

NOx Nitrogen Oxide 

NP National Park 

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ACRONYMS AND ABBREVIATIONS (CONTINUED) 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC vi

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

OFA Over-fire Air 

PM Particulate Matter 

PM10 Particulate Matter less than 10 Micrometers in Aerodynamic Diameter 

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

PRB Powder River Basin 

ROFA Rotating Opposed Fire Air 

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

S&L Sargent & Lundy 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

SNCR Selective Non-catalytic Reduction 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

TRC TRC Companies, Inc. 

USGS United States 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 3 (hereafter referred to as Dave Johnston 3) by January 26, 2007. 

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

a proposal and justification 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 requiring emissions 

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

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

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

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

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 3 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 impact 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 and references in Section 6. 

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

Protocol.

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 1-1
2.0 Present Unit Operation 

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

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

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

Dave Johnston 3 is not equipped with any SO2 removal equipment at this time, nor has the 

unit undergone combustion control modifications for NOx control. A Lodge-Cottrell 

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

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

assumptions. 

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

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

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

characteristics are summarized in Table 2-2. 

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

through 2030; however, this 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 3 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 3 to operate until 2034. 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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TABLE 2-1 

Present Unit Operation 

Dave Johnston 3 

General Plant Data 

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

Stack Height (feet) 500 

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

Stack Exit Temperature (degrees Fahrenheit) 341 

Stack Exit Velocity (feet per second) 105 

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

Plant Operation Start Date 1964 

Latitude (degree: minute: second) 42:50:16.91 

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

Annual Unit Capacity Factor (percentage) 90 

Net Unit Output (megawatts) 230(a)

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

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

hour)(100% load) 

2,500 (as measured by continuous emission 

monitoring) 

Type of Boiler Cell-Fired 

Boiler Fuel Coal 

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

Coal Heating Value (Btu per pound [lb])(b) 8,100 

Coal Sulfur Content (percentage by weight [wt. %])(b) 0.47 

Coal Ash Content (wt. %)(b) 5.01 

Coal Moisture Content (wt. %)(b) 32.0 

Coal Nitrogen Content (wt. %)(b) 0.91 

Current Nitrogen Oxide (NOx) Controls None 

NOx Emission Rate(lb/MMBtu)(c) 0.70 

Current Sulfur Dioxide (SO2) Controls None 

SO2 Emission Rate (lb/MMBtu)(c) 1.20 

Current PM10(d) Controls Electrostatic Precipitator 

Particulate Matter (PM) Emission Rate (lb/MMBtu)(e) 0.030 

NOTES: 

(a)Output is currently limited to 220 MW, until SO2 controls are installed and operating (b)Coal characteristics vary between coal sources (c)Emission rates stated on annual average basis (d)PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter (e)Emission rate stated from test results 
BART A

TABLE 2-2 Coal Sources and Characteristics Dave Johnston 3 

Ultimate An

Mines 

Moisture 

(%) Ash (%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

units per 

pound 

(Btu/lb) 

Sulfur 

(%) 

Moisture 

and Ash 

Free 

(Btu/lb) Hydrogen Carbon Sulf

Clovis Point Mine 32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.99 67.3 0.8Maximum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.58 69.5 1.0Minimum 29.9 4.5 30.0 29.0 7,901 0.36 12,744 3.82 64.4 0.6

Dry Fork Mine 32.1 5.2 29.5 33.0 8,036 0.39 12,818 4.56 68.7 0.5

Maximum 30.7 4.5 39.1 42.7 8,200 0.54 12,924 5.04 71.3 0.7Minimum 33.2 7.8 28.9 31.9 7,650 0.26 12,726 4.07 65.8 0.3

Rawhide Mine 30.4 5.3 30.4 33.9 8,285 0.37 12,875 4.63 69.4 0.5

Maximum 31.6 6.6 32.7 37.1 8,480 0.53 13,000 5.41 71.1 0.6Minimum 29.0 4.5 29.5 31.7 8,120 0.21 12,575 4.31 66.3 0.3

Other Northern Powder River Basin 30.1 5.9 30.8 33.2 8,122 0.39 12,843 4.73 68.4 0.6

Maximum 32.0 5.3 31.1 31.2 8,045 0.41 12,835 4.99 67.3 0.8Minimum 33.1 7.0 34.0 35.0 8,283 0.46 12,961 5.58 69.5 1.0

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 
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 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 3 

• Step 4 – Evaluate Impacts and Document the Results 

− The costs of compliance with the control options 

− The remaining useful life of the facility 

− The energy and non-air quality environmental impacts of compliance 

• Step 5 – Evaluate Visibility Impacts 

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

of BART 

In order to minimize costs in the BART 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 

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

number of variables, including operating conditions, equipment design, and coal 

characteristics. 

Formation of NOx

During coal combustion, NOx is formed in three different 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. A 

smaller part of NOx formation is due to high temperature fixation of atmospheric nitrogen in 

the combustion air. 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 

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BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

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

promote more stable molecular nitrogen, and hence result in lower NOx emissions. 

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

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

Information Administration, PRB coals currently represent 88 percent of total U.S. subbituminous production and 73 percent of western coal production (Energy Information 

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

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

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

Dave Johnston 3 burns sub-bituminous coals from the PRB. The BART presumptive NOx

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

million British thermal unit (MMBtu). The NOx emission rate at Dave Johnston 3 is 0.70 lb 

per MMBtu, which would indicate that a 33 percent reduction from current NOx emission 

levels would be needed to meet the BART presumptive NOx limit. 

The BART analysis for NOx emissions from Dave Johnston 3 is described in this 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 3, 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 3 NOx emissions are currently controlled through the use of good combustion 

practices. 

The following potential NOx control technology options were considered: 

• New LNBs with advanced over-fire air (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 3 on a wall-fired cell burner configuration burning sub-bituminous coal, 

technical feasibility will primarily be determined by physical constraints and boiler 

configuration. Dave Johnston 3 has an uncontrolled NOx emission rate of 0.70 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). Updated cost estimates for SCR and SNCR were used (Sargent & Lundy, 

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-3
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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, 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. 

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

with projected NOx emission rates. 

TABLE 3-1 

NOx Control Technology Emission Rate Ranking 

Dave Johnston 3 

Technology 

Projected Emission Rate 

(pounds per million 

British thermal units) 

Presumptive Best Available Retrofit Technology (BART) Limit 0.45 

Low-NOx burners (LNBs) with over-fire air (OFA) 0.24 

Rotating Opposed Fire Air 0.19 

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

LNB with OFA and Selective Catalytic Reduction (SCR) 0.07 

Step 3: Evaluate Control 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, the 

proposals include inherent uncertainties. These proposals are usually prepared in a limited 

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

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

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

guarantees are established only after more 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 nitrogen 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 a capital cost, combustion technology retrofit. For 

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-4
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

from adjacent burners and reduces burner zone heat flux. These modifications usually require 

boiler waterwall tube replacement. 

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

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

result in an expected NOx emission rate of 0.24 lb per MMBtu. PacifiCorp has indicated that 

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

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

overhauls. This emission rate represents a significant reduction from the 2005 average NOx

emission rate, and is comfortably below the presumptive NOx emission rate of 0.45 lb per 

MMBtu. 

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

states that “the flue gas volume of the furnace is set in rotation by asymmetrically placed air 

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

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

reduces the maximum temperature of the flames and increases heat absorption. The 

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

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

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

Mobotec expects to achieve a NOx emission rate of 0.15 lb per MMBtu using ROFA 

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

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

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

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

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

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

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

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

onsite construction supervisor during installation and startup. 

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

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

sub-bituminous coals, ROFA was not considered in the post-control modeling scenarios. 

SNCR. Selective non-catalytic reduction is generally utilized 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 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-5
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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, due to greater reagent consumption. To reduce reagent costs, 

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

providing a NOx emission rate of 0.24 lb per MMBtu, would be installed in conjunction with 

SNCR. At Dave Johnston 3, a further reduction of 20 percent in NOx emission rates results in 

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

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

ongoing parasitic costs, the operating difficulties, and the potential ammonia slip emission 

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

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

Ammonia is injected into the flue-gas stream, where it reduces 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 3. 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. Due to 

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

Johnston 3. 

