Final Report 

BART Analysis for 

Naughton 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 

Naughton Unit 3 

Submitted to 

PacifiCorp 

December 2007 
Executive Summary 

Background 

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 Naughton Unit 3 (hereafter referred to as Naughton 3). A BART analysis has 

been conducted for the following criteria pollutants: nitrogen oxides (NOx), sulfur dioxide 

(SO2), and particulate matter less than 10 micrometers in aerodynamic diameter (PM10). The 

Naughton Station consists of three units with a total generating capacity of 700 megawatts 

(MW). Presumptive BART limits therefore do not directly apply to Naughton 3, based on the 

United States Environmental Protection Agency’s (EPA) guidelines. Presumptive BART 

limits are a goal, unless it is determined that an alternative control level is justified based on a 

careful consideration of the statutory factors. BART emissions limits must be achieved 

within five 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: 

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

− Rotating opposed fire air (ROFA) 

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

− LNBs with OFA and selective catalytic reduction (SCR) system 

• SO2 emission controls: 

− Upgrade wet waste sodium liquor flue gas desulfurization (FGD) system 

− Upgrade wet sodium FGD system and use soda ash reagent 

• PM10 emission controls: 

− Enhancements to existing electrostatic precipitator (ESP) 

− Polishing fabric filter 

− Replacement fabric filter 

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BART ANALYSIS FOR NAUGHTON 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. 

Coal Characteristics 

The main source of coal burned at Naughton 3 will be the low sulfur and high sulfur P&M 

Kemmerer Mine (P&M). These coals are ranked as sub-bituminous, but are closer in 

characteristics to bituminous coal in many of the parameters influencing NOx formation. 

These coals have higher nitrogen content than coals from the Powder River Basin (PRB), 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-2
BART ANALYSIS FOR NAUGHTON UNIT 3 

which represent the bulk of sub-bituminous coal use in the U.S. This BART analysis has 

considered the higher nitrogen content and the different combustion characteristics of PRB 

coals, as compared to those coals used at Naughton 3, and has evaluated the effect of these 

qualities on NOx formation and achievable emission rates. 

Recommendations 

For BART emission control at Naughton 3, CH2M HILL recommends tuning the existing 

low-NOx burners with over-fire air (LNB with OFA) for NOx, upgrading the wet waste 

sodium liquor FGD system for SO2, and enhancements to the existing ESP for PM10. This 

combination of control devices is referred to as Scenario 1 throughout this report. 

NOx Emission Control 

Naughton 3 burns coal from the P&M Kemmerer Mine. As documented in this analysis, the 

characteristics of the P&M Kemmerer Mine coals are more closely aligned with bituminous 

coals. 

CH2M HILL recommends tuning the existing low-NOx burners with over-fire air (LNB with 

OFA) as BART for Naughton 3, based on the projected NOx emissions, reasonable control 

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

environmental impacts. 

SO2 Emission Control 

CH2M HILL recommends upgrading the wet waste sodium liquor FGD system as BART for 

Naughton 3, based on the significant reduction in SO2 emissions, reasonable control costs, 

and the advantages of both lower power requirements and non-air quality environmental 

impacts. 

PM10 Emission Control 

CH2M HILL recommends enhancements to the existing ESP as BART for Naughton 3, 

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

advantage of both no additional power requirements and non-air quality environmental 

impacts. 

BART Modeling Analysis 

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

emissions from Naughton 3 at Class I areas. The Class I areas potentially affected are located 

more than 50 kilometers, but less than 300 kilometers, from the Naughton 3 Plant. 

The Class I areas include the following wilderness areas (WAs): 

• Bridger WA 

• Fitzpatrick WA 

Because Naughton 3 will simultaneously control NOx, SO2, and PM10 emissions, four 

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

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BART ANALYSIS FOR NAUGHTON UNIT 3 

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: Tune LNB with OFA, upgrade waste liquor FGD, and enhance existing ESP. 

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

recommendation. 

• Scenario 2: LNB with OFA and SCR, upgrade waste liquor FGD, and enhance existing 

ESP. 

• Scenario 3: LNB with OFA and SCR, upgrade waste liquor FGD, and new fabric filter. 

• Scenario 4: LNB with OFA and SCR, upgrade wet FGD and use soda ash reagent, and 

new fabric filter. 

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 Manual.1

Least-cost Envelope Analysis 

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 three 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 three 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. The other scenarios were eliminated for the 

following reasons: 

• Scenario 2 (LNB with OFA, upgrade waste liquor FGD, and fabric filter) 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, upgrade waste liquor FGD, and enhance ESP) has 

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

per dV reduction. 

 

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

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BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-5

• While Scenario 4 (LNB with OFA and SCR, upgrade wet FGD and use soda ash, and 

new fabric filter) 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 Naughton 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 only minimal 

discernable visibility improvements may result, even though PacifiCorp will be spending 

many millions of dollars at this single unit, and over a billion dollars when considering its 

entire fleet of coal-fired power plants. 
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 .................................................................. 3-14 

3.2.3 BART PM10 Analysis ................................................................ 3-17 

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............................................................................. 4-6 

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 

\\SNOWBIRD\PROJ\PACIFICORP\348295BART\OCT 2007 REVISIONS\NAUGHTON3_OCT2007_FINAL.DOC iii
CONTENTS (CONTINUED) 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC iv

Tables 

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 Coal Source and Characteristics

3-2 NOx Control Technology Emission Rates

3-3 NOx Control Cost Comparison

3-4 SO2 Control Cost Comparison (Incremental to Existing FGD System)

3-5 PM10 Control Technology Emission Rate Ranking

3-6 PM10 Control Cost Comparison

4-1 User-specified CALMET Options

4-2 BART Model Input Data

4-3 Average Natural Levels of Aerosol Components

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

Class I Areas

5-1 Bridger WA Class I Agent Control Data

5-2 Fitzpatrick WA Class I Area Control Data

5-3 Bridger WA Class I Agent Incremental Data

5-4 Fitzpatrick WA Class I Area Incremental Data

Figures 

3-1 Illustration of the Effect of Agglomeration on the Speed of Coal Combustion 

3-2 Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive 

BART NOx Limits 

3-3 Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART 

NOx Limits 

3-4 First Year Control Cost for NOx Air Pollution Control Options 

3-5 First Year Control Cost for SO2 Air Pollution Control Options 

3-6 First Year Control Cost for PM Air Pollution Control Options 

4-1 Naughton Source-specific Class I Areas to be Addressed 

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

5-1 Least-cost Envelope Bridger WA Class I Area Reduction 

5-2 Least-cost Envelope Bridger WA Class I Area 98th Percentile 

5-3 Least-cost Envelope Fitzpatrick WA Class I Area Reduction 

5-4 Least-cost Envelope Fitzpatrick WA Class I Area 98th Percentile 

Appendices 

A Economic Analysis

B 2006 Wyoming BART Protocol
Acronyms and Abbreviations 

$/Ton Dollars per Ton 

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 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

ESP Electrostatic Precipitator 

EPA United States Environmental Protection Agency 

FGC Flue Gas Conditioning 

FGD Flue Gas Desulfurization 

kWh Kilowatt-hour 

LAER Lowest Achievable Emission Rate 

lb Pound 

LNB Low-NOx burner 

MMBtu Million British thermal units 

MM5 Mesoscale Meteorological Model, Version 5 

MW Megawatt 

NOx Nitrogen Oxides 

NH4)HSO4 Ammonium bisulfate 

(NH4)2SO4 Ammonium sulfate 

OFA Over-fire Air 

P&M P&M Kemmerer Mine 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC v
ACRONYMS AND ABBREVIATIONS (CONTINUED) 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC vi

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

PM10 Particulate Matter less than 10 Micrometers in Aerodynamic Diameter 

PRB Powder River Basin 

ROFA Rotating Opposed Fire Air 

S&L Sargent & Lundy 

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

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 

WA Wilderness Area 

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 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 Wyoming DEQ to submit the 

BART report for Naughton Unit 3 (hereafter referred to as Naughton 3) by February 9, 2007. 

The BART Report that was submitted to WDEQ in February 2007 included a BART 

analysis, and a proposal and justification for BART at the source. This revised report—

submitted in October 2007—incorporates editorial revisions and new model runs since the 

February 2007 version. 

The State of Wyoming has identified those eligible in-state facilities that are required to 

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

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

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

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

5 years of EPA’s approval of the SIP. 

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

• The cost of the controls 

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

• Any existing pollution control technology in use at the source 

• The remaining useful life of the source 

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

of such technology 

This report documents the BART analysis that was performed on Naughton 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 affect visibility. 

Section 2 of this report provides a description of the present unit operation, including a 

discussion of coal sources and characteristics. The BART Engineering Analysis is provided 

in Section 3 by pollutant type. Section 4 provides the methodology and results of the BART 

Modeling Analysis, followed by recommendations in Section 5 and references are provided 

in Section 6. Appendices provide more detail on the economic analysis and the 2006 

Wyoming BART Protocol. 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 1-1
2.0 Present Unit Operation 

Naughton 3 is a nominal 330-megawatt (MW) unit located approximately 6 miles southwest 

of Kemmerer, Wyoming. The unit is a tangentially fired boiler manufactured by Combustion 

Engineering (now Alstom). Alstom LCCFS II low-NOx burners (LNBs) were installed in 

1999. Particulate emissions are collected by a Buell weighted wire electrostatic precipitator 

(ESP). A UOP, two-tower, sodium-based wet flue gas desulfurization system (FGD) was 

added in 1981 and a Honeywell distributed control system was installed in 1997. 

Naughton 3 began operation in 1971. Its current economic depreciation life is through 2032; 

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 Naughton 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 the unit at Naughton 3 to operate until 2033. 

Table 2-1 lists additional unit information and study assumptions for this analysis. 

Coal sources and characteristics are summarized in Table 2-2. 

