Final Report 

BART Analysis for 

Naughton Unit 2 

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 2 

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 2 (hereafter referred to as Naughton 2). 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 do not directly apply to Naughton 2, based on the United 

States Environmental Protection Agency’s (EPA) guidelines. Presumptive BART limits are a 

goal unless an alternative control level is justified based on careful consideration of the 

statutory factors. BART emission limits must be achieved within 5 years after the State 

Implementation Plan (SIP) is approved by the EPA, and a compliance date of 2014 was 

assumed for this analysis. 

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

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

alternatives were investigated, listed below by pollutant: 

• NOx emission controls: 

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

− Rotating opposed fire air 

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

− LNBs with selective catalytic reduction (SCR) system 

• SO2 emission controls: 

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

(ESP) 

− Dry FGD system with new fabric filter 

− Wet FGD system with existing ESP 

• PM10 emission controls: 

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

− Polishing fabric filter 

− Replacement fabric filter 

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BART ANALYSIS FOR NAUGHTON UNIT 2 

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 Effectiveness of Remaining Control Technologies 

• Step 4 – Evaluate Impacts and Document Results 

− The costs of compliance with 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; costs have not been escalated to the assumed 2014 

BART implementation date. 

Coal Characteristics 

The main source of coal burned at Naughton 2 will be the low-sulfur and high-sulfur 

P&M Kemmerer Mines (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), 

which represent the bulk of sub-bituminous coal use in the United States. This BART 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-2
BART ANALYSIS FOR NAUGHTON UNIT 2 

analysis has compared the higher nitrogen content and the different combustion 

characteristics of PRB coals to those coals used at Naughton 2, and has evaluated the effect 

of these qualities on NOx formation and achievable emission rates. 

Recommendations 

CH2M HILL recommends installing LNBs with OFA, a dry FGD system, and operating the 

existing ESP with an SO3 FGC system. This combination of control devices is identified as 

Scenario 1 throughout this report. 

NOx Emission Control 

Naughton 2 burns coal from P&M. As documented in this analysis, the characteristics of 

P&M coals are aligned more closely with bituminous coals. 

CH2M HILL recommends LNB with OFA as BART for Naughton 2, based on the projected 

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

additional power requirements or non-air quality environmental impacts. Reductions of NOx

are expected to be similar to those realized at the Jim Bridger plant where LNBs with OFA 

have been installed on Unit 2. Selection of new LNB with OFA at Naughton 1 is projected to 

attain an emission rate at or below 0.26 pound per million British thermal units (MMBtu). 

SO2 Emission Control 

CH2M HILL recommends a dry lime FGD system with the existing ESP as BART for 

Naughton 2, assuming use of coal containing no more than 1.02 percent sulfur by weight, 

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

advantages of minimal additional power requirements and minimal non-air quality 

environmental impacts. This technology is projected to attain an SO2 limit of 0.41 pound per 

MMBtu. 

PM10 Emission Control 

CH2M HILL recommends the addition of FGC system to enhance the performance of the 

existing electrostatic precipitator (ESP) as BART for Naughton 2, based on the reduction in 

PM10 emissions, reasonable control costs, and the advantages of minimal additional power 

requirements and no non-air quality environmental impacts. 

BART Modeling Analysis 

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

emissions from Naughton 2 at Class I areas. The Class I areas potentially affected are located 

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

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

• Bridger WA 

• Fitzpatrick WA 

Because Naughton 2 simultaneously will control NOx, SO2, and PM10 emissions, four 

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-3
BART ANALYSIS FOR NAUGHTON UNIT 2 

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

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

• Scenario 1: New LNB with OFA modifications, a dry FGD system, and an FGC system 

for enhanced ESP performance. As indicated previously, this scenario represents the 

preliminary BART recommendation of CH2M HILL. 

• Scenario 2: New LNB with OFA modifications, a dry FGD system, and installation of a 

new fabric filter. 

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

installation of a new fabric filter. 

• Scenario 4: New LNB with OFA modifications and SCR, installation of a new wet FGD 

system, installation of FGC for enhanced ESP performance, and construction of a new 

stack. 

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

were compared using 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, dry 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. 

 

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

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BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-5

• Scenario 3 (LNB with OFA and SCR, dry FGD, and new fabric filter) has very high 

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

reduction. 

• While Scenario 4 (LNB with OFA and SCR, wet FGD and new stack, and ESP with SO3

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

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

Therefore, Scenario 1 represents BART for Naughton 2. 

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 would occur, although PacifiCorp would 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 ................................................................ 3-19 

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.................................................................................... 5-6 

5.2.1 NOx Emission Control ................................................................. 5-6 

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 

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CONTENTS (CONTINUED) 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC iv

Tables 

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 Coal Characteristics Comparison

3-2 NOx Control Technology Projected Emission Rates

3-3 NOx Control Cost Comparison

3-4 SO2 Control Technology Emission Rates

3-5 SO2 Control Cost Comparison (Incremental to Existing FGD System)

3-6 PM10 Control Technology Emission Rates

3-7 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 Days Reduction

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

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

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

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol
Acronyms and Abbreviations 

°C Degrees Celsius 

°F Degrees Fahrenheit 

ƒ(RH) Relative Humidity Factor 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CALDESK Program to display data and results 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing program for calculating visibility impacts 

CALPUFF Gaussian puff dispersion model 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

ESP Electrostatic Precipitator 

EPA United States Environmental Protection Agency 

FGC Flue Gas Conditioning 

FGD Flue Gas Desulfurization 

kW Kilowatt 

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 

N2 Molecular Nitrogen 

NO Nitric Oxide 

NO2 Nitrogen Dioxide 

NOx Nitrogen Oxide 

(NH4)HSO4 Ammonium Bisulfate 

(NH4)2SO4 Ammonium Sulfate 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC v
ACRONYMS AND ABBREVIATIONS (CONTINUED) 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC vi

NP National Park 

OFA Over-fire Air 

P&M P&M Kemmerer Mine 

PM Particulate Matter 

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 (NPs) and other Class I protected air quality 

areas in the United States. These guidelines provide direction for states when determining 

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

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

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

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

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

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

report for Naughton Unit 2 (hereafter referred to as Naughton 2) by February 9, 2007. The 

BART Report that was submitted to WDEQ in February 2007 included a BART analysis, as 

well as 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 submitted formally to the EPA by early 2008. EPA 

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

5 years after EPA approval of the SIP. 

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

• Cost of the controls 

• Energy and non-air quality environmental impacts of compliance 

• Any existing pollution control technology in use at the source 

• Remaining useful life of the source 

• Degree of improvement in visibility that reasonably could be anticipated from the use of 

such technology 

This report documents the BART analysis that CH2M HILL performed on Naughton 2 by for 

PacifiCorp. The analysis was performed for nitrogen oxides (NOx), SO2 (sulfur dioxide), and 

particulate matter less than 10 micrometers in aerodynamic diameter (PM10) because these 

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. 

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2.0 Present Unit Operation 

Naughton 2 is a nominal 210-megawatt (MW) unit located approximately 6 miles southwest 

of Kemmerer, Wyoming. The unit is equipped with a tangentially fired boiler manufactured 

by the former Combustion Engineering (now Alstom). The unit was constructed with a 

United Conveyor mechanical dust collector for particulate matter (PM) control, and a Lodge 

Cottrell electrostatic precipitator (ESP) was added in 1976. The unit presently uses low sulfur 

coal to control SOx emissions below 1.2 pounds per million British thermal units (MMBtu) 

and good combustion practices for NOx control. A Honeywell distributed control system was 

installed in 1998. 

Naughton 2 began operation in 1968. 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 2 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 2 to operate until 2034. Table 2-1 lists additional unit 

information and study assumptions for this analysis. 

The main source of coal burned at Naughton 2 is the P&M Kemmerer Mine (P&M). This 

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

of the parameters influencing NOx formation. P&M coal has higher nitrogen content than 

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

use in the United States. 

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

characteristics of PRB coals, compared to those coals used Naughton 2 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 from P&M, and data on coal from this source were used 

in the modeling analysis. 

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BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 2-2

TABLE 2-1 

Present Unit Operation 

Naughton 2 

General Plant Data 

Site Elevation (feet above mean sea level) 6936 

Stack Height (feet) 224 

Stack Exit Internal Diameter (feet) / Exit Area (square feet) 16 / 201.1 

Stack Exit Temperature (degrees Fahrenheit [°F]) 280 

Stack Exit Velocity (feet per second [feet per second]) 78 

Stack Flow (actual cubic feet per minute) 940,970 

Latitude deg: (minutes:seconds) 41:45:27.36 

Longitude deg: (minutes:seconds) 110:35:53.05 

Annual Unit Capacity Factor (percentage [%]) 90 

Net Unit Output (megawatts) 210 

Net Unit Heat Rate (British thermal unit [Btu] per kilowatthour)(100% load) 

10,550 (as measured by fuel 

throughput) 

Boiler Heat Input (million Btu [MMBtu] per hour)(100% load) 

2,400 (as measured by continuous 

emissions monitoring) 

Type of Boiler Tangentially fired 

Boiler Fuel Coal 

Coal Sources P&M Kemmerer Mine 

Coal Heating Value (Btu per pound)(a) 9,800 

Coal Sulfur Content (% by weight)(a) 0.58 

Coal Ash Content (% by weight)(a) 5.00 

Coal Moisture Content (% by weight)(a) 21.00 

Coal Nitrogen Content (% by weight)(a) 1.3 

Current Nitrogen Oxide (NOx) Controls Good Combustion Practices 

Pre-project NOx Emission Rate (pounds per MMBtu)(b) 0.54 

Current Sulfur Dioxide (SO2) Controls None 

Pre-project SO2 Emission Rate (pounds per MMBtu) 1.20 

Current PM10(c) Controls Electrostatic Precipitator 

Pre-project Particulate Matter Emission Rate (pounds per MMBtu)(d) 0.064 

NOTES: 

(a)Coal characteristics vary between coal sources (b)Emission rates stated on annual average basis (c)PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter (d)Emission rate stated from test results 
BA

TABLE 2-2 Coal Sources and Characteristics Naughton 2 

Ultimate Analysis (% 

Mines 

Moisture 

(%) 

Ash 

(%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

unit per 

pound 

Sulfur 

(%) Hydrogen Carbon Sulfur N

Low-Sulfur P&M Mine 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\BART_NAUGHTON2__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 EPA for Class I areas. The state has estimated that 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 

− 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 Effectiveness of Remaining Control Technologies 

• Step 4 – Evaluate Impacts and Document Results 

− Costs of compliance with the control options 

− Remaining useful life of the facility 

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BART ANALYSIS FOR NAUGHTON UNIT 2 

− Energy and non-air quality environmental impacts of compliance 

• Step 5 – Evaluate Visibility Impacts 

− Degree of visibility improvement that reasonably could be anticipated from the use of 

BART 

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

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

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

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

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

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

included in the BART analysis are in 2006 dollars (not escalated to the 2014 BART 

implementation date). 