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

SNCR, it is generally more cost effective to reduce NOx emission levels as much as possible 

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

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

combustion modifications—including LNBs and OFA, providing a NOx emission rate of 

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

includes a 90 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 

characteristics of the coal used at Dave Johnston 3. 

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

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

follows: 

1. Establish expected NOx emissions value from vendor. 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

3. Review and evaluate unit physical and operational characteristics and restrictions. The 

fewer variations there are 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. 

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

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

have energy impacts. 

The Mobotec ROFA system requires installation and operation of one 3,000 to 

3,700 horsepower ROFA fan. 

Selective catalytic reduction retrofit impacts 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. Total additional power requirements for SCR installation at Dave Johnston 3 are 

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

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

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

or lower than prior levels. Installation of LNBs with OFA may also result in higher CO 

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

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

due to ammonia levels, and could potentially 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. 

Economic Impacts. Costs and schedules for the LNBs and OFA, SNCR, 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 plus or minus 

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

and other costs were added to make a comparable estimate. 

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

of NOx removed is summarized in Table 3-2. The complete economic analysis is contained in 

Appendix A. 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-7
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-8

TABLE 3-2 

NOx Control Cost Comparison 

Dave Johnston 3 

Factor 

Low-NOx

Burners 

(LNBs) with 

Over-fire 

Air (OFA) 

Mobotec 

Rotating 

Opposed 

Fire Air 

(ROFA) 

LNB with 

OFA and 

Selective 

NonCatalytic 

Reduction 

(SNCR) 

LNB with 

OFA and 

Selective 

Catalytic 

Reduction 

(SCR) 

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

Total First Year Fixed and Variable 

Operation and Maintenance Costs 

$0.1 million $1.2 million $1.0 million $1.8 million 

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

Power Consumption (megawatts) ---- 2.76 0.23 1.57 

Annual Power Usage 

(million kilowatt-hours per year) 

---- 21.8 1.8 12.4 

Nitrogen Oxide (NOx) Design Control Efficiency 65.7% 72.9% 72.9% 90% 

Tons NOx Removed per Year 5,077 5,629 5,629 6,954 

First Year Average Control Cost (dollars per ton 

[$/Ton] of NOx Removed) 

$318/ton $424/ton $584/ton $1,401/ton 

Incremental Control Cost ($/Ton of NOx Removed) $318/ton $1,398/ton $3,035/ton $5,555/ton 

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

BART for Dave Johnston 3 based on its significant reduction in NOx emissions, reasonable 

control cost, and no additional power requirements or environmental impacts. Low-NOx

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

the PRB sub-bituminous coal burned at the facility.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BART A

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

Dave Johnston 3 

0

1,0002,0003,0004,0005,0006,000

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

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

3.2.2 BART SO2 Analysis 

Sulfur dioxide 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 3 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 3; 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) system with existing ESP 

• Dry FGD system with new fabric filter 

• Wet FGD system and new stack with existing ESP 

Step 2: Eliminate Technically Infeasible Options 

Dave Johnston 3 currently has an uncontrolled SO2 emission rate of 1.20 lb per MMBtu. The 

following summarizes the technical feasibility analysis performed. 

Dry FGD with Existing ESP. The lime spray dryer typically 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 3, this dry particulate matter would be 

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

typically produces a dry waste product suitable for landfill disposal. 

Dry FGD with the existing ESP is projected to achieve 81.7 percent SO2 removal. At Dave 

Johnston 3, this would result in a controlled SO2 emission rate of 0.22 lb per MMBtu, based 

on an average coal sulfur content of 0.47 percent by weight. 

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

filter located downstream of the lime spray dryer, then 90.0 percent SO2 removal is 

projected, allowing the facility to achieve a limit of 0.12 lb SO2 per MMBtu. 

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

is projected to result in a controlled SO2 emission rate of 0.15 lb per MMBtu, based on an 

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

in Section 3.2.3, Step 2. 

Wet Lime/Limestone FGD. Wet SO2 scrubbers operate by flowing the flue gas upward through 

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

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

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

reagent reacts with the SO2 in the flue gas to form calcium sulfite and/or 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 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-10
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

variations on wet FGD technology are 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. Wet 

lime/limestone scrubbing is projected to achieve an SO2 removal rate of 95 percent and an 

outlet SO2 emission rate of 0.058 lb per MMBtu. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

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

for Dave Johnston 3. 

TABLE 3-3 

SO2 Control Technology Emission Rate 

Dave Johnston 3 

Control Technology Projected Sulfur Dioxide (SO2) Emission Rate 

(pound per million British thermal units) 

Presumptive Best Available Retrofit Technology Limit 0.15 

Wet Lime/Limestone Flue Gas Desulfurization (FGD) 0.058 

Dry FGD with Fabric Filter 0.12 

Dry FGD with Existing Electrostatic Precipitator (ESP) 0.22 

Step 4: Evaluate Impacts and Document the Results 

This step involves the 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 with the existing ESP has the advantage of requiring less 

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

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

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

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

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

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

when compared to wet FGD technology: 

• Sulfuric Acid Mist. Sulfur trioxide (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 ESP or hydrated lime injection when medium to high sulfur 

coal is burned in a unit, in order 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. 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-11
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

• 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 that is saturated with water, which would require a 

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

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

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

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

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

chloride buildup in the absorber scrubbing 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 needs to 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 

that needs to be disposed. 

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

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

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

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

Economic Impacts. A summary of the costs and amounts of SO2 removed for each technology 

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

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

Appendix A. 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-12
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-13

TABLE 3-4 

SO2 Control Cost Comparison 

Dave Johnston 3 

Factor 

Dry Flue Gas 

Desulfurization 

(FGD) with 

Electrostatic 

Precipitator 

Dry FGD with 

Fabric Filter Wet Lime FGD 

Total Installed Capital Costs $91.5 million 139.0 million $144.3 million 

Total First Year Fixed and Variable 

Operation and Maintenance Costs 

$4.8 million $5.6 million $6.3 million 

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

Power Consumption (megawatts) 2.49 3.88 3.45 

Annual Power Usage 

(million kilowatt-hours per year) 

19.7 30.6 27.2 

Sulfur Dioxide (SO2) Design Control 

Efficiency 

81.7% 90.0% 95.0% 

Tons SO2 Removed per Year 10,817 11,920 12,583 

First Year Average Control Cost (dollars 

per ton [$/Ton] of SO2 Removed) 

$1,251/ton $1,576/ton $1,591/ton

Incremental Control Cost ($/Ton of SO2

Removed) 

$1,251/ton $4,758/ton $1,859/ton 

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

BART for Dave Johnston 3, based on the significant reduction in SO2 emissions, reasonable 

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

non-air quality environmental impacts. Although this approach is projected to not meet the 

BART presumptive SO2 limit of 0.15 lb per MMBtu, the cost-effectiveness analysis 

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

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

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

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

excessive incremental costs for minimal benefit in visibility.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BART A

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

Dave Johnston 3 

0

500

1,0001,5002,0002,5003,0003,5004,0004,5005,000

Dry FGD w/ESP Dry FGD w/Fabric Filter Wet FG

Air Pollution Control Option

Control Cost ($/Ton SO2 Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

3.2.3 BART PM10 Analysis 

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

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

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

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

particles drop into hoppers below the precipitator and are removed periodically by the fly 

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

MMBtu. 

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

modeling analysis to be completed in Section 4, PM10 will be used as an indicator for PM, 

and PM10 includes particulate matter less than 2.5 micrometers in aerodynamic diameter 

(PM2.5) as a subset. 

Step 1: Identify All Available Retrofit Control Technologies 

Two retrofit control technologies have been identified for additional PM control: 

• Flue gas conditioning 

• Polishing fabric filter downstream of existing ESP 

• Baghouse fabric filter 

Step 2: Eliminate Technically Infeasible Options 

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

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

which is typically accomplished by injection of SO3, will lower the resistivity of the particles 

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

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

small ESPs. 

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

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

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

improvement in collection efficiency is not expected with the addition of FGC to 

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

BART analysis. 

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

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

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

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

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

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

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

jet fabric filter (3.5 to 4:1). 