The main source of coal burned at Naughton 3 is the P&M Kemmerer Mine (P&M). This 

coal is ranked as sub-bituminous, but is closer in characteristics to bituminous coal in many 

of the parameters influencing NOx formation. This coal has higher nitrogen content than 

coals from the Powder River Basin (PRB), which represent the bulk of sub-bituminous coal 

use in the U.S. 

This BART analysis has considered the higher nitrogen content and different combustion 

characteristics of PRB coals, as compared to those coals used Naughton 3, and the effect of 

these qualities on NOx formation. Coal sources and characteristics are summarized in 

Table 2-2. The primary source of coal will be the P&M mine, and data on coal from this 

source were used in the modeling analysis. 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 2-2

TABLE 2-1 

Present Unit Operation 

Naughton 3 

General Plant Data 

Site Elevation (feet above mean sea level) 6939 

Stack Height (feet) 475 

Stack Exit internal diameter (feet / Exit Area [square feet]) 26.5 / 551.5 

Stack Exit Temperature °F (degrees Fahrenheit) 120 

Stack Exit Velocity (feet per second) 43 

Stack Flow (actual cubic feet per minute) 1,422,679 

Latitude (degree: minute: second) 41:45:31.91 

Longitude (degree: minute: second) 110:35:49.47 

Annual Unit Capacity Factor (percentage) 90 

Net Unit Output (megawatts) 330 

Net Unit Heat Rate (British thermal unit [Btu]/kilowatthour)(100% load) 10,336 (4 yr. avg. 4/1/02-3/31/06) 

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

(100% load) 3,700 

Type of Boiler Tangentially Fired 

Boiler Fuel Coal 

Coal Sources P&M Kemmerer Mine 

Coal Heating Value (Btu per pound [lb])(a) 9,950 

Coal Sulfur Content (percentage by weight [wt. %])(a) 1.45 

Coal Ash Content (wt. %)(a) 5.50 

Coal Moisture Content (wt. %)(a) 21.0 

Coal Nitrogen Content (wt. %)(a) 1.3 

Current Nitrogen Oxide (NOx) Controls Low-NOx Burners 

Pre-project NOx Emission Rate (lb per MMBtu) 0.45 

Current Sulfur Dioxide (SO2) Controls Wet Scrubber 

Pre-project SO2 Emission Rate (lb per MMBtu) 0.50 

Current PM10 Controls ESP 

Pre-project Particulate Matter Emission Rate (lb per MMBtu) (b) 0.094 

(a) Coal characteristics vary between coal sources (b) Emission rates stated from test results 
BA

TABLE 2-2 Coal Sources and Characteristics Naughton 3 

Ultimate Analysis (

Mines 

Moisture 

(%) 

Ash 

(%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

units 

per 

pound 

(Btu/lb) 

Sulfur 

(%) Hydrogen Carbon Sulfur N

Low Sulfur P&M Kemmerer Mine (P&M) Average 20.90 4.49 33.46 41.17 9970 0.59 5.06 71.67 0.73 

Standard Deviation * 0.97 1.11 0.57 1.18 303 0.05 0.19 1.43 0.06 High Sulfur P&M Mine 

Average 20.26 5.50 33.77 40.48 9965 1.29 5.02 70.87 1.68 

Standard Deviation * 0.84 1.41 0.50 1.44 232 0.29 0.20 1.34 0.33 

NOTES:* Statistics are based on daily delivered samples except for ultimate analysis, which is based on weekly composites of daily samples 

JMS EY102007001SLC\NAUGHTON3_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 

• 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 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

• 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. 

All costs included in the BART analysis are in 2006 dollars (not escalated to 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 (fuel NOx). 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 

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

with low-NOx burners, 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 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

U.S. sub-bituminous 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 sub-bituminous coals are presumed to use PRB coal as the basis for the sub-bituminous 

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

There are a number of western coals that are classified as sub-bituminous, however, they 

border on being ranked as bituminous and do not display many of the qualities of PRB coals 

including most of the low NOx forming characteristics. Coals from P&M Kemmerer Mine 

(P&M) fall into this category. 

One distinguishing characteristic that classifies a sub-bituminous from a bituminous coal is 

whether it is agglomerating or non-agglomerating. Agglomerating, as applied to coal, has 

“the property of softening when it is heated to above about 400°C in a non-oxidizing 

atmosphere, and then appearing as a coherent mass after cooling to room temperature.” Since 

the agglomerating property of coals is the result of particles transforming into a plastic or 

semi-liquid state when heated, it reflects a change in surface area of the particle. Thus, with 

the application of heat, agglomerating coals would tend to develop a non-porous surface 

while the surface of non-agglomerating coals would become even more porous with 

combustion. As shown by Figure 3-1, the increased porosity provides more particle surface 

area resulting in more favorable combustion conditions. This non-agglomerating property 

assists in making sub-bituminous coals more amenable to controlling NOx by allowing less 

air to be introduced during the initial ignition portion of the combustion process. 

The coals from the P&M mine just barely fall into the category of non-agglomerating coals. 

While each of these coals is considered non-agglomerating—they either do not exhibit those 

properties of non-agglomerating coals, or exhibit them to only a minor degree. The 

conditions—during combustion of typical non-agglomerating coals that make it easier to 

control NOx emissions—do not exist for the coal used at Naughton 3. 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-3
BART ANALYSIS FOR NAUGHTON UNIT 3 

FIGURE 3-1 

Illustration of the Effect of Agglomeration on the Speed of Coal Combustion 

Naughton 3 

Table 3-1 shows key NOx forming characteristics of a typical PRB coal compared to low 

sulfur and high sulfur coals from the P&M mine, and coals from Twentymile, which is a 

representative western bituminous coal. 

TABLE 3-1 

Coal Source and Characteristics 

Naughton 3 

Parameter PRB P&M Low 

Sulfur 

P&M 

High 

Sulfur 

Twentymile 

Nitrogen (% dry) 1.10 1.33 1.22 1.85 

Oxygen (% dry) 16.2 15.35 14.5 7.19 

Coal rank Sub C Sub B Sub B Bitum. high volatility B 

As shown in Table 3-1, although P&M coal is classified as sub-bituminous, it exhibits higher 

nitrogen content and lower oxygen content than the PRB coal. The higher nitrogen content is 

an indication that more nitrogen is available to the combustion process and higher NOx

emissions are likely. Oxygen content can be correlated to the reactivity of the coal with more 

reactive coals—generally containing higher levels of oxygen. More reactive coals tend to 

produce lower NOx emissions, and they are also more conducive to reduction of NOx

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-4
BART ANALYSIS FOR NAUGHTON UNIT 3 

emissions, through use of combustion control measures such as low NOx burners and over 

fire air (OFA). These characteristics indicate that higher NOx formation is likely with coal 

from the P&M mine, rather than with PRB coal. The P&M coal contains quality 

characteristics that fall between a typical PRB coal and Twentymile, a clearly bituminous 

coal that produces higher NOx—as has been demonstrated at power plants burning this fuel. 

Figures 3-2 and 3-3 illustrate the relationship of nitrogen and oxygen content to related 

BART presumptive NOx limits for the coals listed in Table 3-1. Each chart identifies the 

presumptive BART limit associated with a typical bituminous and sub-bituminous coal, and 

demonstrates how the P&M mine coal falls between these two general coal classifications. 

Twentymile shows achievement of the BART presumptive NOx limit for a bituminous coal 

and the PRB coal corresponds to the sub-bituminous BART presumptive NOx limit. The 

“present” data point represents coal from P&M that has been used at Naughton 3, and 

indicates the average NOx emission rate of 0.40 lb per MMBtu achieved during 2005. The 

tune data point indicates the projected NOx emission rate of 0.35 lb per MMBtu that 

PacifiCorp believes is achievable with additional boiler tuning and optimization. 

Figures 3-2 and 3-3 both demonstrate that for Naughton 3 with new LNBs and OFA installed 

and burning P&M coal, the likely NOx emission rate will be above the bituminous BART 

presumptive NOx limit of 0.28 and considerably higher than the sub-bituminous BART 

presumptive NOx limit of 0.15 lb per MMBtu. 

FIGURE 3-2 

Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Naughton 3 

Typical Coal Nitrogen Content vs. NOx Limit

PRB Subbituminous

Present

Tune

Twentymile Bituminous 

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

Typical Nitrogen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-5
BART ANALYSIS FOR NAUGHTON UNIT 3 

FIGURE 3-3 

Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Naughton 3 

Typical Coal Oxygen Content vs. NOx Limit

PRB Subbituminous

Twentymile Bituminous

Present

Tune

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

Typical Oxygen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Subbituminous Presumptive Limit - 0.15lb/MMBtu

Bituminous Presumptive Limit - 0.28 lb/MMBtu

Coal quality characteristics also impact the design and operation of the boiler and associated 

auxiliary equipment. Minor changes in quality can sometimes be accommodated through 

operational adjustments or changes to equipment. It is important to note, however, that 

consistent variations in quality or assumptions of “average” quality for performance 

projections can be problematic. This is particularly troublesome when dealing with 

performance issues that are very sensitive to both coal quality and combustion conditions, 

such as NOx formation. There can be significant variability in the quality of coals at mines, 

such as the P&M mine that is burned at Naughton 3. 

Several of the coal quality characteristics and their effect on NOx formation have been 

previously discussed. There are some additional considerations that illustrate the complexity 

of achieving and maintaining low NOx emissions with pulverized coal on a consistent shorter 

term, such as a 30-day rolling average basis. 

Good combustion is based on the “three Ts”: time, temperature, and turbulence. These 

parameters, along with a “design” coal are taken into consideration when designing a boiler 

and associated firing equipment such as fans, burners, and pulverizers. If a performance 

requirement such as NOx emission limits is subsequently changed, conflicts with and 

between other performance issues can result. 