3.2.1 BART NOx Analysis 

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

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

characteristics. 

Formation of NOx

During coal combustion, NOx is formed in three different ways. The dominant source of NOx

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

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

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

oxides (NO and nitrogen dioxide) and partially reduced to molecular nitrogen (N2). A smaller 

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

combustion air (thermal NOx). A small amount of NOx is called prompt NOx, which 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 and provide 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 coal according to its degree of metamorphism in the 

natural series, from lignite to sub-bituminous to bituminous and on to anthracite. Lower rank 

coal, such as the sub-bituminous coal from the PRB, produces lower NOx emissions than 

higher rank bituminous coal, due to its 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 (LNBs), sub-bituminous coal creates a longer time for the kinetics to 

promote more stable N2, and hence results in lower NOx emissions. 

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

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

Information Administration, PRB coals currently represent 88 percent of the total production 

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BART ANALYSIS FOR NAUGHTON UNIT 2 

of sub-bituminous coal in the United States and 73 percent of all the western coal production 

(Energy Information Administration, 2006). Most references to western coal and 

sub-bituminous coal imply 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. 

A number of western coals are classified as sub-bituminous; however, these coals 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 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 degrees Celsius (°C) in a 

non-oxidizing atmosphere, and then appearing as a coherent mass after cooling to room 

temperature.” Because 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 in 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 properties of non-agglomerating 

coals or exhibit the properties 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 2. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-3
BART ANALYSIS FOR NAUGHTON UNIT 2 

FIGURE 3-1 

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

Naughton 2 

Table 3-1 shows key NOx-forming characteristics of a typical PRB coal compared to lowsulfur and high-sulfur P&M coals, and to coals from Twentymile, which is a representative 

western bituminous coal. 

TABLE 3-1 

Coal Characteristics Comparison 

Naughton 2 

Parameter 

Powder 

River 

Basin 

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, the coal exhibits 

higher nitrogen content and lower oxygen content than 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; more 

reactive coals generally contain higher levels of oxygen. More reactive coals tend to produce 

lower NOx emissions. More reactive coals are also more conducive to reduction of NOx

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-4
BART ANALYSIS FOR NAUGHTON UNIT 2 

emissions, through use of combustion-control measures such as LNBs and over-fire air 

(OFA). 

These characteristics indicate that higher NOx formation is more likely with P&M coal than 

with PRB coal. The P&M coal contains quality characteristics that fall between a typical 

PRB coal and Twentymile coal. Twentymile coal is 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 BARTpresumptive 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 coal falls between these two general coal classifications. 

Twentymile shows the 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 2 and 

indicates the average NOx emission rate of 0.57 pound per MMBtu achieved during 2005. 

The LNB with OFA data point indicates the projected NOx emission rate of 0.24 after 

installation of new LNBs and OFA. 

Figures 3-2 and 3-3 both demonstrate that for the Naughton 2 with the TFS2000 low NOx

emission system installed and burning P&M coal, the likely NOx emission rate will be closer 

to the bituminous end (0.28) of the BART-presumptive NOx limit range than to the 

sub-bituminous BART presumptive NOx limit of 0.15 pound per MMBtu. Neither limit 

applies to Naughton 2. 

All these factors are consistent with the observed sustainable emission rate of 0.24 pound per 

MMBtu for the control device that has been installed at another PacifiCorp Plant, Jim 

Bridger Unit 2. 

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

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

operational adjustments or changes to equipment. However, consistent variations in quality 

or assumptions of “average” quality for performance projections can be problematic, which 

is particularly troublesome when dealing with performance issues that are sensitive to coal 

quality and combustion conditions (for example, formation of NOx). Significant variability 

can occur in the quality of coal from mines, such as P&M coal, that is burned at Naughton 2. 

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

previously discussed. Some additional considerations illustrate the complexity of achieving 

and maintaining low NOx emissions with pulverized coal on a consistent shorter term basis, 

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, including fans, burners, and pulverizers. If a performance 

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

between other performance issues can result. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-5
BART ANALYSIS FOR NAUGHTON UNIT 2 

FIGURE 3-2 

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

Naughton 2 

PRB Subbituminous

Present

LNB w/OFA

Twentymile Bituminous 

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0.55

0.6

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

FIGURE 3-3 

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

Naughton 2 

PRB Subbituminous

Twentymile Bituminous

Present

LNB w/OFA

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0.55

0.6

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR NAUGHTON UNIT 2 

Naughton 2 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) than pressure at sea level 

(14.7 pounds per square inch). This lower pressure means that less oxygen is available for 

combustion for each volume of air. To provide adequate oxygen to meet the requirements for 

efficient combustion, larger volumes of air are required. When adjusting air flows and 

distribution to reduce NOx emissions using LNBs with OFA, 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 the release of volatile particles and assist char burnout due to more 

surface area that is exposed to air. Reduction of NOx 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 because of the wear to pulverizer 

grinding surfaces. 

When all of the factors are taken into account (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 2, the LNB technology (referred to in the 

presumptive BART analysis by EPA) will achieve NOx reductions similar to the rates 

identified for tangentially fired boilers that burn bituminous coals. The current NOx emission 

rate at Naughton 2 is 0.54 pound per MMBtu. 

The BART analysis for NOx emissions from Naughton 2 is further described in the following 

section. 

Step 1: Identify All Available Retrofit Control Technologies 

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

potential for application to Naughton 2, 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 

emissions from Naughton 2 currently are controlled through the use of good combustion 

practices and OFA. 

The following potential NOx control technology options were considered: 

• New/modified LNBs with advanced OFA 

• Mobotec rotating opposed-fire air (ROFA) 

• Conventional selective non-catalytic reduction (SNCR) system 

• Selective catalytic reduction (SCR) system 

Step 2: Eliminate Technically Infeasible Options 

For Naughton 2, technical feasibility primarily will be determined by physical constraints, and 

boiler configuration. Naughton 2 has an uncontrolled NOx emission rate of 

0.54 pound per MMBtu. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-7
BART ANALYSIS FOR NAUGHTON UNIT 2 

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

on the Sargent & Lundy (S&L) Multi-Pollutant Control Report (Sargent and Lundy, 2002). 

Hereafter, we refer to that document as the S&L Study. Sargent and Lundy (S&L) updated 

the cost estimates for SCR and SNCR in October 2006. PacifiCorp provided additional 

emissions data and costs developed by boiler vendors for LNBs and OFA. Also, 

CH2M HILL solicited a proposal from Mobotec for its ROFA technology. 

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

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

where the temperature reduces NOx to nitrogen and water. NOx reductions of up to 40 to 

60 percent have been achieved, although 15 to 30 percent is more realistic for most 

applications. SNCR typically is applied on smaller units. Adequate reagent distribution in the 

furnaces of large units can be problematic. 

Table 3-2 provides a summary of the control technology options evaluated in this BART 

analysis, along with projected NOx emission rates. 

TABLE 3-2 

NOx Control Technology Projected Emission Rates 

Naughton 2 

Technology 

Projected Emission Rate 

(Pound per million British 

thermal units) 

Low-NOx Burner (LNB) with Over-fire Air (OFA) 0.24 

Rotating Opposed Fire Air (ROFA) 0.26 

LNB with OFA and Selective Non-catalytic Reduction 0.19 

LNB with OFA and Selective Catalytic Reduction 0.07 

Step 3: Evaluate Effectiveness of Remaining Control Technologies 

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

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

the vendor proposals include inherent uncertainties. These proposals usually are prepared in a 

limited time frame, could be based on incomplete information, could contain overoptimistic 

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

preliminary proposals must be qualified, contractual guarantees can be established only after 

more detailed analysis has been completed. The following subsections describe the control 

technologies and the control effectiveness evaluated in this BART analysis. 

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

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-8
BART ANALYSIS FOR NAUGHTON UNIT 2 

Low-NOx burners and OFA are considered to be a capital cost, combustion technology 

retrofit. PacifiCorp provided CH2M HILL information that was based on the S&L Study and 

data from boiler vendors indicating that a new retrofit of LNBs and OFA at Naughton 2 

would result in an expected NOx emission rate of 0.24 pound per MMBtu. PacifiCorp has 

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

a vendor prediction. Vendors believe that this emission rate can be sustained as an average 

between overhauls, which would rate represent a significant reduction from the NOx

emission rate of 0.54 pound per MMBtu. 

Rotating Opposed-Fire Air. Mobotec markets ROFA as an improved second generation OFA 

system, stating: “...the flue gas volume of the furnace is set in rotation by asymmetrically 

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

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

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

combustion air is also mixed more effectively.” 

A typical ROFA installation would have a booster fan(s) to supply the high-velocity air to the 

ROFA boxes. Mobotec would propose one 3,500-horsepower fan for Naughton 2. 

Mobotec expects to achieve a NOx emission rate of 0.24 pound per MMBtu using ROFA 

technology. An operating margin of 0.02 pound per MMBtu was added to the expected rate 

due to the limited ROFA experience that Mobotec has with western sub-bituminous coals. 

Under the Mobotec proposal, which was 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 would 

determine the quantity and location of new ROFA ports. The Mobotec proposal included 

bent-tube assemblies for OFA port installation. 

Mobotec does not provide installation services because it believes that the Owner can more 

cost-effectively contract for these services. However, Mobotec does provide one onsite 

construction supervisor during installation and startup. 

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

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

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

Selective Non-catalytic Reduction. SNCR generally is used to achieve modest reductions of 

NOx 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 the temperature 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 might render fly ash unsaleable, might react with sulfur to foul 

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-9
BART ANALYSIS FOR NAUGHTON UNIT 2 

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 assumed that combustion modifications, including LNBs and advanced OFA, providing 

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

SNCR. At Naughton 2, a further reduction of 20 percent in NOx emission rates results in a 

projected emission rate of 0.19 pound per MMBtu for SNCR. 

Because of the expected marginal improvement in emission rate, 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. 