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-15
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

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

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

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

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

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

reduce PM emissions to approximately 0.015 lb per MMBtu. 

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

TABLE 3-5 

PM10 Control Technology Emission Rates 

Dave Johnston 3 

Control Technology 

Projected PM10(a) Emission Rate 

(pound per million 

British thermal units) 

Current Electrostatic Precipitator (ESP) Controls 0.030 

Polishing Fabric Filter with Existing ESP 0.015 

(a) PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter 

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 

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

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

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

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

85 percent annual plant capacity factor. 

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

COHPAC polishing fabric filter. 

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-16
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 3-17

TABLE 3-6 

PM10 Control Cost 

Dave Johnston 3 

Factor 

Compact Hybrid Particulate Collector 

(COHPAC) Fabric Filter with Existing Electrostatic 

Precipitator (ESP) 

Total Installed Capital Costs $29.8 million 

Total First Year Fixed and Variable Operations and 

Maintenance Costs 

$0.8 million 

Total First Year Annualized Cost $3.6 million 

Power Consumption (megawatts) 1.38 

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

Particulate Matter (PM) Design Control Efficiency 50.0% 

Tons PM Removed per Year 166 

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

of PM Removed) 

$22,008/ton 

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

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

BART for Dave Johnston 3, based on the significant reduction in PM10 emissions, the 

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

non-air quality environmental impacts. 

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
4.0 BART Modeling Analysis 

4.1 Model Selection 

CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of 

emissions from Dave Johnston 3 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 3 facility. These areas include: 

• Wind Cave NP 

• Badlands NP 

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

puff dispersion model (CALPUFF) with 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. Version numbers of the various programs in the CALPUFF system used by 

CH2M HILL were as follows: 

• CALMET Version 5.53a, Level 040716 

• CALPUFF Version 5.711a, Level 040716 

• CALPOST Version 5.51, Level 030709 

4.2 CALMET Methodology 

4.2.1 Dimensions of the Modeling Domain 

CH2M HILL used the CALMET model to 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 kilometers. 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_DJ3_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 3 

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 ten 

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 3 

CALMET Input Parameter Value 

CALMET Input Group 2

 Map projection (PMAP) Lambert Conformal 

 Grid spacing (DGRIDKM) 4 

 Number vertical layers (NZ) 10 

 Top of lowest layer (m) 20 

 Top of highest layer (m) 3500 

CALMET Input Group 4

 Observation mode (NOOBS) 0 

CALMET Input Group 5

 Prog. Wind data (IPROG) 14 

 (RMAX1) 30 

 (RMAX2) 50 

 Terrain influence (TERRAD) 15 

 (R1) 5 

 (R2) 25 

CALMET Input Group 6

 Max mixing ht (ZIMAX) 3500 

4.2.2 CALMET Input Data 

CH2M HILL ran the CALMET model to 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. 

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 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-3
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-4

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

generate a Step 1 wind field, and further 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 

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

SMERGE preprocessor and CALMET. 

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

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

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

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

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

Digital Elevation Model data, which 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 3 

4.2.3 Validation of CALMET Wind Field 

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

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

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

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

Atmospheric Administration, 2006). 

4.3 CALPUFF Modeling Approach 

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

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

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

over the modeling domain described earlier. The CALPUFF model 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 3. 

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 guidance document (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 3. Post-control stack parameters reflect the anticipated 

changes associated with installation of the control technology alternatives that are being 

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

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

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

new maximum heat input rate would be 2,800 MMBtu per hour. It is unclear whether this 

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

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-6
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-7

4.3.3 Emission Rates 

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

may occur under the source’s current permit. 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 (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 PM control technologies being evaluated. 

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

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

levels for each pollutant. 

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

indicated previously, this scenario represents CH2M HILL’s preliminary BART 

recommendation. 

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

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

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

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

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

maintaining the existing ESP. 

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

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

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

modeled.
TABLE 4-2 

BART Model Input Data Dave Johnston 3 

Baseline Post-control Scenario 1 Post-control Sce

Model Input Data 

Current Operation with 

Electrostatic Precipitator 

(ESP) 

Low-NOx Burners (LNBs) with Over-fire 

Air (OFA), Dry Flue Gas Desulfurization 

(FGD), Existing ESP 

LNB with OFA, D

New Fabric F

Sulfur Dioxide (SO2) Stack Emissions 

(pounds per hour [lb/hr]) 3,000 616 336 

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,750 672 672 

PM10 Stack Emissions (lb/hr) 75.0 84.0 42.0 

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

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 42.8 42.8 18.1 Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 46.0 2.58 2.58 

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 45.1 2.52 2.52 

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) 45.1 2.52 2.52 

Stack Conditions

Stack Height (meters) 152.4 152.4 152.4 Stack Exit Diameter (meters) 4.57 4.57 4.57 

Stack Exit Temperature (Kelvin) 445 350 355 Stack Exit Velocity (meters per second) 32.0 25.1 25.5 

NOTES: 

(a)Based on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 43 percent ESP and 57 percent Baghouse. PM10 and PM2.5 refer to pa

diameter.

(b)Based on AP-42, Table 1.1-6, the fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent Baghouse. 

Total Sulfate (SO4) (lb/hr) = 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 3 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology options for Unit 3 followed this 

sequence: 

• Model pre-control (baseline) emissions 

• Model preferred post-control scenario (if applicable) 

• Determine degree of visibility improvement 

• Model other control scenarios 

• Determine degree of visibility improvement 

• Factor visibility results into the BART five-step evaluation 

4.3.6 Receptor Grids 

Discrete receptors for the CALPUFF 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. 

4.4 CALPOST 

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

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

modeled. The sum of all extinction values were used to calculate the delta-dV (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 deciview values for the 10 percent best days for each Class I area, but did not 

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-9
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 4-10

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

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

2003). A separate scaling factor was derived 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 (see Appendix B) provided 

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

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

TABLE 4-3 

Average Natural Levels of Aerosol Components 

Dave Johnston 3 

Aerosol Component 

Average Natural Concentration 

(micrograms per cubic meter) 

for Wind Cave NP and Badlands NP Class I Areas 

Ammonium Sulfate 0.047 

Ammonium Nitrate 0.040 

Organic Carbon 0.186 

Elemental Carbon 0.008 

Soil 0.198 

Coarse Mass 1.191 

NOTE: 

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

4.5 Presentation of Modeling Results 

This section presents the results of the CALPUFF visibility improvement modeling analysis 

for Dave Johnston 3. 

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario 

CH2M HILL modeled Dave Johnston 3 for the 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 Unit 3. 

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

Badlands NP and Wind Cave NP 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 3 

Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost Class I Area 

Highest 

DeltaDeciview 

(ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

Number (No.) of 

Days Above 

0.5 dV 

2001 

Badlands 4.202 1.635 59 

Baseline: Current Operation with Electrostatic Precipitator (ESP) 

Wind Cave 5.191 1.597 57 

$15,149,158 Badlands 1.343 0.477 7 

Scenario 1: Low-NOx Burners (LNBs) with Over-fire Air (OFA), dry Flue 

Gas Desulfurization (FGD), existing ESP $15,149,158 Wind Cave 1.871 0.567 10 

$20,400,821 Badlands 1.101 0.378 6 

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

$20,400,821 Wind Cave 1.529 0.481 5 

$28,530,147 Badlands 0.563 0.208 1 

Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR), dry FGD, fabric filter $28,530,147 Wind Cave 0.794 0.213 1 

$29,761,524 Badlands 0.567 0.253 3 

Scenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack 

$29,761,524 Wind Cave 0.764 0.269 1 

2002 

Badlands 2.606 1.176 37 

Baseline: Current Operation with ESP 

Wind Cave 2.466 1.806 43 

$15,149,158 Badlands 0.645 0.351 4 

Scenario 1: LNB with OFA, dry FGD, existing ESP 

$15,149,158 Wind Cave 1.01 0.488 7 

$20,400,821 Badlands 0.496 0.305 0 

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

$20,400,821 Wind Cave 0.866 0.404 5 

$28,530,147 Badlands 0.276 0.143 0 

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

$28,530,147 Wind Cave 0.382 0.211 0 

$29,761,524 Badlands 0.277 0.155 0 

Scenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack 

$29,761,524 Wind Cave 0.458 0.205 0 

2003 

Badlands 3.091 1.652 47 

Baseline: Current Operation with ESP Wind Cave 4.867 2.402 49 

$15,149,158 Badlands 0.848 0.478 7 

Scenario 1: LNB with OFA, dry FGD, existing ESP $15,149,158 Wind Cave 1.552 0.748 11 