Naughton 3 is located at an altitude of 6,936 feet above sea level. At this elevation, 

atmospheric pressure is lower (11.3 pounds per square inch) as compared with sea level 

pressure of 14.7 pounds per square inch). This lower pressure means that less oxygen is 

available for combustion for each volume of air. In order to provide adequate oxygen to meet 

the requirements for efficient combustion, larger volumes of air are required. When adjusting 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR NAUGHTON UNIT 3 

air flows and distribution to reduce NOx emissions using low NOx burners with over-fire air, 

original boiler design restrictions again limit the modifications that can be made and still 

achieve satisfactory combustion performance. 

Another significant factor in controlling NOx emissions is the fineness of the coal entering 

the burners. Fineness is influenced by the grindability index (Hardgrove) of the coal. Finer 

coal particles promote release of volatiles and assist char burnout due to more surface area 

exposed to air. NOx reduction with high volatile coals is improved with greater fineness and 

with proper air staging. Coal fineness can deteriorate over time periods between pulverizer 

maintenance and service as pulverizer grinding surfaces wear. 

When all the factors are taken into account – of agglomeration versus non-agglomeration, 

nitrogen and oxygen content of the coals, and the grindability index – this analysis 

demonstrates that for the coal used at Naughton 3 (and considering the small size and 

configuration of the Naughton 3 boiler), the low NOx burner technology referred to in the 

EPA’s presumptive BART analysis will achieve a NOx emission rate of 0.35 lb per MMBtu. 

The BART analysis for NOx emissions from Naughton 1 is further 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 Naughton 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. NOx 

from Naughton 3 emissions are currently controlled through the use of LNBs and OFA 

The following potential NOx control technology options were considered: 

• Tune existing LNB with OFA 

• Mobotec rotating opposed fire air (ROFA) 

• Conventional selective non-catalytic reduction system (SNCR) 

• Selective catalytic reduction system (SCR) 

Step 2: Eliminate Technically Infeasible Options 

For Naughton 3, technical feasibility will primarily be determined by physical constraints, 

and the current boiler configuration and size. Naughton 3 had an average NOx emission rate 

of 0.40 lb per MMBtu during 2005. 

For this BART analysis, information pertaining to SNCR, and SCR were based on the MultiPollutant Control Report dated October 2002 (S&L Study). The cost estimates for SCR and 

SNCR were updated by Sargent & Lundy (S&L) in October 2006. PacifiCorp provided 

additional emissions data for boiler tuning. 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°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 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-7
BART ANALYSIS FOR NAUGHTON UNIT 3 

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 3-2 summarizes the control technology options evaluated in this BART analysis, along 

with projected NOx emission rates. All of the technologies except tuning the existing LNB 

with OFA can meet a limit of 0.28 lb per MMBTU. 

TABLE 3-2 

NOx Control Technology Emission Rates 

Naughton 3 

Technology Projected Emission Rate (lb per 

MMBtu) 

Tune Existing LNB with OFA 0.35 

ROFA 0.28 

LNB with OFA & SNCR 0.28 

LNB with OFA & 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, 

they 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. 

Tuning Existing LNB/OFA System. The mechanism used to lower NOx with low NOx burners 

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. 

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

from boiler vendors—indicates that the existing LNB and OFA system at Naughton 3 could 

be tuned to achieve an expected NOx emission rate of 0.35 lb per MMBtu. 

Rotating Opposed Fire Air. 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 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-8
BART ANALYSIS FOR NAUGHTON UNIT 3 

installation would have a booster fan(s) to supply the high velocity air to the ROFA boxes, 

and Mobotec would propose one 6,000 horsepower fan for Naughton 3. 

Mobotec expects to achieve a NOx emission rate of 0.26 lb per MMBtu using ROFA 

technology. An operating margin of 0.02 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 ROFA 

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 post1control modeling scenarios. 

Selective Non-catalytic Reduction. This process 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 

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 0.35 lb per MMBtu, would be tuned in conjunction with 

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

projected emission rate of 0.28 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 a catalyst is used to promote the 

reaction. Ammonia is injected into the flue-gas stream, where it reduces NOx to nitrogen and 

water. Unlike the high temperatures required for SNCR, the reaction takes place on the 

surface of a vanadium/titanium-based catalyst at a temperature range between 580°F to 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-9
BART ANALYSIS FOR NAUGHTON UNIT 3 

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 

Naughton 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 Naughton 3. 

S&L prepared the design conditions and cost estimates for SCR at Naughton 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 0.35 lb per MMBtu, 

would be tuned in conjunction with the SCR. The S&L design basis 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 Naughton 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. Variations may result for many reasons, including coal characteristics, unit 

load, boiler operation including excess air, boiler slagging, burner equipment condition, coal 

mill fineness, and so forth. 

The following steps were utilized for determining a level of confidence for the vendor 

expected value: 

• Establish expected NOx emissions value from vendor. 

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

• 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. 

• 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. Tuning of the existing LNB with OFA is not expected to significantly impact the 

boiler efficiency or forced draft fan power usage. Therefore, should not have energy impacts. 

The Mobotec ROFA system requires installation and operation of one 6,000-horsepower 

ROFA fan. 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-10
BART ANALYSIS FOR NAUGHTON UNIT 3 

SCR 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 Naughton 3 are estimated at approximately 

1,990 kilowatts, based on the S&L Study. 

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

increase in carbon monoxide emissions and unburned carbon in the ash, commonly referred 

to as loss on ignition would be the same or lower than prior levels. Installation of LNBs with 

OFA may also result in higher carbon monoxide emissions and loss on ignition, which will 

result in unburned carbon in the ash. 

SCR installation could impact the saleability and disposal of fly ash due to ammonia levels, 

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

improvements. Other environmental impacts involve the storage of ammonia (especially if 

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

Economic Impacts. Costs and schedules for the 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 3-3, and the first year control costs in Figure 3-4. 

The complete economic analysis is contained in Appendix A. 

TABLE 3-3 

NOx Control Cost Comparison 

Naughton 3 

Factor 

Tune LNB with 

OFA ROFA 

LNB with OFA 

& SNCR 

LNB with OFA 

& SCR 

Total Installed Capital Costs NA $14.7 million $15.8 million $92.0 million 

Total First Year Fixed & Variable 

O&M Costs 

NA $1.9 million $0.9 million $2.6 million 

Total First Year Annualized Cost NA $3.3 million $2.4 million $11.4 million 

Power Consumption (MW) NA 4.5 0.3 2.0 

Annual Power Usage (1000 megawatt 

hours per year) 

NA 35.3 2.6 15.7 

NOx Design Control Efficiency 22.2% 37.8% 37.8% 84.4% 

Tons NOx Removed per Year 1,459 2,479 2,479 5,542 

First Year Average Control Cost 

(dollars per ton [$/Ton] of NOx

Removed) 

0 1,326 984 2,049 

Incremental Control Cost 

($/Ton of NOx Removed) 0 1,326 2,390 2,635 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-11
BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-12

Preliminary BART Selection. CH2M HILL recommends tuning the low-NOx burners with 

OFA as BART for Naughton 3; this is based on its significant reduction in NOx emissions, 

reasonable control cost, as well as they do not create any additional power requirements or 

environmental impacts. Tuning the LNB with OFA is projected to achieve an emission rate 

of 0.35 lb per MMBtu. As discussed in the section on coal quality, the recommended 

technology and the achieved emission rate are deemed appropriate as BART for NOx

emissions when considering the coals combusted and the size and configuration of the boiler 

at Naughton 3.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BA

FIGURE 3-4 First Year Control Cost for NOx Air Pollution Control Options 

Naughton 3 

0

500

1,0001,5002,0002,5003,000

Tune Exist. LNB w/OFA ROFA SNCR 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 3 

3.2.2 BART SO2 Analysis 

Sulfur dioxide (SO2) forms in the boiler during the combustion process, and is primarily 

dependent on coal sulfur content. The BART analysis for SO2 emissions on Naughton 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 Naughton 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: 

• Upgrade wet waste sodium liquor FGD 

• Upgrade wet FGD and use soda ash reagent 

Step 2: Eliminate Technically Infeasible Options 

Naughton 3 currently has a controlled SO2 emission rate of 0.50 lb per MMBtu. The 

following summarizes the technical feasibility analysis performed. 

Upgrade Wet Waste Sodium Liquor FGD. Wet SO2 scrubbers operate by flowing the flue gas 

upward through a large reactor vessel that has an alkaline reagent 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 sodium in the reagent reacts with the 

SO2 in the flue gas to form sodium sulfite and sodium bisulfite, which are removed from the 

scrubber and disposed. 

The wet waste sodium liquor FGD system at Naughton 3 currently achieves approximately 

83 percent SO2 removal to achieve an SO2 outlet emission rate of 0.50 lb per MMBtu. To 

achieve 90 to 95 percent SO2 removal, the wet FGD system operation would be changed by 

improving inlet gas distribution, potentially adding a second tray to improve gas/liquid 

contact, and upgrading the reagent and waste solids systems. An upgraded wet sodium 

scrubbing FGD system using waste liquor is projected to achieve an outlet emission rate of 

0.21 lb per MMBtu (90 percent total SO2 removal or 58 percent incremental SO2 removal). 

An upgraded wet sodium scrubbing FGD system using soda ash reagent is projected to 

achieve an outlet emission rate of 0.10 lb per MMBtu (95 percent overall SO2 removal or 

80 percent incremental SO2 removal). 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Since other technologies, such as dry FGD with the existing ESP or lime spray drying FGD 

with a new fabric filter, are inferior technologies for removing SO2, they were not evaluated 

further. 

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. 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-14
BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-15

Energy Impacts. An upgraded wet sodium FGD system would require approximately 330 kW 

of additional power. 

Environmental Impacts. There are no anticipated environmental impacts from upgrading the 

existing wet sodium FGD system except for an incremental addition to scrubber waste 

disposal and makeup water requirement. The recycling of waste liquor into the scrubber 

would save on disposal of these materials and would conserve more resources. 