Selective Catalytic Reduction System. SCR works on the same principle as SNCR, but it uses 

a catalyst to promote the reaction. Ammonia is injected into the flue-gas stream, where it 

reduces NOx to nitrogen and water. Unlike the high temperatures required for SNCR, the 

reaction takes place on the surface of a vanadium/titanium-based catalyst at a temperature 

range between 580°F to 750°F. Due to the catalyst, the SCR process is more efficient than 

SNCR. The most common type of SCR is the high-dust configuration, where the catalyst is 

located upstream of the air heater and downstream from the economizer. The high-dust 

configuration was assumed for Naughton 2. In a full-scale SCR, the flue ducts are routed to a 

separate large reactor containing the catalyst. With an in-duct SCR, the catalyst would be 

located in the existing gas duct, which could 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 2. 

S&L prepared the design conditions and cost estimates for SCR at Naughton 2. As with 

SNCR, reducing NOx emission levels as much as possible through combustion modifications 

is generally more cost effective due to minimizing the catalyst surface area and ammonia 

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

modifications, including LNBs and OFA that would provide a NOx emission rate of 

0.24 pound per MMBtu, would be installed in conjunction with the SCR. The S&L design 

basis results in a projected NOx emission rate of 0.07 pound per MMBtu. Additional catalyst 

surface was included in the SCR design to accommodate the characteristics of the coal used 

at Naughton 2. 

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

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

of typical NOx emissions from coal-fired generating units was completed. During this review, 

NOx emissions were noted to vary significantly around an average emissions level. 

Variations could result for many reasons including coal characteristics, unit load, and boiler 

operation. Impacts from boiler operation would include such conditions as excess air, boiler 

slagging, condition of burner equipment, and coal mill fineness. 

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

value: 

• Establish expected NOx emissions value from vendor. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-10
BART ANALYSIS FOR NAUGHTON UNIT 2 

• Evaluate vendor’s experience and historical basis for achieving expected values. 

• Review and evaluate physical and operational characteristics and restrictions of the unit. 

The fewer variations existing in operations, coal supply, etc., the more predictable and 

less variant the NOx emissions are. 

• For the expected value of each technology, a corresponding potential exists for actual 

NOx emissions to vary from the 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 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 this evaluation. 

Energy Impacts. Installation of LNBs with OFA is not expected to significantly affect the 

boiler efficiency or power usage of the forced draft fan. Therefore, LNBs with OFA will not 

have energy impacts. 

The Mobotec ROFA system requires installation and operation of one 3,500-horsepower 

ROFA fan. 

SCR retrofit affects 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 2 are estimated at approximately 

1,340 kilowatts (kW) based on the S&L Study. 

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

increase in carbon monoxide (CO) emissions. Unburned carbon in the ash, commonly 

referred to as loss on ignition, would be the same or lower than previous levels. Installation 

of LNBs with OFA also could result in higher CO emissions and loss on ignition, which 

could result in higher unburned carbon in the ash. 

Installation of an SCR system could affect the saleability and disposal of fly ash due to 

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

improvements to visibility. 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. PacifiCorp furnished CH2M HILL the costs and schedules for the LNBs 

and OFA, SNCR, and SCR, all of which were developed using the S&L 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 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. The first year control costs are shown in 

Figure 3-4. The complete economic analysis is contained in Appendix A. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-11
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-12

TABLE 3-3 

NOx Control Cost Comparison 

Naughton 2 

Factor 

Low-NOx

Burner 

(LNB) with 

Over-fire Air 

(OFA) 

Rotating 

Opposed 

Fire Air 

(ROFA) 

LNB with 

OFA and 

Selective 

Non-catalytic 

Reduction 

LNB with 

OFA and 

Selective 

Catalytic 

Reduction 

Total Installed Capital Costs $7.5 million $10.6 million $19.9 million $73.0 million 

Total First Year Fixed and Variable 

Operations and Maintenance (O&M) 

Costs 

$0.1 million $1.1 million $0.9 million $1.6 million 

Total First Year Annualized Cost $0.8 million $2.2 million $2.8 million $8.5 million 

Power Consumption (megawatts) -- 2.6 0.2 1.3 

Annual Power Usage (1,000 megawatt 

hours per year) -- 20.6 1.7 10.6 

Nitrogen Oxide (NOx) Design Control 

Efficiency 55.6% 51.9% 64.8% 87.0% 

Tons NOx Removed per Year 2,838 2,649 3,311 4,446 

First Year Average Control Cost ($ per ton 

of NOx Removed) 280 814 833 1,920 

Incremental Control Cost ($ per ton of 

NOx Removed) 280 814 4,152 3,550 

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

BART for Naughton 2. This recommendation is based on the significant reduction in NOx

emissions, reasonable control cost, as well as the fact that LNBs with OFA do not create 

additional power requirements or environmental impacts. As previously discussed, the 

recommended technology and the achieved emission rate are deemed appropriate as BART 

for NOx emissions from the coals combusted at Naughton 2.

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 2 

0

500

1,0001,5002,0002,5003,0003,5004,0004,500

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

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 2 

3.2.2 BART SO2 Analysis 

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

on sulfur content in the coal. The BART analysis for SO2 emissions at Naughton 2 is 

described in this section. 

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 2. This included control 

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

The following potential SO2 control technology options were considered: 

• Dry flue gas desulfurization (FGD) with existing ESP 

• Dry FGD with new fabric filter 

• Wet lime/limestone FGD with existing ESP and new stack 

Step 2: Eliminate Technically Infeasible Options 

Naughton 2 currently has an uncontrolled SO2 emission rate of approximately 1.20 pound per 

MMBtu. 

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

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

wheel causes the lime slurry to separate into very fine droplets that intermix with the flue 

gas. The SO2 in the flue gas reacts with the calcium in the lime slurry to form calcium sulfate 

in the form of particulate matter. At Naughton 2, this dry particulate matter would be 

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

typically produces a dry waste product suitable for landfill disposal. 

Dry FGD with the existing ESP is projected to achieve 85 percent SO2 removal using the 

lower-sulfur coal. The resulting controlled SO2 emission rate from Naughton 2 would be 

equal to 0.18 pound per MMBtu, based on an average coal sulfur content of 0.58 percent by 

weight. 

Similarly, with coal having a higher sulfur content of 1.02 percent, the controlled SO2

emission rate would be 0.41 pound per MMBtu. Hence, this option cannot meet a limit of 

0.15 pound of SO2 per MMBtu. 

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

filter located downstream of the lime spray dryer, then an 87.5 percent SO2 removal is 

projected when using the lower-sulfur coal, allowing the facility to meet a limit of 

0.15 pound of SO2 per MMBtu. 

However, if higher-sulfur coal (with 1.02 percent sulfur) is used, the controlled SO2 emission 

rate is projected to be 0.21 pound of SO2 per MMBtu. 

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-14
BART ANALYSIS FOR NAUGHTON UNIT 2 

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

which would be removed from the scrubber with the sludge, and disposed of. 

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

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

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

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

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

alkaline reagent. 

Wet lime/limestone scrubbing is projected to achieve 90 to 95 percent SO2 removal. At 

Naughton 2, this removal efficiency is projected to meet a limit of 0.15 pound of SO2 per 

MMBtu if low- or high-sulfur coal is used with the existing ESP. 

Step 3: Evaluate Effectiveness of Remaining Control Technologies 

Table 3-4 contains a summary of the projected emission rates for the FGD technologies being 

evaluated for Naughton 2. 

TABLE 3-4 

SO2 Control Technology Emission Rates 

Naughton 2 

Control Technology 

Projected SO2 Emission Rate 

(pound per million British thermal units) 

Dry Flue Gas Desulfurization (FGD) with Existing Electrostatic 

Precipitator (ESP) 0.41 

Dry FGD with Fabric Filter 0.15 

Wet FGD with Existing ESP and New Stack 0.10 

Step 4: Evaluate Impacts and Document Results 

This step involves the consideration of energy, environmental, and economic impacts 

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

considered during the evaluation. 

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

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

Naughton 2 using the existing ESP would require approximately 2.2 MW of power, 

compared to approximately 3.3 MW for a wet FGD system. Based on a 90 percent annual 

plant capacity factor, this difference would equate to an annual power savings of 

approximately 8.3 million kilowatt-hours (kWh) for a dry FGD rather than a wet FGD at 

Naughton 2. 

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

when compared to wet FGD technology: 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-15
BART ANALYSIS FOR NAUGHTON UNIT 2 

• Sulfuric Acid Mist. Sulfur trioxide (SO3) in the flue gas, which condenses to liquid 

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

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

require the addition of a wet ESP or hydrated lime injection to remove the balance of 

SO3, when medium- to high-sulfur coal is burned in a unit. Otherwise, the emission of 

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

vapor plume dissipates. 

• Plume Buoyancy. Flue gas following a dry FGD system is not saturated with water 

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

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

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

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

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

• Liquid Waste Disposal. No liquid waste results from use of a dry FGD system. 

However, wet FGD systems produce a wastewater blowdown stream that must be treated 

to limit chloride buildup in the absorber scrubbing loop. In some cases, a wastewater 

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

wastewater treatment plant would produce a small volume of solid waste that could 

contain toxic metals and might require special considerations for disposal. 

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

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

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

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

that needs to be disposed of. 

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

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

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

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

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

is provided in Table 3-5, and a comparison of the first year control cost (cost per ton 

removed) is shown in Figure 3-5. A complete economic analysis is found in Appendix A. 

Preliminary BART Selection. CH2M HILL recommends the combination of using a dry FGD 

system with the existing ESP, and using a coal with a sulfur content that does not exceed 

1.02 percent by weight, as BART for Naughton 2. This recommendation is based on 

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

minimal additional power requirements and environmental impacts with the use of a dry 

FGD system and existing ESP.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-16
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-17

TABLE 3-5 

SO2 Control Cost Comparison (Incremental to Existing FGD System) 

Naughton 2 

Factor 

Dry Flue Gas 

Desulfurization 

(FGD) with 

Electrostatic 

Precipitator 

(ESP) 

Dry FGD with 

Fabric Filter Wet FGD 

Total Installed Capital Costs $88.9 million $141.2 $126.1 million 

Total First Year Fixed & Variable Operations & 

Maintenance Costs 

$6.5 million $5.5 million $5.9 million 

Total First Year Annualized Cost $14.9 million $18.9 million $17.9 million 

Power Consumption (megawatts) 2.2 3.6 3.3 

Annual Power Usage (1,000 megawatt hours per year) 17.7 28.6 26.0 

Sulfur Dioxide (SO2) Design Control Efficiency 80.1% 87.3% 91.5% 

Tons SO2 Removed per Year 15,645 9,768 10,241 

First Year Average Control Cost 

($ per ton of SO2 Removed) 955 1,934 1,752 

Incremental Control Cost 

($ per ton of SO2 Removed) 955 1,934 1,752 
BA

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

Naughton 2 

0

500

1,0001,5002,0002,500

Dry FGD w/ESP & Higher S Coal Dry FGD w/Fabric Filter Wet FGD 

Air Pollution Control Option

Control Cost ($/Ton SO2 Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 2 

3.2.3 BART PM10 Analysis 

Naughton 2 currently is equipped with a mechanical dust collector and an ESP. ESPs remove 

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

then attracting these charged 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. Historically, the ESP at Naughton 2 has 

controlled PM10 emissions to level of 0.064 pound per MMBtu. 