$20,400,821 Badlands 0.667 0.401 3 

Scenario 2: LNB with OFA, dry FGD, fabric filter $20,400,821 Wind Cave 1.255 0.624 10 

$28,530,147 Badlands 0.366 0.188 0 

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $28,530,147 Wind Cave 0.663 0.305 1 

$29,761,524 Badlands 0.34 0.233 0 

Scenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack $29,761,524 Wind Cave 0.614 0.312 1 JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Dave Johnston 3 

Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost Class I Area 

Highest 

DeltaDeciview 

(ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

Number (No.) of 

Days Above 

0.5 dV 

3-Year Averages 

Badlands 1.488 47.7 

Baseline: Current Operation with ESP Wind Cave 1.935 49.7 

$15,149,158 Badlands 0.435 6.0 

Scenario 1: LNB with OFA, dry FGD, existing ESP $15,149,158 Wind Cave 0.601 9.3 

$20,400,821 Badlands 0.361 3.0 

Scenario 2: LNB with OFA, dry FGD, fabric filter $20,400,821 Wind Cave 0.503 6.7 

$28,530,147 Badlands 0.180 0.3 

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $28,530,147 Wind Cave 0.243 0.7 

$29,761,524 Badlands 0.214 1.0 

Scenario 4: LNB with OFA and SCR, wet FGD, existing ESP, new stack $29,761,524 Wind Cave 0.262 0.7 

NOTES:

Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $15,149,158 / (1.635 - 0.477) = $13,082,174 

Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001: = $15,149,158 / (59 - 7) = $291,330 
5.0 Preliminary Assessment and 

Recommendations 

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

modeling analysis completed for Dave Johnston 3, the preliminary recommended BART 

controls for NOx, SO2, and PM are as follows:

• New LNBs and OFA system for NOx control

• Lime spray dryer FGD for SO2 control

• Maintain the existing ESP for PM 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, utilizing a least-cost envelope, as outlined in the New Source 

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

5.1 Least-cost Envelope Analysis 

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

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

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

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

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

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

5.1.1 Analysis Methodology 

On page B-41 of the New Source Review Manual, the 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 are ranked in ascending 

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

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

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

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

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

and cost 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 3. 

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-1
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

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

envelope depicted by the curvilinear line 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 the 

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 3 

Scenario Controls 

98th 

Percentile 

deciView 

(dV) 

Reduction 

Reduction 

in Average 

Number of 

Days 

Above 

0.5 dV 

(Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

dV 

Reduction 

(Million$/dV 

Reduced) 

Cost per 

Reduction 

in No. of 

Days Above 

0.5 dV 

(Million$/ 

Day 

Reduced) 

Base Current Operation with 

Electrostatic Precipitator 

(ESP) 

0.00 0.0 $0.0 $0.0 $0.0 

1 Low-NOx Burners (LNBs) 

with Over-fire Air (OFA), 

Dry Flue Gas 

Desulfurization (FGD), 

Existing ESP 

1.05 41.7 $15.1 $14.4 $0.4 

2 LNB with OFA, Dry FGD, 

New Fabric Filter 

1.13 44.7 $20.4 $18.1 $0.5 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), Dry 

FGD, New Fabric Filter 

1.31 47.3 $28.5 $21.8 $0.6 

4 LNB with OFA and SCR, 

Wet FGD, Existing ESP, 

New Stack 

1.27 46.7 $29.8 $23.4 $0.6 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-2
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

TABLE 5-2 

Wind Caves Class I Area Control Data 

Dave Johnston 3 

Scenario Controls 

98th

Percentile 

deciView 

(dV) 

Reduction 

Reduction 

in Average 

Number of 

Days 

Above 

0.5 dV 

(Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per dV 

Reduction 

(Million$/dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Above 0.5 dV 

(Million$/Day 

Reduced) 

Base Current Operation with 

Electrostatic Precipitator 

(ESP) 

0.00 0.0 $0.0 $0.0 $0.0 

1 Low NOx Burners (LNBs) 

with Over-fire Air (OFA), 

Dry Flue Gas 

Desulfurization (FGD), 

Existing ESP 

1.33 40.3 $15.1 $11.4 $0.4 

2 LNB with OFA, Dry FGD, 

New Fabric Filter 

1.43 43.0 $20.4 $14.2 $0.5 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), DRY 

FGD, New Fabric Filter 

1.69 49.0 $28.5 $16.9 $0.6 

4 LNB with OFA and SCR, 

Wet FGD, Existing ESP, 

New Stack 

1.67 49.0 $29.8 $17.8 $0.6 

TABLE 5-3 

Badlands Class I Area Incremental Data 

Dave Johnston 3 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 deciView 

(dV) (Days) 

Incremental dV 

Reductions (dV) 

Incremental Cost 

Effectiveness 

(Million $/Days) 

Incremental Cost 

Effectiveness 

(Million $/dV) 

Baseline and Scenario 1 41.7 1.05 $0.4 $14.4 

Scenario 1 and Scenario 2 3.0 0.07 $1.8 $71.0 

Scenario 1 and Scenario 3 5.7 0.26 $2.4 $52.3 

Scenario 1 and Scenario 4 5.0 0.22 $2.9 $65.9 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-3
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

TABLE 5-4 

Wind Caves Class I Agent Incremental Data 

Dave Johnston 3 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 deciView 

(dV) (Days) 

Incremental dV 

Reductions (dV) 

Incremental Cost 

Effectiveness 

(Million$/Days) 

Incremental 

Cost 

Effectiveness 

(Million$/dV) 

Baseline and Scenario 1 40.3 1.33 $0.4 $11.4 

Scenario 1 and Scenario 2 2.7 0.10 $2.0 $53.6 

Scenario 1 and Scenario 3 8.7 0.36 $1.5 $37.4 

Scenario 1 and Scenario 4 8.7 0.34 $1.7 $43.1 

FIGURE 5-1 

Least-cost Envelope Badlands Class I Area Days Reduction 

Dave Johnston 3 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

0 5 10 15 20 25 30 35 40 45 50

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-4
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

FIGURE 5-2 

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

Dave Johnston 3 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

FIGURE 5-3 

Least-cost Envelope Wind Caves Class I Area Days Reduction 

Dave Johnston 3 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

0 10 20 30 40 50

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

60

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-5
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

FIGURE 5-4 

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

Dave Johnston 3 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

5.1.2 Analysis of Results 

Results of the least-cost analysis, shown in 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 in three of the four categories plotted, which indicates 

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

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

deciview reduction. Scenario 4 is also not 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 4 provides some potential visibility advantage over Scenario 1, 

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

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

Figures 5-1 and 5-2 illustrates the conclusions stated above. 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 $0.4 million per day and $14.4 million per dV to 

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

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

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

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

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-6
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

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

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

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

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

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

formed by the dominant control alternative scenarios in three of the four categories plotted. 

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

5.2 Recommendations 

5.2.1 NOx Emission Control 

The BART presumptive NOx limit assigned by EPA for wall-fired cell burner boilers 

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

only PRB coal, a sub-bituminous coal. 

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

Dave Johnston 3, based on the projected significant reduction in NOx emissions, reasonable 

control costs, and the advantages of no additional power requirements or non-air quality 

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

of 0.45 lb per MMBtu. 

5.2.2 SO2 Emission Control 

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

the significant reduction in SO2 emissions, reasonable control costs, and the advantages of no 

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

this approach is projected to not meet the BART presumptive SO2 limit of 0.15 lb per 

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

Scenario 1 is excessive. 

5.2.3 PM10 Emission Control 

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

based on the significant reduction in PM10 emissions, reasonable control costs, and the 

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

impacts. 