Economic Impacts. A summary of the costs and amount of SO2 removed for the upgraded wet 

sodium FGD system is provided in Table 3-4, and a comparison of the first-year control cost 

($/ton removed) is shown in Figure 3-5. The complete economic analysis is contained in 

Appendix A. 

TABLE 3-4 

SO2 Control Cost Comparison (Incremental to Existing FGD System) 

Naughton 3 

Factor 

Upgraded Wet Flue Gas Desulfurization 

(FGD) with Waste Liquor 

Upgraded Wet FGD 

with Soda Ash 

Total Installed Capital Costs $4.5 million $14.5 million 

Total First Year Fixed and Variable 

Operation and Maintenance Costs $0.5 million $1.6 million 

Total First Year Annualized Cost $0.9 million $3.0 million 

Incremental Power Consumption (MW) 0.3 0.3 

Incremental Annual Power Usage 

(1000 megawatt hours per year) 2.6 2.6 

Incremental SO2 Design Control 

Efficiency 58.0% 80.0% 

Incremental Tons SO2 Removed per 

Year 4,230 5,834 

First Year Average Control Cost ($/Ton 

of SO2 Removed) 223 519 

Incremental Control Cost 

($/Ton of SO2 Removed) 223 1,299 

Preliminary BART Selection. CH2M HILL recommends upgrading the wet FGD system with 

waste liquor as BART for Naughton 3. This is based on its significant reduction in SO2

emissions, reasonable control costs, and the advantages of minimal additional power 

requirements and environmental impacts.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BA

FIGURE 3-5 First Year Control Cost for SO2 Air Pollution Control Options 

Naughton 3 

0

200400600800

1,0001,2001,400

N/A Wet FGD w/Waste Liquor Wet FGD w

Air Pollution Control Option

Control Cost ($/Ton SO2 Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 3 

3.2.3 BART PM10 Analysis 

Naughton 3 is currently equipped with an ESP which removes particulate matter 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 particulate matter 

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 Naughton 3 controls PM emissions to 

0.094 lb per MMBtu. 

The BART analysis for PM emissions on Naughton 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: 

• Enhance existing ESP 

• Polishing fabric filter 

• Replacement fabric filter 

Step 2: Eliminate Technically Infeasible Options 

Enhance Existing ESP. Upgrading the ESP including flue gas conditioning (FGC) will 

improve performance. If the fly ash from coal has high resistivity, such as fly ash from 

sub-bituminous coal, the ash is not collected effectively in a small ESP. Adding FGC will 

allow the ESP to collect the ash more effectively. Adding FGC can account for large 

improvements in collection efficiency for small ESPs. 

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

Naughton 3 ESP. This technology is licensed by the Electric Power Research Institute, and 

referred to as a COHPAC (Compact Hybrid Particulate Collector). 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). 

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

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

the fact that the 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 Naughton 3 is achieving a controlled PM emission rate of 0.094 lb per 

MMBtu. Enhancing the existing ESP would reduce PM emissions to approximately 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-17
BART ANALYSIS FOR NAUGHTON UNIT 3 

0.040 lb per MMBtu. Adding a COHPAC fabric filter downstream of the existing ESP would 

reduce PM emissions to approximately 0.015 lb per MMBtu. A replacement fabric filter is 

also projected to reduce PM emissions to approximately 0.015 lb per MMBtu. 

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 induced draft fan upgrade and upgrade of the auxiliary power supply system. 

A COHPAC fabric filter at Naughton 3 would require approximately 2.1 MW of power, 

equating to an annual power usage of approximately 16.2 million kilowatt hours (kWh), 

based on a 90 percent annual plant capacity factor. 

There are no negative environmental impacts from upgrading the ESP and the addition of a 

flue gas conditioning system. 

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

COHPAC polishing fabric filter or upgrading the ESP and adding a flue gas conditioning 

system. The PM10 control technology emission rate ranking is summarized in Table 3-5. 

TABLE 3-5 

PM10 Control Technology Emission Rate Ranking 

Naughton 3 

Control Technology 

Projected PM10(a) Emission Rate 

(pound per million 

British thermal units) 

Upgrade Electrostatic Precipitator 

(ESP) and Flue Gas Conditioning 

0.040 

Polishing Fabric Filter 0.015 

Replacement Fabric Filter 0.015 

NOTES: 

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

Economic Impacts. A summary of the costs and PM removed for COHPAC and flue gas 

conditionings are recorded in Table 3-6, and the first-year control costs for flue gas 

conditioning and fabric filters are shown in Figure 3-6. The complete economic analysis is 

contained in Appendix A. 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-19

TABLE 3-6 

PM10 Control Cost Comparison 

Naughton 3 

Factor 

Flue Gas 

Conditioning Polishing Fabric Filter 

Total Installed Capital Costs $13.3 million $80.3 million 

Total First Year Fixed & Variable O&M Costs $0.0 million $1.1 million 

Total First Year Annualized Cost $1.3 million $8.8 million 

Power Consumption (MW) 0 2.1 

Annual Power Usage (1000 MW-Hr/Yr) 0 16.2 

PM Design Control Efficiency 57.4% 84.0% 

Tons PM Removed per Year 788 1,152 

First Year Average Control Cost 

($/Ton of PM Removed) 1,606 7,602 

Incremental Control Cost 

($/Ton of SO2 Removed) 1,606 20,553 

Preliminary BART Selection. CH2M HILL recommends upgrading the existing ESP and 

adding flue gas conditioning as BART for Naughton 3; this is based on the significant 

reduction in PM10 emissions, reasonable control costs, as well as the advantages of creating 

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

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis.
BA

FIGURE 3-6 First Year Control Cost for PM Air Pollution Control Options Naughton 3 

0

5,000

10,00015,00020,00025,000

Enhancements to Existing ESP Fabric Filter

Air Pollution Control Option

Control Cost ($/Ton PM Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 
4.0 BART Modeling Analysis 

4.1 Model Selection 

CH2M HILL used a Gaussian puff dispersion modeling system, CALPUFF, to assess the 

visibility impacts of emissions from Naughton 3 at Class I areas. The Class I areas potentially 

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

Naughton 3 Plant. These wilderness areas (WA) include: 

• Bridger WA 

• Fitzpatrick WA 

The CALPUFF modeling system includes the CALMET meteorological model CALPUFF 

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

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

modeling system was applied in a full, refined mode. 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 Naughton 3 facility and allow for a 50-km buffer around the 

Class I areas that were within 300 km of the facility. Grid resolution was 4 km. 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 BART Modeling Protocol which 

is included in this report as Appendix B. This protocol was prepared by the WDEQ-AQD. 

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\NAUGHTON3_OCT2007_FINAL.DOC 4-1
Bridger

Wilderness Area

FitzpatrickWilderness Area

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

0 

Na

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

Naughton

SLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\NAUGHTON_CLASSI.MXD 11/9/2006 MSLAYDEN
BART ANALYSIS FOR NAUGHTON 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 

Naughton 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-km resolution Mesoscale Meteorological Model, Version 5 

(MM5) meteorological data fields for each year that covered the entire modeling domain. 

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 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_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 for all stations from the National Weather Service’s 

Automated Surface Observing System network 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 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. 
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

IEN

PHP

D07

CUT

2WX

SNY

BFF

CDR

AIA

LVM

DLN

BTM

BZN BIL

BridgerWilderness Area

FitzpatrickWilderness Area

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

0 

Surface and Upper 

N

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

Naughton

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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 Naughton 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 Naughton 3. Post-control stack parameters reflect the anticipated changes 

associated with installation of the control technology alternatives that are being evaluated. 

4.3.3 Emission Rates 

Pre-control emission rates for Naughton 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 

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BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-7

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, unless it was determined that an alternative control level is justified, 

based on a careful consideration of the statutory factors evaluated in Sections 3, 4, and 5. 

• Scenario 1: Tune LNB with OFA, upgrade waste liquor FGD, and enhance existing ESP. 

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

recommendation. 

• Scenario 2: LNB with OFA and SCR, upgrade waste liquor FGD, and enhance existing 

ESP. 

• Scenario 3: LNB with OFA and SCR, upgrade waste liquor FGD, and new fabric filter. 

• Scenario 4: LNB with OFA and SCR, upgrade wet FGD and use soda ash reagent, and 

new fabric filter. 

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

Baseline Post-control Scenario 1 Post-contro

Model Input Data 

Current Operations with Wet 

FGD and Electrostatic 

Precipitator (ESP) 

Low-NOx Burners (LNBs) with Overfire Air (OFA), Wet Flue Gas 

Desulfurization (FGD) with Waste 

Liquor, Existing ESP 

LNB with OF

FGD with W

Enhanc

Sulfur Dioxide (SO2) Stack Emissions 

(pounds per hour [lb/hr]) 1,840 777 7

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,656 1,295 2

PM10 Stack Emissions (lb/hr) 348 148 1

Coarse Particulate (PM2.5 <diameter< PM10) Stack Emissions (lb/hr)(a) 149 63.6 6

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 198 84.4 8Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 34.0 34.0 5

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 33.4 33.4 5

Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr) 4

(NH4)2SO4 as SO4 Stack Emissions (lb/hr) 3

(NH4)HSO4 Stack Emissions (lb/hr) 7

(NH4)HSO4 as SO4 Stack Emissions (lb/hr) 6

Total Sulfate (SO4) (lb/hr) 33.2 33.3 6

Stack Conditions

Stack Height (meters) 145 145 1Stack Exit Diameter (meters) 8.08 8.08 8

Stack Exit Temperature (Kelvin) 323 322 3

Stack Exit Velocity (meters per second) 23.8 20.2 2

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. (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 NAUGHTON UNIT 3 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology options for Naughton 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 deciview (dV) units. Calculations of light extinction were made for each 

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

(ΔdV) change relative to natural background. The following default extinction coefficients 

for each pollutant, were used: 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

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

humidity factors 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 relative humidity factors for the Class I areas. These 

values were used for the particular Class I area being modeled. 