The BART analysis for PM10 emissions from Naughton 2 is described in the following steps. 

For the modeling analysis in Section 4, PM10 was used as an indicator for PM, and PM10 

includes PM2.5 as a subset. 

Step 1: Identify Available Retrofit Control Technologies 

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

• Flue gas conditioning (FGC) 

• Polishing fabric filter 

• Replacement of fabric filter 

Step 2: Eliminate Technically Infeasible Options 

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

sub-bituminous coal, the ash is not collected effectively in a small ESP because the elevated 

resistivity makes the particles less willing to accept an electrical charge. Adding FGC, which 

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

they will accept more charge, allowing 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 

ESP at Naughton 2. One such technology is licensed by the Electric Power Research 

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

COHPAC collects the ash that the ESP does not collect, 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-sized fabric filter. 

The smaller size is due to the fact that the COHPAC has a higher air-to-cloth ratio (7 to 9:1), 

compared to the ratio of a full-sized pulse jet fabric filter (3.5 to 4:1). 

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

with a new fabric filter. However, because of the environmental and cost benefits (that is, the 

fact that the same control efficiencies that would be achieved by a replacement fabric filter 

are achieved by installing a polishing fabric filter downstream of the existing ESP only at 

lower costs) installation of a full fabric filter was not considered in the analysis. 

Step 3: Evaluate Effectiveness of Remaining Control Technologies 

The existing ESP at Naughton 2 achieves a controlled PM emission rate of 0.064 pound per 

MMBtu. Adding FGC upstream of the existing ESP is projected to reduce PM emissions to 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-19
BART ANALYSIS FOR NAUGHTON UNIT 2 

approximately 0.040 pound per MMBtu. Adding a COHPAC fabric filter downstream of the 

existing ESP is projected to reduce PM emissions to approximately 0.015 pound per MMBtu. 

A new fabric filter is also projected to reduce PM emissions to approximately 0.015 pound 

per MMBtu. 

A summary of the PM10 control technology emission rates is shown in Table 3-6. 

TABLE 3-6 

PM10 Control Technology Emission Rates 

Naughton 2 

Control Technology 

Projected PM10 Emission Rate 

(pound per million British 

thermal units) 

Flue Gas Conditioning 0.040 

Polishing Fabric Filter 0.015 

Replacement Fabric Filter 0.015 

Step 4: Evaluate Impacts and Document 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 would require 

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

A COHPAC fabric filter at Naughton 2 would require approximately 1.4 MW of power, 

equating to an annual power usage of approximately 10.9 million kWh, based on a 90 percent 

annual plant capacity factor. 

No negative environmental impacts would result from the addition of an FGC system. 

Environmental Impacts. No negative environmental impacts result from the addition of a 

COHPAC polishing fabric filter or FGC system. 

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

conditionings are recorded in Table 3-7, and the first year of control costs for FGC and fabric 

filters are shown in Figure 3-6. The complete economic analysis is contained in Appendix A. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-20
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-21

Preliminary BART Selection. CH2M HILL recommends adding flue gas conditioning to the 

existing ESP as BART for Naughton 2. This recommendation 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. 

TABLE 3-7 

PM10 Control Cost Comparison 

Naughton 2 

Factor 

Flue Gas 

Conditioning Polishing Fabric Filter 

Total Installed Capital Costs $1.3 million $34.9 million 

Total First Year Fixed and Variable Operation and 

Maintenance Costs 

$0.1 million $0.8 million 

Total First Year Annualized Cost $0.2 million $4.1 million 

Power Consumption (megawatts) 0.1 1.4 

Annual Power Usage (1,000 megawatt hours per 

year) 

0.4 10.9 

PM Design Control Efficiency 37.5% 76.6% 

Tons Particulate Matter (PM) Removed per Year 227 464 

First Year Average Control Cost 

($ per ton of PM Removed) 949 8,848 

Incremental Control Cost 

($ per ton of PM Removed) 949 16,432 
BA

FIGURE 3-6 First Year Control Cost for PM Air Pollution Control Options Naughton 2 

0

2,0004,0006,0008,000

10,00012,00014,00016,00018,000

Flue Gas Conditioning Fabric Filter

Air Pollution Control Option

Control Cost ($/Ton PM Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_NAUGHTON2__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 2 at Class I areas. The Class I areas potentially 

affected are located more than 50 but less than 300 kilometers from the Naughton 2 Plant. 

These wilderness areas (WA) include: 

• Bridger WA 

• Fitzpatrick WA 

The CALPUFF modeling system includes the CALMET meteorological model 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 that CH2M HILL used 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 Naughton 2 and to include a 50-kilometer buffer around the Class I 

areas that were within 300 kilometers of the facility. Grid resolution was 4 kilometers. 

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

otherwise by the Wyoming Department of Environmental Quality – Air Quality Division 

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

Protocol, which is included in Appendix B of this report. WDEQ-AQD prepared this 

protocol. 

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

large extent of the domain. The latitude of the projection origin and the longitude of the 

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

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

minimize distortion in the north-south direction. 

JMS EY102007001SLC\BART_NAUGHTON2__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 2 

The default technical options listed in current example CALMET.inp file of TRC 

Companies, Inc. (TRC) were used for CALMET. Vertical resolution of the wind field 

included 10 layers, with vertical face heights as follows (in meters): 

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

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

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

analysis. 

TABLE 4-1 

User-specified CALMET Options 

Naughton 2 

CALMET Input Parameter Value 

CALMET Input Group 2 

 Map projection (PMAP) Lambert Conformal 

 Grid spacing (DGRIDKM) 4 

 Number vertical layers (NZ) 10 

 Top of lowest layer (m) 20 

 Top of highest layer (m) 3500 

CALMET Input Group 4 

 Observation mode (NOOBS) 0 

CALMET Input Group 5 

 Prog. Wind data (IPROG) 14 

 (RMAX1) 30 

 (RMAX2) 50 

 Terrain influence (TERRAD) 15 

 (R1) 5 

 (R2) 25 

CALMET Input Group 6 

 Max mixing ht (ZIMAX) 3500 

4.2.2 CALMET Input Data 

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

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

Version 5 (MM5) meteorological data fields that covered the entire modeling domain for 

each year. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-3
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-4

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

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

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

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

final Step 2 wind field. 

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

CH2M HILL processed the data from the Automated Surface Observing System network of 

the National Weather Service for all stations that are in the domain. The surface data were 

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

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

SMERGE preprocessor and CALMET. 

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

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

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

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

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

Digital Elevation Model data, which primarily derive from USGS 1:250,000-scale 

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

appropriate for the missing area. 

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

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

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

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

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

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

following stations: 

• Denver, Colorado 

• Salt Lake City, Utah 

• Riverton, Wyoming 

• Rapid City, South Dakota 

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

domain. 
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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BART ANALYSIS FOR NAUGHTON UNIT 2 

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 (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 precontrol (baseline) scenario for comparison to the predicted 

impacts for post-control scenarios for Naughton 2. 

4.3.1 Background Ozone and Ammonia 

CALPUFF used hourly values of background ozone concentrations 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 

(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 2. 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 

Precontrol emission rates for Naughton 2 reflect the peak 24-hour-average emissions that 

could occur under the current permit of the source. The emission rates reflect actual 

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-6
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-7

Regulations and Guidelines for Best Available Retrofit Technology Determinations; Final 

Rule (40 CFR Part 51). 

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

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

more recent period was more representative. Allowable short-term (24 hours or less) 

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 precontrol 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 performed 

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

levels for each pollutant. 

• Scenario 1: New LNBs with OFA modifications, a dry FGD system, and flue gas 

conditioning for enhanced ESP performance. As indicated previously, this scenario 

represents the preliminary BART recommendation of CH2M HILL. 

• Scenario 2: New LNBs with OFA modifications, a dry FGD system, and new fabric 

filter. 

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

fabric filter. 

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

enhanced ESP performance, and a new stack. 

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

Baseline Post-control Scenario 1 Post-control S

Model Input Data Current Operations with ESP LNB with OFA, Dry FGD, ESP 

LNB with OFA, D

Fabric F

Sulfur Dioxide (SO2) Stack Emissions 

(pounds per hour [lb/hr]) 2,868 984 359 

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,291 576 574 

PM10 Stack Emissions (lb/hr) 154 96.0 36.0 

Coarse Particulate (PM2.5 <diameter< PM10) Stack Emissions (lb/hr)(a) 65.8 41.3 20.4 

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 87.2 54.7 15.4 Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 44.2 2.16 2.16 

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 43.3 2.12 2.12 

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

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

(NH4)HSO4 Stack Emissions (lb/hr) 

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

Total Sulfate (SO4) (lb/hr) 43.1 2.12 2.11 

Stack Conditions

Stack Height (meters) 68 68 68 Stack Exit Diameter (meters) 4.88 4.88 4.88 Stack Exit Temperature (Kelvin) 411 350 343 Stack Exit Velocity (meters per second) 27.8 20.21 24.3 Notes:

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

diameter. 

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

Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack Emissions (lb/hr)
BART ANALYSIS FOR NAUGHTON UNIT 2 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology options for Naughton 2 followed this 

sequence: 

• Model precontrol (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 and 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 in deciview relative to natural background. Default extinction 

coefficients for each pollutant, as shown below, 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 [ƒ(RH)] were used in the light-extinction calculations to account for the 

hygroscopic characteristics of nitrate and sulfate particles. Table 5 in the WDEQ BART Air 

Modeling Protocol (shown in Appendix B) lists the monthly ƒ(RH) for the Class I areas. 

These values were used for the specific 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 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-9
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-10

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

Estimating Natural Visibility Conditions Under the Regional Haze Rule (EPA, 2003). 

A separate scaling factor was derived for each Class I area such that, when multiplied by the 

guidance table annual concentrations, the 20 percent best days dV value for that area would 

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

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

2005). However, the Wyoming BART Air Modeling Protocol provided natural background 

concentrations of aerosol components to use in the BART analysis (Appendix B). Table 4-3 

lists the annual average species concentrations from the BART protocol. 