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

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

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

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

results indicate that only 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 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-7
BART ANALYSIS FOR DAVE JOHNSTON UNIT 3 

JMS EY102007001SLC\BART_DJ3_OCT2007_FINAL.DOC 5-8

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

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

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_DJ3_OCT2007_FINAL.DOC 6-1
APPENDIX A 

Economic Analysis 
PacifiCorp BART Analysis Scenarios

1

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

 $ 15,149,158 N/A N/A  $ 15,149,158 N/A N/A  $ 20,400,821 N/A N/A  $ 20,400,821 N/A N/A  $ 28,530,147 N/A N/A  $ 28,530,147 N/A N/A  $ 29,761,524 N/A N/A  $ 29,761,524 N/A 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 3

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

Scenario 4 - LNB witSCR, Wet FGD, ESP

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
ECONOMIC ANALYSIS SUMMARY

Dave Johnston Unit 3 Boiler Design: 3-Cell Burner, Opposed Wall-Fired PC

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

Case 1 2 3 4 5 6 

NOx Emission Control System None LNB w/OFA ROFA

LNB w/OFA & 

SNCR

LNB w/OFA & 

SCR None 

SO2 Emission Control System None None None None None Dry FGD w/PM Emission Control System ESP ESP ESP ESP ESP ESP 

TOTAL INSTALLED CAPITAL COST ($) 0 15,900,001 12,054,022 24,035,544 83,301,164 91,499,73FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 506,128 Maintenance Material ($) 0 40,000 60,000 98,000 155,000 714,175 Maintenance Labor ($) 0 60,000 90,000 147,000 232,500 476,928 Administrative Labor ($) 0 0 0 0 0 0 TOTAL FIXED O&M COST 0 100,000 150,000 245,000 387,500 1,697,23Makeup Water Cost 0 0 0 0 0 99,566 Reagent Cost 0 0 0 665,287 426,024 1,351,84SCR Catalyst / FF Bag Cost 0 0 0 0 384,000 0 Waste Disposal Cost 0 0 0 0 0 701,072 Electric Power Cost 0 0 1,087,633 90,666 620,077 982,741 TOTAL VARIABLE O&M COST 0 0 1,087,633 755,953 1,430,101 3,135,22

TOTAL FIRST YEAR O&M COST 0 100,000 1,237,633 1,000,953 1,817,601 4,832,45

FIRST YEAR DEBT SERVICE ($) 0 1,512,533 1,146,673 2,286,449 7,924,258 8,704,17TOTAL FIRST YEAR COST ($) 0 1,612,533 2,384,306 3,287,402 9,741,859 13,536,62

Power Consumption (MW) 0.0 0.0 2.8 0.2 1.6 2.5 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 21.8 1.8 12.4 19.7 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 65.7% 72.9% 72.9% 90.0% 0.0% 

NOx Removed (Tons/Yr) 0 5,077 5,629 5,629 6,954 0 First Year Average Control Cost ($/Ton NOx Rem.) 0 318 424 584 1,401 0 

Incremental Control Cost ($/Ton NOx Removed) 0 318 1,398 3,035 5,555 0 

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

SO2 Removal Rate (%) 0.0% 0.0% 0.0% 0.0% 0.0% 81.7% 

SO2 Removed (Tons/Yr) 0 0 0 0 0 10,817 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 1,251 Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 1,251 

6-1 

PM Removal Rate (%) 99.42% 0.00% 0.00% 0.00% 0.00% 0.00% PM Removed (Tons/Yr) 0 0 0 0 0 0 First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 

PRESENT WORTH COST ($) 0 17,121,787 27,175,244 36,265,039 105,508,343 150,541,9

NOx Control 

Parameter Current Operation

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
INPUT CALCULATIONS

Dave Johnston Unit 3 Boiler Design: 3-Cell Burner, Opposed Wall-Fired PC

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

Case 1 2 3 4 5 6 

NOx Emission Control System None LNB w/OFA ROFA

LNB w/OFA & 

SNCR LNB w/OFA & SCR None 

SO2 Emission Control System None None None None None Dry FGD w/ESP Dry PM Emission Control System ESP ESP ESP ESP ESP ESP Unit Design and Coal CharacteristicsType of Unit PC PC PC PC PC PC Net Power Output (kW) 223,214 250,000 250,000 250,000 250,000 250,000 

Net Plant Heat Rate (Btu/kW-Hr) 11,200 11,200 11,200 11,200 11,200 11,200 Boiler Fuel Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB Dry Fork PRB 

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

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) 2,500 2,800 2,800 2,800 2,800 2,800 Coal Flow Rate (Lb/Hr) 321,172 359,712 359,712 359,712 359,712 359,712  (Ton/Yr) 1,266,059 1,417,986 1,417,986 1,417,986 1,417,986 1,417,986  (MMBtu/Yr) 19,710,000 22,075,200 22,075,200 22,075,200 22,075,200 22,075,200 

Emissions

Uncontrolled SO2 (Lb/Hr) 3,000 3,360 3,360 3,360 3,360 3,360  (Lb/MMBtu) 1.20 1.20 1.20 1.20 1.20 1.20  (Lb Moles/Hr) 46.83 52.45 52.45 52.45 52.45 52.45  (Tons/Yr) 11,826 13,245 13,245 13,245 13,245 13,245 SO2 Removal Rate (%) 0.0% 0.0% 0.0% 0.0% 0.0% 81.7%  (Lb/Hr) 0 0 0 0 0 2,744  (Ton/Yr) 0 0 0 0 0 10,817 SO2 Emission Rate (Lb/Hr) 3,000 3,360 3,360 3,360 3,360 616  (Lb/MMBtu) 1.20 1.20 1.20 1.20 1.20 0.22 

 (Ton/Yr) 11,826 13,245 13,245 13,245 13,245 2,428 Uncontrolled NOx (Lb/Hr) 1,750 1,960 1,960 1,960 1,960 1,960  (Lb/MMBtu) 0.70 0.70 0.70 0.70 0.70 0.70 

 (Lb Moles/Hr) 58.31 65.31 65.31 65.31 65.31 65.31  (Tons/Yr) 6,899 7,726 7,726 7,726 7,726 7,726 NOx Removal Rate (%) 0.0% 65.7% 72.9% 72.9% 90.0% 0.0% 

 (Lb/Hr) 0 1,288 1,428 1,428 1,764 0  (Lb Moles/Hr) 0.00 42.92 47.58 47.58 58.78 0.00  (Ton/Yr) 0 5,077 5,629 5,629 6,954 0 NOx Emission Rate (Lb/Hr) 1,750 672 532 532 196 1,960  (Lb/MMBtu) 0.70 0.24 0.19 0.19 0.07 0.70 

 (Ton/Yr) 6,899 2,649 2,097 2,097 773 7,726 Uncontrolled Fly Ash (Lb/Hr) 12,873 84 84 84 84 84  (Lb/MMBtu) 5.149 0.030 0.030 0.030 0.030 0.030  (Lb Moles/Hr) 428.9 2.8 2.8 2.8 2.8 2.8  (Tons/Yr) 50,744 331 331 331 331 331 Fly Ash Removal Rate (%) 99.42% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 12,798 0 0 0 0 0  (Ton/Yr) 50,448 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 75 84 84 84 84 84  (Lb/MMBtu) 0.030 0.030 0.030 0.030 0.030 0.030 

 (Ton/Yr) 296 331 331 331 331 331 

Parameter 

Current Operation NOx Control 

SO

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/ESP Dry 

Case 1 2 3 4 5 6 

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 15,900,001 12,054,022 24,035,544 83,301,164 0 

SO2 Emission Control System ($2006) 0 0 0 0 0 91,499,734 

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

Total Emission Control Systems ($2006) 0 15,900,001 12,054,022 24,035,544 83,301,164 91,499,734 NOx Emission Control System ($/kW) 0 64 48 96 333 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 366 PM Emission Control System ($/kW) 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 64 48 96 333 366 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 0 0 0 0 0 506,128 Maintenance Material ($) 0 40,000 60,000 98,000 155,000 714,175 Maintenance Labor ($) 0 60,000 90,000 147,000 232,500 476,928 Administrative Labor ($) 00000 0 