The natural background conditions as a reference for determining the ΔdV change 

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

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

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

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-9
BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-10

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 

Naughton 3 

Aerosol Component 

Average Natural Concentration 

(micrograms per cubic meter) 

for Fitzpatrick and Bridger Class I Wilderness Areas 

Ammonium Sulfate 0.045 

Ammonium Nitrate 0.038 

Organic Carbon 0.178 

Elemental Carbon 0.008 

Soil 0.189 

Coarse Mass 1.136 

NOTE: 

Source: 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 Naughton 3. 

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario 

CH2M HILL modeled Naughton 3 for the baseline and its post-control Scenario #1. In 

addition, three other scenarios were modeled. The post-control scenario included emission 

rates for SO2, NOx, and PM10 that would be achieved if BART state-of-the-art technology 

were installed on Naughton 3. Some scenarios included controls that would not be able to 

meet presumptive BART limits where it was determined, based on the statutory factors, that 

the selection of an alternative control device may be warranted. 

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

Bridger WA and Fitzpatrick WA. 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 Naughton 3

Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost 

Class I 

Wilderness Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

Number (No.) of Days 

Above 0.5 dV 

C

 2001 

Bridger 5.657 1.978 66 

Baseline: Current Operation with wet flue gas desulfurization (FGD), Electrostatic Precipitator (ESP) Fitzpatrick 3.214 1.126 24 

$2,207,011 Bridger 4.498 1.413 12 

Scenario 1: Low-NOx Burners (LNBs) with Over-fire Air 

(OFA), wet waste liquor FGD, enhanced ESP $2,207,011 Fitzpatrick 2.110 0.735 16 

$13,563,715 Bridger 2.346 0.716 19 $

Scenario 2: LNB with OFA, wet waste liquor FGD, enhanced ESP $13,563,715 Fitzpatrick 1.096 0.371 4 $

$21,057,857 Bridger 2.276 0.697 16 $

Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR), wet waste liquor FGD, fabric filter $21,057,857 Fitzpatrick 1.076 0.363 4 $

$23,141,792 Bridger 1.914 0.553 12 $

Scenario 4: LNB with OFA and SCR, wet soda ash FGD, fabric filter $23,141,792 Fitzpatrick 0.770 0.265 2 $2002 

Bridger 4.783 1.618 55 

Baseline: Current Operation with wet FGD, ESP 

Fitzpatrick 3.862 0.893 21 

$2,207,011 Bridger 3.401 1.175 32 

Scenario 1: LNB with OFA, wet waste liquor FGD, enhanced ESP $2,207,011 Fitzpatrick 2.864 0.564 11 

$13,563,715 Bridger 1.683 0.650 10 $

Scenario 2: LNB with OFA, wet waste liquor FGD, enhanced ESP $13,563,715 Fitzpatrick 1.478 0.290 3 $

$21,057,857 Bridger 1.631 0.635 10 $

Scenario 3: LNB with OFA and SCR, wet waste liquor FGD, fabric filter $21,057,857 Fitzpatrick 1.440 0.279 3 $

$23,141,792 Bridger 1.341 0.494 7 $

Scenario 4: LNB with OFA and SCR, wet soda ash FGD, fabric filter $23,141,792 Fitzpatrick 1.144 0.203 3 $

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 
JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 

TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Naughton 3

 Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost 

Class I 

Wilderness Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

Number (No.) of Days 

Above 0.5 dV 

C

2003 

Bridger 4.056 2.171 53 

Baseline: Current Operation with wet FGD, ESP 

Fitzpatrick 1.710 0.871 21 

$2,207,011 Bridger 3.016 1.555 39 

Scenario 1: LNB with OFA, wet waste liquor FGD, enhanced ESP $2,207,011 Fitzpatrick 1.233 0.549 9 

$13,563,715 Bridger 1.444 0.828 14 $

Scenario 2: LNB with OFA, wet waste liquor FGD, enhanced ESP $13,563,715 Fitzpatrick 0.604 0.260 1 $

$21,057,857 Bridger 1.393 0.810 14 $

Scenario 3: LNB with OFA and SCR, wet waste liquor FGD, fabric filter $21,057,857 Fitzpatrick 0.585 0.253 1 $

$23,141,792 Bridger 1.198 0.662 11 $

Scenario 4: LNB with OFA and SCR, wet soda ash FGD, fabric filter $23,141,792 Fitzpatrick 0.480 0.214 0 $3-Year Averages 

Bridger 1.922 58.0 

Baseline: Current Operation with wet FGD, ESP 

Fitzpatrick 0.963 22.0 

$2,207,011 Bridger 1.381 27.7 

Scenario 1: LNB with OFA, wet waste liquor FGD, enhanced ESP $2,207,011 Fitzpatrick 0.616 12.0 

$13,563,715 Bridger 0.731 14.3 $

Scenario 2: LNB with OFA, wet waste liquor FGD, enhanced ESP $13,563,715 Fitzpatrick 0.307 2.7 $

$21,057,857 Bridger 0.714 13.3 $

Scenario 3: LNB with OFA and SCR, wet waste liquor FGD, fabric filter $21,057,857 Fitzpatrick 0.298 2.7 $

$23,141,792 Bridger 0.570 10.0 $

Scenario 4: LNB with OFA and SCR, wet soda ash FGD, fabric filter $23,141,792 Fitzpatrick 0.227 1.7 $

NOTES: Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $2,207,011 / (2.569 - 1.782) = $2,804,334 Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001: = $2,207,011 / (72 - 48) = $91,959 
5.0 Preliminary Assessment and 

Recommendations 

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

modeling analysis completed for Naughton 3, the preliminary recommended BART controls 

for NOx, SO2, and PM are as follows:

• Tune LNBs and OFA system for NOx control

• Upgrade wet waste sodium liquor scrubber for SO2 control

• Enhance 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 and 5-2. A comparison of the incremental costs between 

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

days above 0.5 dV, and the total annualized cost versus 98th percentile ΔdV reduction, are 

shown in Figures 5-1 through 5-4 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 Naughton 3. 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-1
BART ANALYSIS FOR NAUGHTON UNIT 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. The EPA states that: “in calculating incremental costs, the 

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

options.” In 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 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 

Bridger WA Class I Agent Control Data 

Naughton 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), Waste 

Liquor Flue Gas 

Desulfurization (FGD), 

Enhanced ESP 

0.54 30.3 $2.2 $4.1 $0.1 

2 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), 

Waste Liquor FGD, 

Enhanced ESP 

1.19 43.7 $13.6 $11.4 $0.3 

3 LNB with OFA and 

SCR, Waste Liquor 

FGD, New Fabric Filter 

1.21 44.7 $21.1 $17.4 $0.5 

4 LNB with OFA & SCR, 

Wet Soda Ash FGD, 

New Fabric filter 

1.35 48.0 $23.1 $17.1 $0.5 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-2
BART ANALYSIS FOR NAUGHTON UNIT 3 

TABLE 5-2 

Fitzpatrick WA Class I Area Control Data 

Naughton 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), 

Waste Liquor Flue Gas 

Desulfurization (FGD), 

Enhanced ESP 

0.35 10.0 $2.2 $6.4 $0.2 

2 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), Waste 

Liquor FGD, Enhanced 

ESP 

0.66 19.3 $13.6 $20.7 $0.7 

3 LNB with OFA and SCR, 

Dry FGD, Fabric Filter 

0.67 19.3 $21.1 $31.7 $1.1 

4 LNB with OFA & SCR, Wet 

FGD, New stack 

0.74 20.3 $23.1 $31.4 $1.1 

TABLE 5-3 

Bridger WA Class I Agent Incremental Data 

Naughton 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 30.3 0.54 $0.07 $4.08 

Scenario 1 and Scenario 2 13.3 0.65 $0.9 $17.5 

Scenario 1 and Scenario 3 14.3 0.67 $1.3 $28.3 

Scenario 1 and Scenario 4 17.7 0.81 $1.2 $25.8 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-3
BART ANALYSIS FOR NAUGHTON UNIT 3 

TABLE 5-4 

Fitzpatrick WA Class I Area Incremental Data 

Naughton 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 10.0 0.35 $0.22 $6.35 

Scenario 1 and Scenario 2 9.3 0.31 $1.2 $36.8 

Scenario 1 and Scenario 3 9.3 0.32 $2.0 $59.3 

Scenario 1 and Scenario 4 10.3 0.39 $2.0 $53.9 

FIGURE 5-1 

Least-cost Envelope Bridger WA Class I Area Reduction 

Naughton 3 

Scenario 4

Baseline Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0 10 20 30 40 50 6

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

0

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-4
BART ANALYSIS FOR NAUGHTON UNIT 3 

FIGURE 5-2 

Least-cost Envelope Bridger WA Class I Area 98th Percentile 

Naughton 3 

Scenario 4

Baseline Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

FIGURE 5-3 

Least-cost Envelope Fitzpatrick WA Class I Area Reduction 

Naughton 3 

Scenario 3

Scenario 2

Baseline Scenario 1

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0 5 10 15 20 25

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-5
BART ANALYSIS FOR NAUGHTON UNIT 3 

FIGURE 5-4 

Least-cost Envelope Fitzpatrick WA Class I Area 98th Percentile 

Naughton 3 

Scenario 4

Baseline Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80

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. The other scenarios were eliminated for the following reasons: 

• Scenario 2 is to the left of the curve formed by the dominant control alternative scenarios, 

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

• Scenario 3 has very high incremental costs on the basis of both a cost per day of 

improvement and a cost per dV reduction. 