TABLE 4-3 

Average Natural Levels of Aerosol Components 

Naughton 2 

Aerosol Component 

Average Natural Concentration 

 Bridger and Fitzpatrick WA Class I Areas 

(micrograms per cubic meter) 

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: WDEQ-AQD, 2006 

4.5 Presentation of Modeling Results 

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

for Naughton 2. 

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario 

CH2M HILL modeled Naughton 2 for the baseline and four post-control scenarios. The 

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

achieved if BART state-of-the-art technology were installed at Unit 2. 

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 2 

Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost Class I Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

No. of Days Above 

0.5 dV 

C

 2001 Baseline: current operation with Bridger WA 5.420 2.127 61 

electrostatic precipitator 

(ESP) Fitzpatrick WA 3.277 1.158 26 Scenario 1: Low-NO $15,951,704 Bridger WA 2.635 0.838 28 $

x burner (LNB) with over-fire air (OFA), 

dry flue gas desulfurization (FGD), ESP $15,951,704 Fitzpatrick WA 1.515 0.462 6 $

$19,686,224 Bridger WA 2.078 0.642 14 $

Scenario 2: LNB with OFA, dry FGD, fabric filter $19,686,224 Fitzpatrick WA 1.113 0.312 3 $

$27,429,327 Bridger WA 0.949 0.284 2 $

Scenario 3: LNB with OFA and selective catalytic reduction (SCR), dry FGD, fabric filter $27,429,327 Fitzpatrick WA 0.519 0.158 1 $Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $26,693,951 Bridger WA 1.627 0.482 7 $stack $26,693,951 Fitzpatrick WA 0.717 0.208 2 $ 2002 

Bridger WA 4.349 1.860 56 

Baseline: current operation with ESP 

Fitzpatrick WA 3.900 1.099 24 

$15,951,704 Bridger WA 1.728 0.926 18 $

Scenario 1: LNB with OFA, dry FGD, ESP $15,951,704 Fitzpatrick WA 1.667 0.413 5 $

$19,686,224 Bridger WA 1.389 0.745 11 $

Scenario 2: LNB with OFA, dry FGD, fabric filter $19,686,224 Fitzpatrick WA 1.153 0.286 4 $

$27,429,327 Bridger WA 0.618 0.321 3 $

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $27,429,327 Fitzpatrick WA 0.542 0.141 1 $Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $26,693,951 Bridger WA 1.076 0.354 4 $stack $26,693,951 Fitzpatrick WA 0.887 0.138 1 $

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Naughton 2 

 Modeling Results 

Scenario 

Total First 

Year 

Annualized 

Cost Class I Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

No. of Days Above 

0.5 dV 

C

 2003 

Bridger WA 4.678 2.087 55 

Baseline: current operation with ESP 

Fitzpatrick WA 2.466 1.110 22 

$15,951,704 Bridger WA 2.136 0.882 19 $

Scenario 1: LNB with OFA, dry FGD, ESP $15,951,704 Fitzpatrick WA 1.296 0.448 6 $

$19,686,224 Bridger WA 1.735 0.614 12 $

Scenario 2: LNB with OFA, dry FGD, fabric filter $19,686,224 Fitzpatrick WA 0.855 0.313 4 $

$27,429,327 Bridger WA 0.791 0.291 3 $

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $27,429,327 Fitzpatrick WA 0.465 0.148 0 $Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $26,693,951 Bridger WA 1.102 0.526 8 $stack $26,693,951 Fitzpatrick WA 0.363 0.162 0 $3-Year Averages 

Bridger WA 2.025 57.3 

Baseline: current operation with ESP 

Fitzpatrick WA 1.122 24.0 

$15,951,704 Bridger WA 0.882 21.7 $

Scenario 1: LNB with OFA, dry FGD, ESP 

$15,951,704 Fitzpatrick WA 0.441 5.7 $

$19,686,224 Bridger WA 0.667 12.3 $

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

$19,686,224 Fitzpatrick WA 0.304 3.7 $

$27,429,327 Bridger WA 0.299 2.7 $

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

$27,429,327 Fitzpatrick WA 0.149 0.7 $

$26,693,951 Bridger WA 0.454 6.3 $

Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new stack $26,693,951 Fitzpatrick WA 0.169 1.0 $

NOTES:Scenario 4 produces worse results than Scenario 3. Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $15,951,704/ (2.306 - 0.908) = $11,410,375 Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001: = $15,951,704 / (76 - 32) = $362,539 
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 2, the preliminary recommended BART controls 

for NOx, SO2, and PM are as follows:

• New LNBs and OFA system for NOx control

• Lime spray dryer FGD for SO2 control and a coal sulfur limit less than 1.02 weight 

percent

• Add FGC ahead of the existing ESP for PM control

The above recommendations were identified as Scenario 1 for the modeling analysis 

described in Section 4, except for the FGC. Visibility improvements for all emission control 

scenarios were analyzed, and the results are compared in Table 5-1 using a Least-Cost 

Envelope, as outlined in the New Source Review Workshop Manual (EPA, 1990), referred to 

hereafter as the NSR Manual. 

5.1 Least-cost Envelope Analysis 

An objective analysis of the results has been performed using the EPA Least-cost Envelope 

method. The methodology and results of the analysis are described in this section. 

5.1.1 Analysis Methodology 

On page B-41 of the NSR Manual, the EPA states (EPA, 1990): “Incremental costeffectiveness 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 manner. 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, represent a comparison of 

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

areas. The incremental cost-effectiveness is determined by the difference in total annual costs 

between two contiguous scenarios divided by the difference in emissions reduction. 

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 affected 

by the operation of Naughton 2. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-1
BART ANALYSIS FOR NAUGHTON UNIT 2 

TABLE 5-1 

Bridger WA Class I Agent Control Data 

Naughton 2 

Scenario Controls 

98th

Percentile 

deciview 

(dV( 

Reduction 

Exceedance 

Reduction 

(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 Burner (LNB) 

with Over-fire Air (OFA), 

Dry Flue Gas 

Desulfurization (FGD), 

ESP 

1.14 35.7 $16.0 $14.0 $0.4 

2 LNB with OFA, Dry FGD, 

New Fabric Filter 

1.36 45.0 $19.7 $14.5 $0.4 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), Dry 

FGD, Fabric Filter 

1.73 54.7 $27.4 $15.9 $0.5 

4 LNB with OFA and SCR, 

Wet FGD, ESP, New 

Stack 

1.57 51.0 $26.7 $17.0 $0.5 

TABLE 5-2 

Fitzpatrick WA Class I Area Control Data 

Naughton 2 

Scenario Controls 

98th

Percentile 

dV 

Reduction 

Exceedance 

Reduction 

(Days) 

Total 

Annualized 

Cost 

(million$) 

Cost per dV 

Reduction 

(million$/dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Exceeding 

0.5 dV 

(million$/Day 

Reduced) 

Base Current Operation with ESP 0.00 0.0 $0.0 $0.0 $0.0 

1 LNB with OFA, Dry FGD, 

ESP 

0.68 18.3 $16.0 $23.4 $0.9 

2 LNB with OFA, Dry FGD, 

New Fabric Filter 

0.82 20.3 $19.7 $24.0 $1.0 

3 LNB with OFA and SCR, 

Dry FGD, Fabric Filter 

0.97 23.3 $27.4 $28.2 $1.2 

4 LNB with OFA and SCR, 

Wet FGD, ESP, New Stack 

0.95 23.0 $26.7 $28.0 $1.2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-2
BART ANALYSIS FOR NAUGHTON UNIT 2 

TABLE 5-3 

Bridger WA Class I Agent Incremental Data 

Naughton 2 

Options Compared 

Incremental 

Exceedance 

Reductions 

(Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(million$/Days) 

Incremental 

Cost 

Effectiveness 

(million$/dV) 

Baseline and Scenario 1 35.7 1.14 $0.45 $13.96 

Scenario 1 and Scenario 2 9.3 0.22 $0.4 $17.4 

Scenario 1 and Scenario 3 19.0 0.58 $0.6 $19.7 

Scenario 1 and Scenario 4 15.3 0.43 $0.7 $25.1 

NOTE: 

Because Scenario 3 produces better results in visibility than Scenario 4, Scenario 4 was not analyzed further. 

TABLE 5-4 

Fitzpatrick WA Class I Area Incremental Data 

Naughton 2 

Options Compared 

Incremental 

Exceedance 

Reductions 

(Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(million$/Days) 

Incremental 

Cost 

Effectiveness 

(million$/dV) 

Baseline and Scenario 1 18.3 0.68 $0.87 $23.41 

Scenario 1 and Scenario 2 2.0 0.14 $1.9 $27.2 

Scenario 1 and Scenario 3 5.0 0.29 $2.3 $39.3 

Scenario 1 and Scenario 4 4.7 0.27 $2.3 $39.5 

NOTE: 

Because Scenario 3 produces better results in visibility than Scenario 4, Scenario 4 was not analyzed further. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-3
BART ANALYSIS FOR NAUGHTON UNIT 2 

FIGURE 5-1 

Least-cost Envelope Bridger WA Class I Area Reduction Days Reduction 

Naughton 2 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0 10 20 30 40 50 6

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

0

FIGURE 5-2 

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

Naughton 2 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-4
BART ANALYSIS FOR NAUGHTON UNIT 2 

FIGURE 5-3 

Least-cost Envelope Fitzpatrick WA Class I Area Days Reduction 

Naughton 2 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0 5 10 15 20 25

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

FIGURE 5-4 

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

Naughton 2 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-5
BART ANALYSIS FOR NAUGHTON UNIT 2 

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 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 high incremental costs on the bases of 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 0.5 dV, and the cost increment is excessive. It is also 

to the left of the curves indicating a scenario with lower improvement or higher costs. 

Thus, the scenario was eliminated from consideration. 

Analysis of the results for the Bridger Class I WA in Tables 5-1 and 5-3 and Figures 5-1 and 

5-2 illustrates the conclusions stated above. The greatest reduction in 98th percentile dV and 

number of days above 0.5 dV is between the Baseline and Scenario 1. For example, Table 5-3 

shows that the incremental cost-effectiveness for Scenario 1 compared to the Baseline is 

$450,000 per day and $13.96 million per dV to improve visibility at the Bridger WA. 

In addition, the incremental cost-effectiveness for Scenario 2 compared to Scenario 1 is 

$400,000 per day and $17.4 million per dV. The incremental cost-effectiveness for 

Scenario 3 compared to Scenario 1 is also excessive at $600,000 per day and $19.7 million 

per dV. 