Total Fixed O&M Cost ($) 0 100,000 150,000 245,000 387,500 1,697,231 

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 0 173 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 99,566 

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 0.41 1.00 1.15 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 90% 

Reagent Usage (Lb/Hr) 0 0 0 456 270 3,758 First Year Reagent Cost ($) 0 0 0 665,287 426,024 1,351,845 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 128 0 

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 0 384,000 0 

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 7,309 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 0 701,072 

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% 1.10% 0.09% 0.63% 1.00%  (MW) 0.00 0.00 2.76 0.23 1.57 2.49 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 1,087,633 90,666 620,077 982,741 

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

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.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 

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 

Filte

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

 LNB w/OFA & 

SCR N/A N/A Upgraded 

4 Jim Bridger Unit 2 Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A Upgraded 5 Jim Bridger Unit 3 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A Upgraded 

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

 LNB w/OFA & 

SCR N/A N/A Upgraded 

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 

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 

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

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

LNB w/OFA & 

SCR Upgraded Dry FGD N/A Wet F

Table 2 - Unit Design and Coal Characteristics

NOx SO2 PM Boiler Design

Net Power 

Output (kW)

Net Plant Heat 

Rate (Btu/kW-Hr) Coal

Heating 

HHV (B

1 Dave Johnston Unit 3 None None ESP

3-Cell Burner, Opposed 

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

2 Dave Johnston Unit 4 Windbox Mods.

Lime Added to Venturi 

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

3 Jim Bridger Unit 1

LNCFS-1 & 

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

Bridger Mine 

Underground 

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

Bridger Mine 

Underground 

5 Jim Bridger Unit 3

LNCFS-1 & 

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

Bridger Mine 

Underground 

6 Jim Bridger Unit 4

LNCFS-1 & 

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

Bridger Mine 

Underground 

7 Naughton Unit 1 None None ESP Tangential-Fired PC 173,000 10,694 Kemmerer Mine 8 Naughton Unit 2 None None ESP Tangential-Fired PC 226,000 10,574 Kemmerer Mine 9 Naughton Unit 3 LNCFS II LNB Wet FGD ESP Tangential-Fired PC 356,000 10,336 Kemmerer Mine 

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

Current Emission Control Systems Unit Design 

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

NOx Control SO2 Control 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
Table 3 - Emissions

Controlled 

SO2 Controlled NOx

Controlled 

PM Case 2 Case 3 Case 4 Case 5 Case 

1 Dave Johnston Unit 3 1.20 0.70 0.030 0.24 0.19 0.19 0.07 

 

2 Dave Johnston Unit 4 0.50 0.40 0.061 0.15 0.15 0.12 0.07 3 Jim Bridger Unit 1 0.27 0.45 0.045 0.24 0.22 0.20 0.07 

4 Jim Bridger Unit 2 0.27 0.24 0.074 0.24 0.22 0.20 0.07 5 Jim Bridger Unit 3 0.27 0.45 0.057 0.24 0.22 0.20 0.07 6 Jim Bridger Unit 4 0.17 0.45 0.030 0.24 0.22 0.20 0.07 7 Naughton Unit 1 1.20 0.58 0.056 0.24 0.28 0.18 0.07 

 

8 Naughton Unit 2 1.20 0.54 0.064 0.24 0.28 0.18 0.07 

 

9 Naughton Unit 3 0.50 0.45 0.094 0.35 0.30 0.25 0.07 

10 Wyodak Unit 1 0.50 0.50 0.030 0.23 0.18 0.22 0.07 

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. P

Usage 

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. P

Usage 

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 C

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_PCorpDJ3BARTEconomic Analysis_Oct2007.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. P

Usage 

1 Dave Johnston Unit 3 $ 60,000 - $ 90,000 $ - $ - None - 

2 Dave Johnston Unit 4 $ 54,000 - $ 81,000 $ $ - - None - 3 Jim Bridger Unit 1 $ 42,000 - $ 63,000 $ $ - - None - 4 Jim Bridger Unit 2 $ 42,000 - $ 63,000 $ $ - - None - 5 Jim Bridger Unit 3 $ 42,000 - $ 63,000 $ $ - - None - 6 Jim Bridger Unit 4 $ 42,000 - $ 63,000 $ $ - - None - 7 Naughton Unit 1 $ 48,000 - $ 72,000 $ $ - - None - 8 Naughton Unit 2 $ 48,000 - $ 72,000 $ $ - - None - 9 Naughton Unit 3 $ 48,000 - $ 72,000 $ $ - - None - 

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

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. P

Usage 

1 Dave Johnston Unit 3 $ 98,000 - $ 147,000 $ - $ - Urea 0.41 

2 Dave Johnston Unit 4 $ 105,000 - $ 157,500 $ $ - - Urea 0.45 3 Jim Bridger Unit 1 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 4 Jim Bridger Unit 2 $ 95,000 - $ 142,500 $ $ - - Urea 0.45 5 Jim Bridger Unit 3 $ 122,000 - $ 183,000 $ $ - - Urea 0.45 6 Jim Bridger Unit 4 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 7 Naughton Unit 1 $ 83,000 - $ 124,500 $ $ - - Urea 0.45 8 Naughton Unit 2 $ 93,000 - $ 139,500 $ $ - - Urea 0.51 9 Naughton Unit 3 $ 75,000 - $ 112,500 $ $ - - Urea 0.45 

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

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.

Annua

Catalyst R

(m3

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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_PCorpDJ3BARTEconomic Analysis_Oct2007.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 F

Repla

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 F

Repla

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

 

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

 

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

 

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 F

Repla

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 

 

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_PCorpDJ3BARTEconomic Analysis_Oct2007.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 F

Repla

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 F

Repla

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

Table 14 - Major Materials Design and Supply Costs

2 3 4 5 6 7 8 9 

1 Dave Johnston Unit 3 $ 5,449,830 $ 3,556,617 $ 5,773,000 $ 49,355,000 $ 56,379,000 $ 85,647,000 $ 88,913,000 $ 

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 $ 

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 $ 

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

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

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 

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

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
CAPITAL COST

Dave Johnston Unit 3

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 $5,449,830 Vendor $3,556,617 Vendor $5,449,830 Vendor $5,449,830 Vendor $0 Vendor 

Construction 85.3% $4,650,545 85.3% $3,034,995 85.3% $4,650,545 85.3% $4,650,545 85.3% $0 85.3% 

Balance of Plant 51.7% $2,817,134 51.7% $1,838,492 51.7% $2,817,134 51.7% $2,817,134 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $1,066,985 0.0% $0 0.0% $0 0.0% $0 0.0% 

Owner's Costs 13.2% $722,012 13.2% $471,193 13.2% $722,012 13.2% $722,012 13.2% $0 13.2% 

Surcharge 16.4% $895,161 16.4% $584,192 16.4% $895,161 16.4% $895,161 16.4% $0 16.4% AFUDC 12.2% $665,885 12.2% $434,564 12.2% $665,885 12.2% $665,885 12.2% $0 12.2% Subtotal $15,200,567 $10,987,037 $15,200,567 $15,200,567 $0 Contingency 12.8% $699,434 30.0% $1,066,985 12.8% $699,434 12.8% $699,434 12.8% $0 12.8% Total Capital Cost for LNB w/OFA or ROFA $15,900,001 $12,054,022 $15,900,001 $15,900,001 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $5,773,000 S&L Report $49,355,000 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $1,154,600 10.0% $4,935,500 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $322,884 5.6% $2,760,425 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $4,169,017 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% $63,618 1.1% $543,892 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% $162,048 0.0% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $659,392 11.4% $5,637,328 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $8,135,543 $67,401,162 $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 $56,379,000 S&L Repor

Contingency 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% $11,275,800 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% $3,153,277 5.6% 

EPC Premium 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% $4,762,334 8.4% 

Boiler Reinforcement (Allowance) 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,586,505 2.8% 

Sales Tax 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% $621,297 1.1% 

Escalation 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% $5,699,353 10.1% 

Contingency on Adders 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,582,559 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% $6,439,609 11.4% 

Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $91,499,734 

LNB w/OFA & SNCR Dry FGD w/ESP Dry FGD 

SO2 

LNB w/OFA

None

ESP ESP

ROFA

None

Dry FGD 

Parameter

LNB w/OFA ROFA LNB w/OFA & SCR

None

Dry FGD w/ESP

ESP

LNB w/OFA & SNCR

None

ESP ESP

LNB w/OFA & SCR

None

NOx Control

2 3 45 

6 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
Dave Johnston Unit 3 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 100,000 - - - - - - 

 

2 2015 102,000 - - - - - - 

 

3 2016 104,040 - - - - - - 

 

4 2017 106,121 - - - - - - 

 

5 2018 108,243 - - - - - - 

 

6 2019 110,408 - - - - - - 

 

7 2020 112,616 - - - - - - 

 

8 2021 114,869 - - - - - - 

 

9 2022 117,166 - - - - - - 

 

10 2023 119,509 - - - - - - 

 

11 2024 121,899 - - - - - - 

 

12 2025 124,337 - - - - - - 

 

13 2026 126,824 - - - - - - 

 

14 2027 129,361 - - - - - - 

 

15 2028 131,948 - - - - - - 

 

16 2029 134,587 - - - - - - 

 

17 2030 137,279 - - - - - - 

 

18 2031 140,024 - - - - - - 

 

19 2032 142,825 - - - - - - 

 

20 2033 145,681 - - - - - - 

 

Present Worth - 1,221,785 - - - - - 1

 

(% of PW) 7.1% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Dave Johnston Unit 3 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 150,000 - - - - 1,087,633 1,087,633 

 

2 2015 153,000 - - - - 1,109,386 1,109,386 

 

3 2016 156,060 - - - - 1,131,574 1,131,574 

 

4 2017 159,181 - - - - 1,154,205 1,154,205 

 

5 2018 162,365 - - - - 1,177,289 1,177,289 

 

6 2019 165,612 - - - - 1,200,835 1,200,835 

 

7 2020 168,924 - - - - 1,224,852 1,224,852 

 

8 2021 172,303 - - - - 1,249,349 1,249,349 

 

9 2022 175,749 - - - - 1,274,336 1,274,336 

 

10 2023 179,264 - - - - 1,299,822 1,299,822 

 

11 2024 182,849 - - - - 1,325,819 1,325,819 

 

12 2025 186,506 - - - - 1,352,335 1,352,335 

 

13 2026 190,236 - - - - 1,379,382 1,379,382 

 

14 2027 194,041 - - - - 1,406,970 1,406,970 

 

15 2028 197,922 - - - - 1,435,109 1,435,109 

 

16 2029 201,880 - - - - 1,463,811 1,463,811 

 

17 2030 205,918 - - - - 1,493,087 1,493,087 

 

18 2031 210,036 - - - - 1,522,949 1,522,949 

 

19 2032 214,237 - - - - 1,553,408 1,553,408 

 

20 2033 218,522 - - - - 1,584,476 1,584,476 

 

Present Worth - 1,832,678 - - - 13,288,544 13,288,544 1

 

(% of PW) 6.7% 0.0% 0.0% 0.0% 0.0% 48.9% 48.9% 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
Dave Johnston Unit 3 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 245,000 - 665,287 - - 90,666 755,953 

 

2 2015 249,900 - 678,593 - - 92,479 771,072 

 

3 2016 254,898 - 692,164 - - 94,329 786,493 

 

4 2017 259,996 - 706,008 - - 96,215 802,223 

 

5 2018 265,196 - 720,128 - - 98,140 818,268 

 

6 2019 270,500 - 734,530 - - 100,103 834,633 

 

7 2020 275,910 - 749,221 - - 102,105 851,326 

 

8 2021 281,428 - 764,205 - - 104,147 868,352 

 

9 2022 287,057 - 779,490 - - 106,230 885,719 

 

10 2023 292,798 - 795,079 - - 108,354 903,434 

 

11 2024 298,654 - 810,981 - - 110,521 921,502 

 

12 2025 304,627 - 827,201 - - 112,732 939,932 

 

13 2026 310,719 - 843,745 - - 114,986 958,731 

 

14 2027 316,934 - 860,619 - - 117,286 977,906 

 

15 2028 323,272 - 877,832 - - 119,632 997,464 

 

16 2029 329,738 - 895,388 - - 122,024 1,017,413 

 

17 2030 336,332 - 913,296 - - 124,465 1,037,761 

 

18 2031 343,059 - 931,562 - - 126,954 1,058,516 

 

19 2032 349,920 - 950,193 - - 129,493 1,079,687 

 

20 2033 356,919 - 969,197 - - 132,083 1,101,281 

 

Present Worth - 2,993,374 8,128,377 - - 1,107,744 9,236,121 2

 

(% of PW) 8.3% 0.0% 22.4% 0.0% 0.0% 3.1% 25.5% 

Dave Johnston Unit 3 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 387,500 - 426,024 384,000 - 620,077 1,430,101 

 

2 2015 395,250 - 434,545 391,680 - 632,478 1,458,703 

 

3 2016 403,155 - 443,236 399,514 - 645,128 1,487,877 

 

4 2017 411,218 - 452,100 407,504 - 658,030 1,517,634 

 

5 2018 419,442 - 461,142 415,654 - 671,191 1,547,987 

 

6 2019 427,831 - 470,365 423,967 - 684,615 1,578,947 

 

7 2020 436,388 - 479,772 432,446 - 698,307 1,610,526 

 

8 2021 445,116 - 489,368 441,095 - 712,273 1,642,736 

 

9 2022 454,018 - 499,155 449,917 - 726,519 1,675,591 

 

10 2023 463,098 - 509,138 458,916 - 741,049 1,709,103 

 

11 2024 472,360 - 519,321 468,094 - 755,870 1,743,285 

 

12 2025 481,808 - 529,707 477,456 - 770,987 1,778,151 

 

13 2026 491,444 - 540,302 487,005 - 786,407 1,813,714 

 

14 2027 501,273 - 551,108 496,745 - 802,135 1,849,988 

 

15 2028 511,298 - 562,130 506,680 - 818,178 1,886,988 

 

16 2029 521,524 - 573,372 516,813 - 834,541 1,924,727 

 

17 2030 531,954 - 584,840 527,150 - 851,232 1,963,222 

 

18 2031 542,594 - 596,537 537,693 - 868,257 2,002,486 

 

19 2032 553,445 - 608,467 548,447 - 885,622 2,042,536 

 

20 2033 564,514 - 620,637 559,415 - 903,335 2,083,387 

 

Present Worth - 4,734,418 5,205,100 4,691,656 - 7,576,005 17,472,761 8

 

(% of PW) 4.5% 0.0% 4.9% 4.4% 0.0% 7.2% 16.6% 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
Dave Johnston Unit 3 Dry FGD w/ESP

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 1,697,231 99,566 1,351,845 - 701,072 982,741 3,135,224 

 

2 2015 1,731,175 101,557 1,378,882 - 715,093 1,002,395 3,197,928 

 

3 2016 1,765,799 103,588 1,406,460 - 729,395 1,022,443 3,261,887 

 

4 2017 1,801,115 105,660 1,434,589 - 743,983 1,042,892 3,327,125 

 

5 2018 1,837,137 107,773 1,463,281 - 758,863 1,063,750 3,393,667 

 

6 2019 1,873,880 109,929 1,492,547 - 774,040 1,085,025 3,461,540 

 

7 2020 1,911,358 112,127 1,522,398 - 789,521 1,106,726 3,530,771 

 

8 2021 1,949,585 114,370 1,552,845 - 805,311 1,128,860 3,601,387 

 

9 2022 1,988,576 116,657 1,583,902 - 821,417 1,151,437 3,673,414 

 

10 2023 2,028,348 118,990 1,615,580 - 837,846 1,174,466 3,746,883 

 

11 2024 2,068,915 121,370 1,647,892 - 854,603 1,197,955 3,821,820 

 

12 2025 2,110,293 123,798 1,680,850 - 871,695 1,221,914 3,898,257 

 

13 2026 2,152,499 126,274 1,714,467 - 889,129 1,246,353 3,976,222 

 

14 2027 2,195,549 128,799 1,748,756 - 906,911 1,271,280 4,055,746 

 