• While Scenario 4 provides some potential visibility advantage over Scenario 1, the 

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

Analysis of the results for the Bridger Class I Wilderness Area in Tables 5-1 and 5-3 and 

Figures 5-1 and 5-2 illustrate the conclusions stated in this section. 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 $70,000 per day and $4.08 million per dV to 

improve visibility at the Bridger WA. However, the incremental cost-effectiveness for 

Scenario 2 compared to Scenario 1 is excessive at $900,000 per day and 

$17.5 million per dV. The incremental cost-effectiveness for Scenario 3 compared to 

Scenario 1 is equally excessive at $1.3,000 million per day and $28.3 million per dV. Finally 

Scenario 4 compared with Scenario 1 has an incremental cost-effectiveness of $1.2 million 

per day and $25.8 million per dV. Using Table 5-4, a similar conclusion is reached for 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-6
BART ANALYSIS FOR NAUGHTON UNIT 3 

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-7

improving visibility at the Fitzpatrick Wilderness Area. In fact, the incremental costs are 

higher for improving visibility in the Fitzpatrick WA than in the Bridger WA. Therefore, 

EPA’s least-cost analysis confirms that Scenario 1 represents the proper BART control 

technology for Naughton 3, because, if Scenario 2, 3, or 4 were chosen (compared to 

Scenario 1), the incremental cost-effectiveness is excessive. 

5.2 Recommendations 

5.2.1 NOx Emission Control 

CH2M HILL recommends tuning the low-NOx burners with over-fire air as BART for 

Naughton 3; this is based on the projected significant reduction in NOx emissions, reasonable 

control costs, as well as the advantages of no additional power requirements or non-air 

quality environmental impacts. With this approach, the NOx emission rate is projected to be 

0.35 lb per MMBtu. 

5.2.2 SO2 Emission Control 

CH2M HILL recommends upgrading the wet waste liquor sodium scrubber system as BART 

for Naughton 3, based on the significant reduction in SO2 emissions, reasonable control 

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

quality environmental impacts. This approach is projected to meet an SO2 emission rate of 

0.21 lb per MMBtu. 

5.2.3 PM10 Emission Control 

CH2M HILL recommends the enhancement of the existing ESP as BART for Naughton 3; 

this is based on the significant reduction in PM10 emissions, reasonable control costs, as well 

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

impacts. 

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

Haze” by Dr. Ronald Henry (Henry, 2002), state that only dV differences of approximately 

1.5 to 2.0 dV or more are perceivable 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, 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 

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 Naughton 3 facility, 

it would increase the costs per dV 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\NAUGHTON3_OCT2007_FINAL.DOC 6-1
APPENDIX A 

Economic Analysis 
PacifiCorp BART Analysis Scenarios

9

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

Scenario First Year Cost Scenario

 First Year 

Cost Scenario First Year Cost Scena

 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 First Year Cost Scenario First Year Scenario First Year Cost Scena

 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 wFGD, 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 wFGD, 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 wSCR, Wet FGD, Fa

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 wSCR, Wet FGD, ES

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 wFGD, New Fabric F

Scenario 1 - LNB with OFA, Dry FGD, ESP and Higher Sulfur Coal

Scenario 1 - LNB wFGD, ESP

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

Scenario 3 - LNB wSCR, Dry FGD, New 

Naughton Unit 3

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

Scenario 4 - LNB wSCR, Wet FGD, ES

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
ECONOMIC ANALYSIS SUMMARY

Naughton Unit 3 Boiler Design: Tangential-Fired PC

Tune Exist. 

LNB w/OFA ROFA SNCR SCR Wet FG

w/Waste Li

Case 1 2 3 4 5 7 

NOx Emission Control System LNCFS II LNB

Tune Exist. LNB 

w/OFA ROFA SNCR SCR LNCFS II L

SO2 Emission Control System Wet FGD Wet FGD Wet FGD Wet FGD Wet FGD

Wet FGD w/W

Liquor

PM Emission Control System ESP ESP ESP ESP ESP ESP 

TOTAL INSTALLED CAPITAL COST ($) 0 0 14,747,608 15,788,530 92,007,264 4,499,83FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 0 Maintenance Material ($) 0 0 48,000 75,000 156,000 21,900 Maintenance Labor ($) 0 0 72,000 112,500 234,000 14,600 Administrative Labor ($) 0 0 0 0 0 0 TOTAL FIXED O&M COST 0 0 120,000 187,500 390,000 36,500 Makeup Water Cost 0 0 0 0 0 37,985 Reagent Cost 0 0 0 620,285 927,219 0 SCR Catalyst / FF Bag Cost 0 0 0 0 501,000 0 Waste Disposal Cost 0 0 0 0 0 309,228 Electric Power Cost 0 0 1,763,730 130,086 786,035 130,086 TOTAL VARIABLE O&M COST 0 0 1,763,730 750,371 2,214,254 477,298 

TOTAL FIRST YEAR O&M COST 0 0 1,883,730 937,871 2,604,254 513,798 

FIRST YEAR DEBT SERVICE ($) 0 0 1,402,908 1,501,929 8,752,451 428,059 TOTAL FIRST YEAR COST ($) 0 0 3,286,638 2,439,799 11,356,705 941,857 

Power Consumption (MW) 0.0 0.0 4.5 0.3 2.0 0.3 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 35.3 2.6 15.7 2.6 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 22.2% 37.8% 37.8% 84.4% 0.0% 

NOx Removed (Tons/Yr) 0 1,459 2,479 2,479 5,542 0 First Year Average Control Cost ($/Ton NOx Rem.) 0 0 1,326 984 2,049 0 

Incremental Control Cost ($/Ton NOx Removed) 0 0 1,326 2,390 2,635 0 

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

SO2 Removal Rate (%) 82.8% 0.0% 0.0% 0.0% 0.0% 58.0% 

SO2 Removed (Tons/Yr) 0 0 0 0 0 4,230 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 223 Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 223 

7-1 

PM Removal Rate (%) 97.87% 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 0 37,762,741 27,247,297 123,825,654 10,777,34

NOx Control 

Parameter Current Operation

SO

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
INPUT CALCULATIONS

Naughton Unit 3 Boiler Design: Tangential-Fired PC

Tune Exist. 

LNB w/OFA ROFA SNCR SCR Wet FGD w/Waste Liquor 

w

Case 1 2 3 4 5 7 

NOx Emission Control System LNCFS II LNB

Tune Exist. LNB 

w/OFA ROFA SNCR SCR LNCFS II LNB 

SO2 Emission Control System Wet FGD Wet FGD Wet FGD Wet FGD Wet FGD Wet FGD w/Waste Liquor Wet 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) 330,000 330,000 330,000 330,000 330,000 330,000 

Net Plant Heat Rate (Btu/kW-Hr) 11,212 11,212 11,212 11,212 11,212 11,212 Boiler Fuel Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Ke

Coal Heating Value (Btu/Lb) 9,950 9,875 9,875 9,875 9,875 9,875 

Coal Sulfur Content (wt.%) 1.45% 1.02% 1.02% 1.02% 1.02% 1.02% 

Coal Ash Content (wt.%) 5.50% 5.25% 5.25% 5.25% 5.25% 5.25% Boiler Heat Input, each (MMBtu/Hr) 3,700 3,700 3,700 3,700 3,700 3,700 Coal Flow Rate (Lb/Hr) 371,855 374,679 374,679 374,679 374,679 374,679  (Ton/Yr) 1,465,853 1,476,987 1,476,987 1,476,987 1,476,987 1,476,987  (MMBtu/Yr) 29,170,485 29,170,485 29,170,485 29,170,485 29,170,485 29,170,485 EmissionsUncontrolled SO2 (Lb/Hr) 10,773 7,636 7,636 7,636 7,636 1,850  (Lb/MMBtu) 2.91 2.06 2.06 2.06 2.06 0.50 

 (Lb Moles/Hr) 168.16 119.19 119.19 119.19 119.19 28.88  (Tons/Yr) 42,467 30,100 30,100 30,100 30,100 7,293 SO2 Removal Rate (%) 82.8% 0.0% 0.0% 0.0% 0.0% 58.0% 

 (Lb/Hr) 8,923 0 0 0 0 1,073  (Ton/Yr) 35,175 0 0 0 0 4,230 SO2 Emission Rate (Lb/Hr) 1,850 7,636 7,636 7,636 7,636 777  (Lb/MMBtu) 0.50 2.06 2.06 2.06 2.06 0.21 

 (Ton/Yr) 7,293 30,100 30,100 30,100 30,100 3,063 Uncontrolled NOx (Lb/Hr) 1,665 1,665 1,665 1,665 1,665 1,665  (Lb/MMBtu) 0.45 0.45 0.45 0.45 0.45 0.45 

 (Lb Moles/Hr) 55.48 55.48 55.48 55.48 55.48 55.48  (Tons/Yr) 6,563 6,563 6,563 6,563 6,563 6,563 NOx Removal Rate (%) 0.0% 22.2% 37.8% 37.8% 84.4% 0.0% 

 (Lb/Hr) 0 370 629 629 1,406 0  (Lb Moles/Hr) 0.00 12.33 20.96 20.96 46.85 0.00  (Ton/Yr) 0 1,459 2,479 2,479 5,542 0 NOx Emission Rate (Lb/Hr) 1,665 1,295 1,036 1,036 259 1,665  (Lb/MMBtu) 0.45 0.35 0.28 0.28 0.07 0.45 

 (Ton/Yr) 6,563 5,105 4,084 4,084 1,021 6,563 Uncontrolled Fly Ash (Lb/Hr) 16,362 348 348 348 348 348  (Lb/MMBtu) 4.422 0.094 0.094 0.094 0.094 0.094  (Lb Moles/Hr) 545.2 11.6 11.6 11.6 11.6 11.6  (Tons/Yr) 64,498 1,371 1,371 1,371 1,371 1,371 Fly Ash Removal Rate (%) 97.87% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 16,014 0 0 0 0 0  (Ton/Yr) 63,127 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 348 348 348 348 348 348  (Lb/MMBtu) 0.094 0.094 0.094 0.094 0.094 0.094 

 (Ton/Yr) 1,371 1,371 1,371 1,371 1,371 1,371 

Parameter 

Current Operation NOx Control 

SO2 Contr

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Tune Exist. 