Using Table 5-4, a similar conclusion is reached for improving visibility at the Fitzpatrick 

WA. In fact, the incremental costs are higher for improving visibility in the Fitzpatrick WA 

than in the Bridger WA. Therefore, the EPA Least-cost Analysis indicates that Scenario 1 

represents the proper BART control technology for Naughton 2 because the incremental costeffectiveness would be excessive if either Scenario 2 or Scenario 3 were chosen compared to 

Scenario 1. 

5.2 Recommendations 

5.2.1 NOx Emission Control 

The characteristics of the P&M coals are more closely aligned with bituminous coals that 

produce higher NOx emissions than typical sub-bituminous coals, such as PRB coals. 

CH2M HILL recommends LNB with OFA as BART for Naughton 2, based on the projected 

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

additional power requirements or non-air quality environmental impacts. NOx reductions are 

expected to be similar to those realized at the Jim Bridger plant where these devices have 

been installed on Unit 2. This selection of new LNB with OFA at Naughton 2 is projected to 

attain an emission rate at or below 0.26 pound per MMBtu. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-6
BART ANALYSIS FOR NAUGHTON UNIT 2 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-7

5.2.2 SO2 Emission Control 

CH2M HILL recommends installing a dry lime FGD system as BART for Naughton 2, 

assuming use of coal containing no more than 1.02 percent sulfur by weight. This 

recommendation is based on the significant reduction in SO2 emissions, reasonable control 

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

quality environmental impacts. 

5.2.3 PM10 Emission Control 

CH2M HILL recommends the addition of an FGC system to enhance the performance of the 

existing ESP as BART for Naughton 2. This recommendation is based on the reduction in 

PM10 emissions, reasonable control costs, and the advantages of minimal additional power 

requirements and no non-air quality environmental impacts. 

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

Haze by Dr. Ronald Henry (2002), state that only dV differences of approximately 1.5 to 

2.0 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, although many millions of dollars 

would be spent, only minimal visibility improvements might result. 

Finally, none of the data were corrected for natural obscuration. During the period of 2001 

through 2003, several mega-wildfires occurred and lasted for many days, and the fires 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 2 facility, the costs per dV 

reduction that are presented in this report would increase. 
6.0 References 

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

Technology Determinations; Final Rule. July 6, 2005. 

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

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

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

and Nonattainment Area Permitting. Draft. October 1990. 

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

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

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

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

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

http://docs.lib.noaa.gov/rescue/dwm/data_rescue_daily_weather_maps.html. 

Accessed October 2006. 

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

Improvement Modeling Analysis in North Dakota. North Dakota Department of 

Health. October 26, 2005. 

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

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

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

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

Quality Division. September 2006. 

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 6-1
APPENDIX A 

Economic Analysis 
PacifiCorp BART Analysis Scenarios

8

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 2

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

Scenario 4 - LNB wSCR, Wet FGD, ES

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
ECONOMIC ANALYSIS SUMMARY

Naughton Unit 2 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/ESP & Higher S Coal 

w/

Case 1 2 3 4 5 6 

NOx Emission Control System None LNB w/OFA ROFA

LNB w/OFA & 

SNCR

LNB w/OFA & 

SCR None 

SO2 Emission Control System None None None None None

Dry FGD w/ESP & 

Higher S Coal Dry 

PM Emission Control System ESP ESP ESP ESP ESP ESP 

TOTAL INSTALLED CAPITAL COST ($) 0 7,500,001 10,586,222 19,878,765 72,960,588 88,896,713 FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 506,128 Maintenance Material ($) 0 32,000 48,000 93,000 160,000 860,174 Maintenance Labor ($) 0 48,000 72,000 139,500 240,000 573,044 Administrative Labor ($) 0 0 0 0 0 0 TOTAL FIXED O&M COST 0 80,000 120,000 232,500 400,000 1,939,345 Makeup Water Cost 0 0 0 0 0 94,962 Reagent Cost 0 0 0 547,170 365,145 2,425,901 SCR Catalyst / FF Bag Cost 0 0 0 0 303,000 0 Waste Disposal Cost 0 0 0 0 0 1,139,518 Electric Power Cost 0 0 1,028,842 86,724 527,834 886,556 TOTAL VARIABLE O&M COST 0 0 1,028,842 633,894 1,195,979 4,546,936 

TOTAL FIRST YEAR O&M COST 0 80,000 1,148,842 866,394 1,595,979 6,486,281 

FIRST YEAR DEBT SERVICE ($) 0 713,459 1,007,044 1,891,024 6,940,582 8,456,551 TOTAL FIRST YEAR COST ($) 0 793,459 2,155,887 2,757,418 8,536,561 14,942,832 

Power Consumption (MW) 0.0 0.0 2.6 0.2 1.3 2.2 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 20.6 1.7 10.6 17.7 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 55.6% 51.9% 64.8% 87.0% 0.0% 

NOx Removed (Tons/Yr) 0 2,838 2,649 3,311 4,446 0 First Year Average Control Cost ($/Ton NOx Rem.) 0 280 814 833 1,920 0 

Incremental Control Cost ($/Ton NOx Removed) 0 280 814 4,152 3,550 0 

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

SO2 Removal Rate (%) 0.0% 0.0% 0.0% 0.0% 0.0% 80.1% 

SO2 Removed (Tons/Yr) 0 0 0 0 0 15,645 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 955 Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 955 

6-1 

PM Removal Rate (%) 98.43% 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 8,477,429 24,622,608 30,464,242 92,460,027 168,145,144 

NOx Control 

Parameter Current Operation

SO

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
INPUT CALCULATIONS

Naughton Unit 2 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/ESP & Higher S Coal Dry FGD w/

Filter 

Case 1 2 3 4 5 6 7 

NOx Emission Control System None LNB w/OFA ROFA

LNB w/OFA & 

SNCR LNB w/OFA & SCR None None 

SO2 Emission Control System None None None None None

Dry FGD w/ESP & Higher S 

Coal Dry FGD w/Fab

PM Emission Control System ESP ESP ESP ESP ESP ESP ESP Unit Design and Coal CharacteristicsType of Unit PC PC PC PC PC PC PC Net Power Output (kW) 210,000 210,000 210,000 210,000 210,000 210,000 210,000 

Net Plant Heat Rate (Btu/kW-Hr) 11,428 11,428 11,428 11,428 11,428 11,428 11,428 Boiler Fuel Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer 

Coal Heating Value (Btu/Lb) 9,800 9,800 9,800 9,800 9,800 9,875 9,800 

Coal Sulfur Content (wt.%) 0.58% 0.58% 0.58% 0.58% 0.58% 1.02% 0.58% Coal Ash Content (wt.%) 5.00% 5.00% 5.00% 5.00% 5.00% 5.25% 5.00% Boiler Heat Input, each (MMBtu/Hr) 2,400 2,400 2,400 2,400 2,400 2,400 2,400 Coal Flow Rate (Lb/Hr) 244,886 244,886 244,886 244,886 244,886 243,026 244,886  (Ton/Yr) 965,339 965,339 965,339 965,339 965,339 958,008 965,339  (MMBtu/Yr) 18,920,654 18,920,654 18,920,654 18,920,654 18,920,654 18,920,654 18,920,65EmissionsUncontrolled SO2 (Lb/Hr) 2,838 2,838 2,838 2,838 2,838 4,953 2,838  (Lb/MMBtu) 1.18 1.18 1.18 1.18 1.18 2.06 1.18  (Lb Moles/Hr) 44.30 44.30 44.30 44.30 44.30 77.31 44.30  (Tons/Yr) 11,187 11,187 11,187 11,187 11,187 19,524 11,187 SO2 Removal Rate (%) 0.0% 0.0% 0.0% 0.0% 0.0% 80.1% 87.3%  (Lb/Hr) 0 0 0 0 0 3,969 2,478  (Ton/Yr) 0 0 0 0 0 15,645 9,768 SO2 Emission Rate (Lb/Hr) 2,838 2,838 2,838 2,838 2,838 984 360  (Lb/MMBtu) 1.18 1.18 1.18 1.18 1.18 0.41 0.15 

 (Ton/Yr) 11,187 11,187 11,187 11,187 11,187 3,879 1,419 Uncontrolled NOx (Lb/Hr) 1,296 1,296 1,296 1,296 1,296 1,296 1,296  (Lb/MMBtu) 0.54 0.54 0.54 0.54 0.54 0.54 0.54 

 (Lb Moles/Hr) 43.18 43.18 43.18 43.18 43.18 43.18 43.18  (Tons/Yr) 5,109 5,109 5,109 5,109 5,109 5,109 5,109 NOx Removal Rate (%) 0.0% 55.6% 51.9% 64.8% 87.0% 0.0% 0.0% 

 (Lb/Hr) 0 720 672 840 1,128 0 0  (Lb Moles/Hr) 0.00 23.99 22.39 27.99 37.59 0.00 0.00  (Ton/Yr) 0 2,838 2,649 3,311 4,446 0 0 NOx Emission Rate (Lb/Hr) 1,296 576 624 456 168 1,296 1,296  (Lb/MMBtu) 0.54 0.24 0.26 0.19 0.07 0.54 0.54 

 (Ton/Yr) 5,109 2,270 2,460 1,797 662 5,109 5,109 Uncontrolled Fly Ash (Lb/Hr) 9,795 154 154 154 154 154 154  (Lb/MMBtu) 4.082 0.064 0.064 0.064 0.064 0.064 0.064  (Lb Moles/Hr) 326.4 5.1 5.1 5.1 5.1 5.1 5.1  (Tons/Yr) 38,614 605 605 605 605 605 605 Fly Ash Removal Rate (%) 98.43% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 9,642 0 0 0 0 0 0  (Ton/Yr) 38,008 0 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 154 154 154 154 154 154 154  (Lb/MMBtu) 0.064 0.064 0.064 0.064 0.064 0.064 0.064 

 (Ton/Yr) 605 605 605 605 605 605 605 

Parameter 

Current Operation NOx Control SO2 Contr

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Dry FGD w/ESP & Higher S Coal Dry FGD w/

Filter 

Case 1 2 3 4 5 6 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 7,884 Annual On-Site Power Plant Capacity Factor 0.90 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% 7.10% Discount Rate (%) 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% 7.10% Plant Economic Life (Years) 20 20 20 20 20 20 20 

Installed Capital Costs

NOx Emission Control System ($2006) 0 7,500,001 10,586,222 19,878,765 72,960,588 0 0 

SO2 Emission Control System ($2006) 0 0 0 0 0 88,896,713 141,244,7

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

Total Emission Control Systems ($2006) 0 7,500,001 10,586,222 19,878,765 72,960,588 88,896,713 141,244,7