15 2028 2,239,460 131,375 1,783,731 - 925,049 1,296,705 4,136,861 

 

16 2029 2,284,249 134,003 1,819,406 - 943,550 1,322,639 4,219,598 

 

17 2030 2,329,934 136,683 1,855,794 - 962,421 1,349,092 4,303,990 

 

18 2031 2,376,533 139,416 1,892,910 - 981,670 1,376,074 4,390,070 

 

19 2032 2,424,064 142,205 1,930,768 - 1,001,303 1,403,596 4,477,872 

 

20 2033 2,472,545 145,049 1,969,384 - 1,021,329 1,431,667 4,567,429 

 

Present Worth 1,216,482 20,736,517 16,516,649 - 8,565,593 12,006,980 38,305,704 9

 

(% of PW) 13.8% 0.8% 11.0% 0.0% 5.7% 8.0% 25.4% 

Dave Johnston Unit 3 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 1,697,231 99,566 1,351,845 151,563 735,825 1,529,496 3,868,295 1

 

2 2015 1,731,175 101,557 1,378,882 154,594 750,542 1,560,086 3,945,661 1

 

3 2016 1,765,799 103,588 1,406,460 157,686 765,553 1,591,288 4,024,575 1

 

4 2017 1,801,115 105,660 1,434,589 160,840 780,864 1,623,113 4,105,066 1

 

5 2018 1,837,137 107,773 1,463,281 164,056 796,481 1,655,576 4,187,167 1

 

6 2019 1,873,880 109,929 1,492,547 167,337 812,411 1,688,687 4,270,911 1

 

7 2020 1,911,358 112,127 1,522,398 170,684 828,659 1,722,461 4,356,329 1

 

8 2021 1,949,585 114,370 1,552,845 174,098 845,232 1,756,910 4,443,456 1

 

9 2022 1,988,576 116,657 1,583,902 177,580 862,137 1,792,048 4,532,325 1

 

10 2023 2,028,348 118,990 1,615,580 181,131 879,380 1,827,889 4,622,971 1

 

11 2024 2,068,915 121,370 1,647,892 184,754 896,967 1,864,447 4,715,431 1

 

12 2025 2,110,293 123,798 1,680,850 188,449 914,906 1,901,736 4,809,739 1

 

13 2026 2,152,499 126,274 1,714,467 192,218 933,205 1,939,771 4,905,934 1

 

14 2027 2,195,549 128,799 1,748,756 196,062 951,869 1,978,566 5,004,053 1

 

15 2028 2,239,460 131,375 1,783,731 199,984 970,906 2,018,137 5,104,134 1

 

16 2029 2,284,249 134,003 1,819,406 203,983 990,324 2,058,500 5,206,216 1

 

17 2030 2,329,934 136,683 1,855,794 208,063 1,010,131 2,099,670 5,310,341 1

 

18 2031 2,376,533 139,416 1,892,910 212,224 1,030,333 2,141,664 5,416,548 1

 

19 2032 2,424,064 142,205 1,930,768 216,469 1,050,940 2,184,497 5,524,878 1

 

20 2033 2,472,545 145,049 1,969,384 220,798 1,071,959 2,228,187 5,635,376 1

 

Present Worth 1,216,482 20,736,517 16,516,649 1,851,770 8,990,208 18,687,158 47,262,266 13

 

(% of PW) 10.0% 0.6% 8.0% 0.9% 4.3% 9.0% 22.8% 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
Dave Johnston Unit 3 Wet FGD w/ESP

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 2,780,782 132,371 1,134,609 - 884,924 1,359,990 3,511,894 1

 

2 2015 2,836,398 135,018 1,157,301 - 902,623 1,387,190 3,582,132 1

 

3 2016 2,893,125 137,719 1,180,447 - 920,675 1,414,934 3,653,774 1

 

4 2017 2,950,988 140,473 1,204,056 - 939,089 1,443,232 3,726,850 1

 

5 2018 3,010,008 143,282 1,228,137 - 957,870 1,472,097 3,801,387 1

 

6 2019 3,070,208 146,148 1,252,700 - 977,028 1,501,539 3,877,415 1

 

7 2020 3,131,612 149,071 1,277,754 - 996,568 1,531,570 3,954,963 1

 

8 2021 3,194,244 152,053 1,303,309 - 1,016,500 1,562,201 4,034,062 1

 

9 2022 3,258,129 155,094 1,329,375 - 1,036,830 1,593,445 4,114,743 1

 

10 2023 3,323,292 158,195 1,355,963 - 1,057,566 1,625,314 4,197,038 1

 

11 2024 3,389,758 161,359 1,383,082 - 1,078,718 1,657,820 4,280,979 1

 

12 2025 3,457,553 164,587 1,410,744 - 1,100,292 1,690,977 4,366,599 1

 

13 2026 3,526,704 167,878 1,438,958 - 1,122,298 1,724,796 4,453,931 1

 

14 2027 3,597,238 171,236 1,467,738 - 1,144,744 1,759,292 4,543,009 1

 

15 2028 3,669,183 174,661 1,497,092 - 1,167,639 1,794,478 4,633,869 1

 

16 2029 3,742,566 178,154 1,527,034 - 1,190,991 1,830,367 4,726,547 1

 

17 2030 3,817,418 181,717 1,557,575 - 1,214,811 1,866,975 4,821,078 1

 

18 2031 3,893,766 185,351 1,588,726 - 1,239,107 1,904,314 4,917,499 1

 

19 2032 3,971,641 189,058 1,620,501 - 1,263,889 1,942,401 5,015,849 1

 

20 2033 4,051,074 192,839 1,652,911 - 1,289,167 1,981,249 5,116,166 1

 

Present Worth 1,617,288 33,975,185 13,862,485 - 10,811,873 16,616,158 42,907,804 14

 

(% of PW) 15.4% 0.7% 6.3% 0.0% 4.9% 7.5% 19.4% 

Dave Johnston Unit 3 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 112,540 - - 151,563 - 545,179 696,741 

 

2 2015 114,791 - - 154,594 - 556,082 710,676 

 

3 2016 117,087 - - 157,686 - 567,204 724,890 

 

4 2017 119,429 - - 160,840 - 578,548 739,387 

 

5 2018 121,817 - - 164,056 - 590,119 754,175 

 

6 2019 124,254 - - 167,337 - 601,921 769,259 

 

7 2020 126,739 - - 170,684 - 613,960 784,644 

 

8 2021 129,274 - - 174,098 - 626,239 800,337 

 

9 2022 131,859 - - 177,580 - 638,764 816,343 

 

10 2023 134,496 - - 181,131 - 651,539 832,670 

 

11 2024 137,186 - - 184,754 - 664,570 849,324 

 

12 2025 139,930 - - 188,449 - 677,861 866,310 

 

13 2026 142,728 - - 192,218 - 691,418 883,636 

 

14 2027 145,583 - - 196,062 - 705,247 901,309 

 

15 2028 148,495 - - 199,984 - 719,352 919,335 

 

16 2029 151,465 - - 203,983 - 733,739 937,722 

 

17 2030 154,494 - - 208,063 - 748,413 956,476 

 

18 2031 157,584 - - 212,224 - 763,382 975,606 

 

19 2032 160,735 - - 216,469 - 778,649 995,118 

 

20 2033 163,950 - - 220,798 - 794,222 1,015,020 

 

Present Worth - 1,375,002 - 1,851,770 - 6,660,912 8,512,683 2

 

(% of PW) 3.5% 0.0% 0.0% 4.7% 0.0% 16.8% 21.5% 

EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 
EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 

First Year Cost for Air Pollution Control Options

0

5,000,000

10,000,00015,000,00020,000,00025,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Dry FGD

w/ESP

Dry FGD

w/Fabric Filter

Wet 

w/E

Air Pollution Control Option

First Year Cost ($)
EY102007001SLC\App A_PCorpDJ3BARTEconomic Analysis_Oct2007.xls 

Present Worth Cost for Air Pollution Control Options

0

50,000,000

100,000,000150,000,000200,000,000250,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Dry FGD

w/ESP

Dry FGD

w/Fabric Filter

Wet 

w/

Air Pollution Control Options

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

2006 Wyoming BART Protocol