LNB w/OFA ROFA SNCR SCR Wet FGD w/Waste Liquor 

w

Case 1 2 3 4 5 7 

Parameter 

Current Operation NOx Control 

SO2 Contr

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 0 14,747,608 15,788,530 92,007,264 0

SO2 Emission Control System ($2006) 0 0 0 0 0 4,499,834 

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

Total Emission Control Systems ($2006) 0 0 14,747,608 15,788,530 92,007,264 4,499,834 

NOx Emission Control System ($/kW) 0 0 45 48 279 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 14 PM Emission Control System ($/kW) 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 0 45 48 279 14 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 00000 0 Maintenance Material ($) 0 0 48,000 75,000 156,000 21,900 Maintenance Labor ($) 0 0 72,000 112,500 234,000 14,600 Administrative Labor ($) 00000 0 

Total Fixed O&M Cost ($) 0 0 120,000 187,500 390,000 36,500 

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 66 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 37,985 

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 Waste Liquor 

Unit Cost ($/Ton) 0.00 0.00 0.00 370 400 0.00  ($/Lb) 0.000 0.000 0.000 0.185 0.200 0.000 Molar Stoichiometry 0.00 0.00 0.00 0.45 1.00 1.02 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 90% 

Reagent Usage (Lb/Hr) 0 0 0 425 588 1,835 First Year Reagent Cost ($) 0 0 0 620,285 927,219 0 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 167 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 0 501,000 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 3,224 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 0 309,228 

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% 1.36% 0.10% 0.60% 0.10%  (MW) 0.00 0.00 4.47 0.33 1.99 0.33 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 1,763,730 130,086 786,035 130,086 

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

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Input Tables

Table 1 - Cases

Existing

1 2 3 4 5 6 7 8 

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

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD 

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 & 

Higher S Coal 

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 & 

Higher S Coal 

Dry FGD w/Fabric 

Filter Wet FGD 

9 Naughton Unit 3 Current Operation

Tune Exist. LNB 

w/OFA ROFA SNCR SCR N/A 

Wet FGD w/Waste 

Liquor Wet FGD w/

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

LNB w/OFA & 

SCR Upgraded Dry FGD 

Dry FGD w/Fabric 

Filter 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 160,000 11,563 Kemmerer Mine 8 Naughton Unit 2 None None ESP Tangential-Fired PC 210,000 11,428 Kemmerer Mine 9 Naughton Unit 3 LNCFS II LNB Wet FGD ESP Tangential-Fired PC 330,000 11,212 Kemmerer Mine 

10 Wyodak LNB Dry FGD ESP Opposed Wall-Fired PC 365,000 12,877 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_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Table 3 - Emissions

Controlled 

SO2 Controlled NOx

Controlled 

PM Case 2 Case 3 Case 4 Case 5 Case 

1 Dave Johnston Unit 3 2.91 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 2.91 0.58 0.056 0.24 0.26 0.19 0.07 

 

8 Naughton Unit 2 2.91 0.54 0.064 0.24 0.26 0.19 0.07 

 

9 Naughton Unit 3 0.50 0.45 0.094 0.35 0.28 0.28 0.07 

10 Wyodak 0.50 0.31 0.030 0.23 0.18 0.20 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 $ - - $ - $ $ - 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 $ 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_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Table 6 - Case 3 O&M Costs (Mobotec ROFA)

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

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. 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 $ 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 $ 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 $ 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_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Table 9 - Case 6 O&M Costs (Dry FGD)

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

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual 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 $ 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 $ 21,900 - $ 14,600 $ $ - 66 Waste Liquor 1.02 

 

10 Wyodak $ 30,660 - $ 20,440 $ - 30 Lime 1.10 

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 $ 328,496 303,677 $ 218,998 $ $ - 82 Lime 1.02 

Variable Operating RequirementsVariable Operating RequirementsVariable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)

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

Makeup Water 

Use (Gpm) Reagent

Reagent 

Usage (Lb/Hr)

Annual 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 $ - - $ - $ $ - - None - 

 

10 Wyodak $ - - $ - $ - - None - 

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 $ 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 $ 39,617,991 $ 57,979,051 $ 56,500,308 $ 

8 Naughton Unit 2 $ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 54,775,108 $ 76,278,497 $ 77,695,625 $ 

9 Naughton Unit 3 $ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $ 2,772,643 $ 8,934,073 $ 8,

10 Wyodak $ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 16,487,985 $ 41,146,026 $ 58,619,840 $ 

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_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
CAPITAL COST

Naughton 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 $0 Vendor $4,351,377 Vendor $0 Vendor $0 Vendor $0 Vendor 

Construction 85.3% $0 85.3% $3,713,194 85.3% $0 85.3% $0 85.3% $0 85.3% 

Balance of Plant 51.7% $0 51.7% $2,249,320 51.7% $0 51.7% $0 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $1,305,413 0.0% $0 0.0% $0 0.0% $0 0.0% 

Owner's Costs 13.2% $0 13.2% $576,485 13.2% $0 13.2% $0 13.2% $0 13.2% 

Surcharge 16.4% $0 16.4% $714,735 16.4% $0 16.4% $0 16.4% $0 16.4% AFUDC 12.2% $0 12.2% $531,671 12.2% $0 12.2% $0 12.2% $0 12.2% Subtotal $0 $13,442,195 $0 $0 $0 

Contingency 12.8% $0 30.0% $1,305,413 12.8% $0 12.8% $0 12.8% $0 12.8% 

Total Capital Cost for LNB w/OFA or ROFA $0 $14,747,608 $0 $0 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $11,203,578 S&L Report $67,373,000 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $2,240,716 10.0% $6,737,300 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $626,616 5.6% $3,768,172 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $5,690,997 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% $123,463 1.1% $742,450 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% $314,484 0.0% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $1,279,673 11.4% $7,695,344 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $15,788,530 $92,007,264 $0 

Dry or Wet FGD, FGC or Fabric Filter Dry FGD 

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

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

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

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

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

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

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

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

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

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

SNCR N/A Wet FGD w

SO2 

Tune Exist. LNB w/OFA

Wet FGD

ESP ESP

ROFA

Wet FGD

LNC

Wet FGD 

Parameter

Tune Exist. LNB w/OFA ROFA SCR

LNCFS II LNB

N/A

ESP

SNCR

Wet FGD

ESP ESP

SCR

Wet FGD

NOx Control

2 3 45 

6 

EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Naughton Unit 3 Tune Exist. LNB w/OF

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 2015 - - - - - - - 

 

3 2016 - - - - - - - 

 

4 2017 - - - - - - - 

 

5 2018 - - - - - - - 

 

6 2019 - - - - - - - 

 

7 2020 - - - - - - - 

 

8 2021 - - - - - - - 

 

9 2022 - - - - - - - 

 

10 2023 - - - - - - - 

 

11 2024 - - - - - - - 

 

12 2025 - - - - - - - 

 

13 2026 - - - - - - - 

 

14 2027 - - - - - - - 

 

15 2028 - - - - - - - 

 

16 2029 - - - - - - - 

 

17 2030 - - - - - - - 

 

18 2031 - - - - - - - 

 

19 2032 - - - - - - - 

 

20 2033 - - - - - - - 

 

Present Worth - - - - - - - 

 

Naughton 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 120,000 - - - - 1,763,730 1,763,730 

 

2 2015 122,400 - - - - 1,799,004 1,799,004 

 

3 2016 124,848 - - - - 1,834,984 1,834,984 

 

4 2017 127,345 - - - - 1,871,684 1,871,684 

 

5 2018 129,892 - - - - 1,909,118 1,909,118 

 

6 2019 132,490 - - - - 1,947,300 1,947,300 

 

7 2020 135,139 - - - - 1,986,246 1,986,246 

 

8 2021 137,842 - - - - 2,025,971 2,025,971 

 

9 2022 140,599 - - - - 2,066,490 2,066,490 

 

10 2023 143,411 - - - - 2,107,820 2,107,820 

 

11 2024 146,279 - - - - 2,149,977 2,149,977 

 

12 2025 149,205 - - - - 2,192,976 2,192,976 

 

13 2026 152,189 - - - - 2,236,836 2,236,836 

 

14 2027 155,233 - - - - 2,281,572 2,281,572 

 

15 2028 158,337 - - - - 2,327,204 2,327,204 

 

16 2029 161,504 - - - - 2,373,748 2,373,748 

 

17 2030 164,734 - - - - 2,421,223 2,421,223 

 

18 2031 168,029 - - - - 2,469,647 2,469,647 

 

19 2032 171,390 - - - - 2,519,040 2,519,040 

 

20 2033 174,817 - - - - 2,569,421 2,569,421 

 

Present Worth - 1,466,142 - - - 21,548,990 21,548,990 1

 

(% of PW) 3.9% 0.0% 0.0% 0.0% 0.0% 57.1% 57.1% 

1 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Naughton Unit 3 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 187,500 - 620,285 - - 130,086 750,371 

 

2 2015 191,250 - 632,690 - - 132,688 765,378 

 

3 2016 195,075 - 645,344 - - 135,341 780,686 

 

4 2017 198,977 - 658,251 - - 138,048 796,299 

 

5 2018 202,956 - 671,416 - - 140,809 812,225 

 

6 2019 207,015 - 684,844 - - 143,625 828,470 

 

7 2020 211,155 - 698,541 - - 146,498 845,039 

 

8 2021 215,379 - 712,512 - - 149,428 861,940 

 

9 2022 219,686 - 726,762 - - 152,416 879,179 

 

10 2023 224,080 - 741,298 - - 155,465 896,762 

 

11 2024 228,561 - 756,124 - - 158,574 914,698 

 

12 2025 233,133 - 771,246 - - 161,746 932,992 

 

13 2026 237,795 - 786,671 - - 164,981 951,651 

 

14 2027 242,551 - 802,404 - - 168,280 970,684 

 

15 2028 247,402 - 818,452 - - 171,646 990,098 

 