NOx Emission Control System ($/kW) 0 36 50 95 347 0 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 423 673 PM Emission Control System ($/kW) 0 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 36 50 95 347 423 673 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 0 0 0 0 0 506,128 506,128 Maintenance Material ($) 0 32,000 48,000 93,000 160,000 860,174 905,190 Maintenance Labor ($) 0 48,000 72,000 139,500 240,000 573,044 640,568 Administrative Labor ($) 00000 0 0 

Total Fixed O&M Cost ($) 0 80,000 120,000 232,500 400,000 1,939,345 2,051,88

Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Water CostMakeup Water Usage (Gpm) 0 0 0 0 0 165 165 Unit Price ($/1000 Gallons) 1.22 1.22 1.22 0.00 1.22 1.22 1.22 

First Year Water Cost ($) 0 0 0 0 0 94,962 94,962 

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

Unit Cost ($/Ton) 0.00 0.00 0.00 370 400 91.25 91.25  ($/Lb) 0.000 0.000 0.000 0.185 0.200 0.046 0.046 Molar Stoichiometry 0.00 0.00 0.00 0.51 1.00 1.40 1.15 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 90% 90% 

Reagent Usage (Lb/Hr) 0 0 0 375 232 6,744 3,174 

First Year Reagent Cost ($) 0 0 0 547,170 365,145 2,425,901 1,141,77

Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% SCR Catalyst / FF Bag Replacement Cost SCR Catalyst Bags Bags 

Annual SCR Catalyst (m3) / No. FF Bags 0000 101 0 1,193 

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

First Year SCR Catalyst / Bag Replace. Cost ($) 0 0 0 0 303,000 0 124,072 

Annual SCR Catalyst / Bag Cost Esc. Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr) 0 0 0 0 0 11,880 6,381 FGD Waste Disposal Unit Cost ($/Dry Ton) 24.33 24.33 24.33 24.33 24.33 24.33 24.33 

First Year FGD Waste Disposal Cost ($) 0 0 0 0 0 1,139,518 612,026 

Annual Waste Disposal Cost Esc. Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Auxiliary Power CostAuxiliary Power Requirement (% of Plant Output) 0.00% 0.00% 1.24% 0.10% 0.64% 1.07% 1.73%  (MW) 0.00 0.00 2.61 0.22 1.34 2.25 3.63 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 1,028,842 86,724 527,834 886,556 1,431,73

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

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.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 2 BART Economic Analysis_02-08-07.xls 
Table 3 - Emissions

Controlled 

SO2 Controlled NOx

Controlled 

PM Case 2 Case 3 Case 4 Case 5 Case 

1 Dave Johnston Unit 3 1.18 0.70 0.030 0.24 0.19 0.19 0.07 

 

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

4 Jim Bridger Unit 2 0.27 0.24 0.074 0.24 0.22 0.20 0.07 5 Jim Bridger Unit 3 0.27 0.45 0.057 0.24 0.22 0.20 0.07 6 Jim Bridger Unit 4 0.17 0.45 0.030 0.24 0.22 0.20 0.07 7 Naughton Unit 1 1.18 0.58 0.056 0.24 0.26 0.19 0.07 

 

8 Naughton Unit 2 1.18 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 2 BART Economic Analysis_02-08-07.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 2 BART Economic Analysis_02-08-07.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 2 BART Economic Analysis_02-08-07.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 $ 67,159,581 $ 56,500,308 $ 

8 Naughton Unit 2 $ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 54,775,108 $ 87,030,191 $ 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 2 BART Economic Analysis_02-08-07.xls 
CAPITAL COST

Naughton Unit 2

CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control System

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

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

Major Materials Design and Supply Vendor $2,570,674 Vendor $3,123,533 Vendor $2,570,674 Vendor $2,570,674 Vendor $0 Vendor 

Construction 85.3% $2,193,653 85.3% $2,665,428 85.3% $2,193,653 85.3% $2,193,653 85.3% $0 85.3% 

Balance of Plant 51.7% $1,328,837 51.7% $1,614,621 51.7% $1,328,837 51.7% $1,328,837 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $937,060 0.0% $0 0.0% $0 0.0% $0 0.0% Owner's Costs 13.2% $340,572 13.2% $413,816 13.2% $340,572 13.2% $340,572 13.2% $0 13.2% Surcharge 16.4% $422,246 16.4% $513,056 16.4% $422,246 16.4% $422,246 16.4% $0 16.4% AFUDC 12.2% $314,097 12.2% $381,648 12.2% $314,097 12.2% $314,097 12.2% $0 12.2% Subtotal $7,170,079 $9,649,162 $7,170,079 $7,170,079 $0 Contingency 12.8% $329,922 30.0% $937,060 12.8% $329,922 12.8% $329,922 12.8% $0 12.8% Total Capital Cost for LNB w/OFA or ROFA $7,500,001 $10,586,222 $7,500,001 $7,500,001 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $8,784,000 S&L Report $47,934,000 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $1,756,800 10.0% $4,793,400 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $491,289 5.6% $2,680,949 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $4,048,985 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% $96,800 1.1% $528,233 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% $246,567 0.0% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $1,003,308 11.4% $5,475,021 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $12,378,764 $65,460,588 $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 $54,775,108 S&L Repor

Contingency 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% $10,955,022 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% $3,063,572 5.6% 

EPC Premium 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% $4,626,853 8.4% 

Boiler Reinforcement (Allowance) 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,541,372 2.8% 

Sales Tax 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% $603,622 1.1% 

Escalation 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% $5,537,216 10.1% 

Contingency on Adders 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,537,537 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% $6,256,413 11.4% 

Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $88,896,713 

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

SO2 

LNB w/OFA

None

ESP ESP

ROFA

None

Dry FGD 

Parameter

LNB w/OFA ROFA LNB w/OFA & SCR

None

Dry FGD w/ESP & Higher S Coal

ESP

LNB w/OFA & SNCR

None

ESP ESP

LNB w/OFA & SCR

None

NOx Control

2 3 45 

6 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
Naughton Unit 2 LNB w/OFA

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

0 20131 2014 80,000 - - - - - - 

 

2 2015 81,600 - - - - - - 

 

3 2016 83,232 - - - - - - 

 

4 2017 84,897 - - - - - - 

 

5 2018 86,595 - - - - - - 

 

6 2019 88,326 - - - - - - 

 

7 2020 90,093 - - - - - - 

 

8 2021 91,895 - - - - - - 

 

9 2022 93,733 - - - - - - 

 

10 2023 95,607 - - - - - - 

 

11 2024 97,520 - - - - - - 

 

12 2025 99,470 - - - - - - 

 

13 2026 101,459 - - - - - - 

 

14 2027 103,489 - - - - - - 

 

15 2028 105,558 - - - - - - 

 

16 2029 107,669 - - - - - - 

 

17 2030 109,823 - - - - - - 

 

18 2031 112,019 - - - - - - 

 

19 2032 114,260 - - - - - - 

 

20 2033 116,545 - - - - - - 

 

Present Worth - 977,428 - - - - - 

 

(% of PW) 11.5% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Naughton Unit 2 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 - - - - 1,028,842 1,028,842 

 

2 2015 122,400 - - - - 1,049,419 1,049,419 

 

3 2016 124,848 - - - - 1,070,408 1,070,408 

 

4 2017 127,345 - - - - 1,091,816 1,091,816 

 

5 2018 129,892 - - - - 1,113,652 1,113,652 

 

6 2019 132,490 - - - - 1,135,925 1,135,925 

 

7 2020 135,139 - - - - 1,158,644 1,158,644 

 

8 2021 137,842 - - - - 1,181,816 1,181,816 

 

9 2022 140,599 - - - - 1,205,453 1,205,453 

 

10 2023 143,411 - - - - 1,229,562 1,229,562 

 

11 2024 146,279 - - - - 1,254,153 1,254,153 

 

12 2025 149,205 - - - - 1,279,236 1,279,236 

 

13 2026 152,189 - - - - 1,304,821 1,304,821 

 

14 2027 155,233 - - - - 1,330,917 1,330,917 

 

15 2028 158,337 - - - - 1,357,536 1,357,536 

 

16 2029 161,504 - - - - 1,384,686 1,384,686 

 

17 2030 164,734 - - - - 1,412,380 1,412,380 

 

18 2031 168,029 - - - - 1,440,628 1,440,628 

 

19 2032 171,390 - - - - 1,469,440 1,469,440 

 

20 2033 174,817 - - - - 1,498,829 1,498,829 

 

Present Worth - 1,466,142 - - - 12,570,244 12,570,244 1

 

(% of PW) 6.0% 0.0% 0.0% 0.0% 0.0% 51.1% 51.1% 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
Naughton Unit 2 LNB w/OFA & SNCR

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

0 20131 2014 232,500 - 547,170 - - 86,724 633,894 

 

2 2015 237,150 - 558,114 - - 88,458 646,572 

 

3 2016 241,893 - 569,276 - - 90,228 659,504 

 

4 2017 246,731 - 580,661 - - 92,032 672,694 

 

5 2018 251,665 - 592,275 - - 93,873 686,147 

 

6 2019 256,699 - 604,120 - - 95,750 699,870 

 

7 2020 261,833 - 616,203 - - 97,665 713,868 

 

8 2021 267,069 - 628,527 - - 99,619 728,145 

 

9 2022 272,411 - 641,097 - - 101,611 742,708 

 

10 2023 277,859 - 653,919 - - 103,643 757,562 

 

11 2024 283,416 - 666,997 - - 105,716 772,714 

 

12 2025 289,085 - 680,337 - - 107,830 788,168 

 

13 2026 294,866 - 693,944 - - 109,987 803,931 

 

14 2027 300,764 - 707,823 - - 112,187 820,010 

 

15 2028 306,779 - 721,979 - - 114,430 836,410 

 

16 2029 312,914 - 736,419 - - 116,719 853,138 

 

17 2030 319,173 - 751,147 - - 119,053 870,201 

 

18 2031 325,556 - 766,170 - - 121,435 887,605 

 

19 2032 332,067 - 781,494 - - 123,863 905,357 

 

20 2033 338,709 - 797,124 - - 126,340 923,464 

 

Present Worth - 2,840,651 6,685,245 - - 1,059,581 7,744,827 1

 

(% of PW) 9.3% 0.0% 21.9% 0.0% 0.0% 3.5% 25.4% 

Naughton Unit 2 LNB w/OFA & SCR

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

0 20131 2014 400,000 - 365,145 303,000 - 527,834 1,195,979 

 

2 2015 408,000 - 372,448 309,060 - 538,390 1,219,899 

 

3 2016 416,160 - 379,897 315,241 - 549,158 1,244,297 

 