16 2029 252,350 - 834,821 - - 175,079 1,009,900 

 

17 2030 257,397 - 851,518 - - 178,580 1,030,098 

 

18 2031 262,545 - 868,548 - - 182,152 1,050,700 

 

19 2032 267,796 - 885,919 - - 185,795 1,071,714 

 

20 2033 273,152 - 903,638 - - 189,511 1,093,148 

 

Present Worth - 2,290,847 7,578,547 - - 1,589,372 9,167,919 1

 

(% of PW) 8.4% 0.0% 27.8% 0.0% 0.0% 5.8% 33.6% 

Naughton Unit 3 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 390,000 - 927,219 501,000 - 786,035 2,214,254 

 

2 2015 397,800 - 945,763 511,020 - 801,755 2,258,539 

 

3 2016 405,756 - 964,679 521,240 - 817,791 2,303,710 

 

4 2017 413,871 - 983,972 531,665 - 834,146 2,349,784 

 

5 2018 422,149 - 1,003,652 542,299 - 850,829 2,396,780 

 

6 2019 430,592 - 1,023,725 553,144 - 867,846 2,444,715 

 

7 2020 439,203 - 1,044,199 564,207 - 885,203 2,493,609 

 

8 2021 447,987 - 1,065,083 575,492 - 902,907 2,543,482 

 

9 2022 456,947 - 1,086,385 587,001 - 920,965 2,594,351 

 

10 2023 466,086 - 1,108,113 598,741 - 939,384 2,646,238 

 

11 2024 475,408 - 1,130,275 610,716 - 958,172 2,699,163 

 

12 2025 484,916 - 1,152,880 622,931 - 977,335 2,753,146 

 

13 2026 494,614 - 1,175,938 635,389 - 996,882 2,808,209 

 

14 2027 504,507 - 1,199,457 648,097 - 1,016,820 2,864,373 

 

15 2028 514,597 - 1,223,446 661,059 - 1,037,156 2,921,661 

 

16 2029 524,889 - 1,247,915 674,280 - 1,057,899 2,980,094 

 

17 2030 535,386 - 1,272,873 687,766 - 1,079,057 3,039,696 

 

18 2031 546,094 - 1,298,330 701,521 - 1,100,638 3,100,490 

 

19 2032 557,016 - 1,324,297 715,551 - 1,122,651 3,162,500 

 

20 2033 568,156 - 1,350,783 729,862 - 1,145,104 3,225,750 

 

Present Worth - 4,764,963 11,328,626 6,121,144 - 9,603,658 27,053,428 9

 

(% of PW) 3.8% 0.0% 9.1% 4.9% 0.0% 7.8% 21.8% 

2 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Naughton Unit 3 Wet FGD w/Waste Liqu

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 36,500 37,985 - - 309,228 130,086 477,298 

 

2 2015 37,230 38,744 - - 315,412 132,688 486,844 

 

3 2016 37,974 39,519 - - 321,721 135,341 496,581 

 

4 2017 38,734 40,310 - - 328,155 138,048 506,513 

 

5 2018 39,508 41,116 - - 334,718 140,809 516,643 

 

6 2019 40,298 41,938 - - 341,412 143,625 526,976 

 

7 2020 41,104 42,777 - - 348,241 146,498 537,516 

 

8 2021 41,927 43,632 - - 355,206 149,428 548,266 

 

9 2022 42,765 44,505 - - 362,310 152,416 559,231 

 

10 2023 43,620 45,395 - - 369,556 155,465 570,416 

 

11 2024 44,493 46,303 - - 376,947 158,574 581,824 

 

12 2025 45,383 47,229 - - 384,486 161,746 593,461 

 

13 2026 46,290 48,174 - - 392,176 164,981 605,330 

 

14 2027 47,216 49,137 - - 400,019 168,280 617,436 

 

15 2028 48,160 50,120 - - 408,019 171,646 629,785 

 

16 2029 49,124 51,122 - - 416,180 175,079 642,381 

 

17 2030 50,106 52,145 - - 424,503 178,580 655,229 

 

18 2031 51,108 53,188 - - 432,994 182,152 668,333 

 

19 2032 52,130 54,251 - - 441,653 185,795 681,700 

 

20 2033 53,173 55,337 - - 450,486 189,511 695,334 

 

Present Worth 464,091 445,947 - - 3,778,100 1,589,372 5,831,563 

 

(% of PW) 4.1% 4.3% 0.0% 0.0% 35.1% 14.7% 54.1% 

Naughton Unit 3 Wet FGD w/Soda Ash

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 36,500 37,985 787,613 - 654,306 130,086 1,609,990 

 

2 2015 37,230 38,744 803,365 - 667,393 132,688 1,642,190 

 

3 2016 37,974 39,519 819,433 - 680,740 135,341 1,675,034 

 

4 2017 38,734 40,310 835,821 - 694,355 138,048 1,708,535 

 

5 2018 39,508 41,116 852,538 - 708,242 140,809 1,742,705 

 

6 2019 40,298 41,938 869,589 - 722,407 143,625 1,777,559 

 

7 2020 41,104 42,777 886,980 - 736,855 146,498 1,813,111 

 

8 2021 41,927 43,632 904,720 - 751,592 149,428 1,849,373 

 

9 2022 42,765 44,505 922,814 - 766,624 152,416 1,886,360 

 

10 2023 43,620 45,395 941,271 - 781,957 155,465 1,924,087 

 

11 2024 44,493 46,303 960,096 - 797,596 158,574 1,962,569 

 

12 2025 45,383 47,229 979,298 - 813,548 161,746 2,001,821 

 

13 2026 46,290 48,174 998,884 - 829,819 164,981 2,041,857 

 

14 2027 47,216 49,137 1,018,862 - 846,415 168,280 2,082,694 

 

15 2028 48,160 50,120 1,039,239 - 863,343 171,646 2,124,348 

 

16 2029 49,124 51,122 1,060,024 - 880,610 175,079 2,166,835 

 

17 2030 50,106 52,145 1,081,224 - 898,222 178,580 2,210,172 

 

18 2031 51,108 53,188 1,102,849 - 916,187 182,152 2,254,375 

 

19 2032 52,130 54,251 1,124,906 - 934,511 185,795 2,299,463 

 

20 2033 53,173 55,337 1,147,404 - 953,201 189,511 2,345,452 

 

Present Worth 464,091 445,947 9,622,943 - 7,994,219 1,589,372 19,670,625 1

 

(% of PW) 1.3% 1.3% 27.8% 0.0% 23.1% 4.6% 56.8% 

3 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
Naughton Unit 3 Enhancements to Exis

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 2015 - - - - - - - 

 

3 2016 - - - - - - - 

 

4 2017 - - - - - - - 

 

5 2018 - - - - - - - 

 

6 2019 - - - - - - - 

 

7 2020 - - - - - - - 

 

8 2021 - - - - - - - 

 

9 2022 - - - - - - - 

 

10 2023 - - - - - - - 

 

11 2024 - - - - - - - 

 

12 2025 - - - - - - - 

 

13 2026 - - - - - - - 

 

14 2027 - - - - - - - 

 

15 2028 - - - - - - - 

 

16 2029 - - - - - - - 

 

17 2030 - - - - - - - 

 

18 2031 - - - - - - - 

 

19 2032 - - - - - - - 

 

20 2033 - - - - - - - 

 

Present Worth - - - - - - - 1

 

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

Naughton 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 121,665 - - 187,096 - 812,052 999,148 

 

2 2015 124,099 - - 190,838 - 828,293 1,019,131 

 

3 2016 126,581 - - 194,655 - 844,859 1,039,514 

 

4 2017 129,112 - - 198,548 - 861,756 1,060,304 

 

5 2018 131,694 - - 202,519 - 878,991 1,081,510 

 

6 2019 134,328 - - 206,569 - 896,571 1,103,140 

 

7 2020 137,015 - - 210,700 - 914,502 1,125,203 

 

8 2021 139,755 - - 214,914 - 932,792 1,147,707 

 

9 2022 142,550 - - 219,213 - 951,448 1,170,661 

 

10 2023 145,401 - - 223,597 - 970,477 1,194,074 

 

11 2024 148,309 - - 228,069 - 989,887 1,217,956 

 

12 2025 151,275 - - 232,630 - 1,009,685 1,242,315 

 

13 2026 154,301 - - 237,283 - 1,029,878 1,267,161 

 

14 2027 157,387 - - 242,029 - 1,050,476 1,292,504 

 

15 2028 160,535 - - 246,869 - 1,071,485 1,318,355 

 

16 2029 163,745 - - 251,807 - 1,092,915 1,344,722 

 

17 2030 167,020 - - 256,843 - 1,114,773 1,371,616 

 

18 2031 170,361 - - 261,980 - 1,137,069 1,399,048 

 

19 2032 173,768 - - 267,219 - 1,159,810 1,427,029 

 

20 2033 177,243 - - 272,564 - 1,183,006 1,455,570 

 

Present Worth - 1,486,489 - 2,285,911 - 9,921,532 12,207,444 8

 

(% of PW) 1.6% 0.0% 0.0% 2.4% 0.0% 10.6% 13.0% 

4 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 
EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 

First Year Cost for Air Pollution Control Options

0

2,000,0004,000,0006,000,0008,000,000

10,000,00012,000,000

Tune Exist.

LNB w/OFA

ROFA SNCR SCR Wet FGD

w/Waste Liquor

Wet FGD

w/Soda Ash

Enhanc

to Exist

Air Pollution Control Option

First Year Cost ($)
EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 

Present Worth Cost for Air Pollution Control Options

0

20,000,00040,000,00060,000,00080,000,000

100,000,000120,000,000140,000,000

Tune Exist.

LNB w/OFA

ROFA SNCR SCR Wet FGD

w/Waste Liquor

Wet FGD

w/Soda Ash

Enhan

to Exis

Air Pollution Control Options

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

2006 Wyoming BART Protocol