4 2017 424,483 - 387,495 321,546 - 560,141 1,269,183 

 

5 2018 432,973 - 395,245 327,977 - 571,344 1,294,566 

 

6 2019 441,632 - 403,150 334,536 - 582,771 1,320,458 

 

7 2020 450,465 - 411,213 341,227 - 594,427 1,346,867 

 

8 2021 459,474 - 419,437 348,052 - 606,315 1,373,804 

 

9 2022 468,664 - 427,826 355,013 - 618,441 1,401,280 

 

10 2023 478,037 - 436,382 362,113 - 630,810 1,429,306 

 

11 2024 487,598 - 445,110 369,355 - 643,426 1,457,892 

 

12 2025 497,350 - 454,012 376,742 - 656,295 1,487,050 

 

13 2026 507,297 - 463,093 384,277 - 669,421 1,516,791 

 

14 2027 517,443 - 472,354 391,963 - 682,809 1,547,126 

 

15 2028 527,792 - 481,801 399,802 - 696,465 1,578,069 

 

16 2029 538,347 - 491,437 407,798 - 710,395 1,609,630 

 

17 2030 549,114 - 501,266 415,954 - 724,603 1,641,823 

 

18 2031 560,097 - 511,292 424,273 - 739,095 1,674,659 

 

19 2032 571,298 - 521,517 432,759 - 753,877 1,708,153 

 

20 2033 582,724 - 531,948 441,414 - 768,954 1,742,316 

 

Present Worth - 4,887,141 4,461,292 3,702,010 - 6,448,996 14,612,297 7

 

(% of PW) 5.3% 0.0% 4.8% 4.0% 0.0% 7.0% 15.8% 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
Naughton Unit 2 Dry FGD w/ESP & High

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

0 20131 2014 1,939,345 94,962 2,425,901 - 1,139,518 886,556 4,546,936 

 

2 2015 1,978,132 96,861 2,474,419 - 1,162,309 904,287 4,637,875 

 

3 2016 2,017,694 98,798 2,523,907 - 1,185,555 922,373 4,730,633 

 

4 2017 2,058,048 100,774 2,574,385 - 1,209,266 940,820 4,825,245 

 

5 2018 2,099,209 102,790 2,625,873 - 1,233,451 959,637 4,921,750 

 

6 2019 2,141,193 104,845 2,678,390 - 1,258,120 978,829 5,020,185 

 

7 2020 2,184,017 106,942 2,731,958 - 1,283,283 998,406 5,120,589 

 

8 2021 2,227,697 109,081 2,786,597 - 1,308,948 1,018,374 5,223,001 

 

9 2022 2,272,251 111,263 2,842,329 - 1,335,127 1,038,741 5,327,461 

 

10 2023 2,317,696 113,488 2,899,176 - 1,361,830 1,059,516 5,434,010 

 

11 2024 2,364,050 115,758 2,957,159 - 1,389,066 1,080,707 5,542,690 

 

12 2025 2,411,331 118,073 3,016,303 - 1,416,848 1,102,321 5,653,544 

 

13 2026 2,459,558 120,434 3,076,629 - 1,445,185 1,124,367 5,766,615 

 

14 2027 2,508,749 122,843 3,138,161 - 1,474,088 1,146,854 5,881,947 

 

15 2028 2,558,924 125,300 3,200,924 - 1,503,570 1,169,792 5,999,586 

 

16 2029 2,610,103 127,806 3,264,943 - 1,533,641 1,193,187 6,119,578 

 

17 2030 2,662,305 130,362 3,330,242 - 1,564,314 1,217,051 6,241,969 

 

18 2031 2,715,551 132,969 3,396,847 - 1,595,601 1,241,392 6,366,809 

 

19 2032 2,769,862 135,629 3,464,783 - 1,627,513 1,266,220 6,494,145 

 

20 2033 2,825,259 138,341 3,534,079 - 1,660,063 1,291,544 6,624,028 

 

Present Worth 1,160,228 23,694,629 29,639,298 - 13,922,466 10,831,809 55,553,801 8

 

(% of PW) 14.1% 0.7% 17.6% 0.0% 8.3% 6.4% 33.0% 

Naughton Unit 2 Dry FGD w/Fabric Filte

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

0 20131 2014 2,051,885 94,962 1,141,778 124,072 612,026 1,431,734 3,404,572 1

 

2 2015 2,092,923 96,861 1,164,614 126,553 624,267 1,460,369 3,472,664 1

 

3 2016 2,134,781 98,798 1,187,906 129,085 636,752 1,489,576 3,542,117 1

 

4 2017 2,177,477 100,774 1,211,664 131,666 649,487 1,519,368 3,612,959 1

 

5 2018 2,221,026 102,790 1,235,897 134,300 662,477 1,549,755 3,685,218 1

 

6 2019 2,265,447 104,845 1,260,615 136,986 675,726 1,580,750 3,758,923 1

 

7 2020 2,310,756 106,942 1,285,827 139,725 689,241 1,612,365 3,834,101 1

 

8 2021 2,356,971 109,081 1,311,544 142,520 703,026 1,644,613 3,910,783 1

 

9 2022 2,404,110 111,263 1,337,775 145,370 717,086 1,677,505 3,988,999 1

 

10 2023 2,452,193 113,488 1,364,530 148,278 731,428 1,711,055 4,068,779 1

 

11 2024 2,501,237 115,758 1,391,821 151,243 746,056 1,745,276 4,150,154 1

 

12 2025 2,551,261 118,073 1,419,657 154,268 760,977 1,780,182 4,233,158 1

 

13 2026 2,602,286 120,434 1,448,051 157,353 776,197 1,815,785 4,317,821 1

 

14 2027 2,654,332 122,843 1,477,012 160,500 791,721 1,852,101 4,404,177 1

 

15 2028 2,707,419 125,300 1,506,552 163,710 807,555 1,889,143 4,492,261 1

 

16 2029 2,761,567 127,806 1,536,683 166,985 823,706 1,926,926 4,582,106 1

 

17 2030 2,816,799 130,362 1,567,416 170,324 840,181 1,965,465 4,673,748 1

 

18 2031 2,873,135 132,969 1,598,765 173,731 856,984 2,004,774 4,767,223 1

 

19 2032 2,930,597 135,629 1,630,740 177,205 874,124 2,044,869 4,862,567 1

 

20 2033 2,989,209 138,341 1,663,355 180,749 891,606 2,085,767 4,959,819 1

 

Present Worth 1,160,228 25,069,631 13,950,076 1,515,893 7,477,644 17,492,721 41,596,563 14

 

(% of PW) 12.1% 0.6% 6.7% 0.7% 3.6% 8.4% 20.0% 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
Naughton Unit 2 Wet FGD w/ESP

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

0 20131 2014 2,853,781 126,616 954,332 - 711,213 1,300,860 3,093,020 1

 

2 2015 2,910,857 129,148 973,419 - 725,437 1,326,877 3,154,881 1

 

3 2016 2,969,074 131,731 992,887 - 739,946 1,353,415 3,217,979 1

 

4 2017 3,028,455 134,365 1,012,745 - 754,745 1,380,483 3,282,338 1

 

5 2018 3,089,024 137,053 1,033,000 - 769,839 1,408,093 3,347,985 1

 

6 2019 3,150,805 139,794 1,053,660 - 785,236 1,436,255 3,414,945 1

 

7 2020 3,213,821 142,590 1,074,733 - 800,941 1,464,980 3,483,243 1

 

8 2021 3,278,097 145,442 1,096,228 - 816,960 1,494,279 3,552,908 1

 

9 2022 3,343,659 148,350 1,118,152 - 833,299 1,524,165 3,623,966 1

 

10 2023 3,410,533 151,317 1,140,515 - 849,965 1,554,648 3,696,446 1

 

11 2024 3,478,743 154,344 1,163,326 - 866,964 1,585,741 3,770,375 1

 

12 2025 3,548,318 157,431 1,186,592 - 884,303 1,617,456 3,845,782 1

 

13 2026 3,619,284 160,579 1,210,324 - 901,990 1,649,805 3,922,698 1

 

14 2027 3,691,670 163,791 1,234,531 - 920,029 1,682,801 4,001,152 1

 

15 2028 3,765,503 167,067 1,259,221 - 938,430 1,716,457 4,081,175 1

 

16 2029 3,840,814 170,408 1,284,406 - 957,199 1,750,786 4,162,798 1

 

17 2030 3,917,630 173,816 1,310,094 - 976,343 1,785,802 4,246,054 1

 

18 2031 3,995,982 177,292 1,336,296 - 995,869 1,821,518 4,330,975 1

 

19 2032 4,075,902 180,838 1,363,021 - 1,015,787 1,857,948 4,417,595 1

 

20 2033 4,157,420 184,455 1,390,282 - 1,036,102 1,895,107 4,505,947 1

 

Present Worth 1,546,971 34,867,078 11,659,892 - 8,689,491 15,893,717 37,790,071 12

 

(% of PW) 17.5% 0.8% 5.9% 0.0% 4.4% 8.0% 19.0% 

Naughton Unit 2 Flue Gas Conditioning

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 10,000 - 62,194 - - 19,710 81,904 

 

2 2015 10,200 - 63,438 - - 20,104 83,542 

 

3 2016 10,404 - 64,707 - - 20,506 85,213 

 

4 2017 10,612 - 66,001 - - 20,916 86,918 

 

5 2018 10,824 - 67,321 - - 21,335 88,656 

 

6 2019 11,041 - 68,668 - - 21,761 90,429 

 

7 2020 11,262 - 70,041 - - 22,197 92,238 

 

8 2021 11,487 - 71,442 - - 22,641 94,082 

 

9 2022 11,717 - 72,871 - - 23,093 95,964 

 

10 2023 11,951 - 74,328 - - 23,555 97,883 

 

11 2024 12,190 - 75,815 - - 24,026 99,841 

 

12 2025 12,434 - 77,331 - - 24,507 101,838 

 

13 2026 12,682 - 78,877 - - 24,997 103,875 

 

14 2027 12,936 - 80,455 - - 25,497 105,952 

 

15 2028 13,195 - 82,064 - - 26,007 108,071 

 

16 2029 13,459 - 83,705 - - 26,527 110,232 

 

17 2030 13,728 - 85,380 - - 27,058 112,437 

 

18 2031 14,002 - 87,087 - - 27,599 114,686 

 

19 2032 14,282 - 88,829 - - 28,151 116,980 

 

20 2033 14,568 - 90,605 - - 28,714 119,319 

 

Present Worth - 122,179 759,881 - - 240,814 1,000,695 

 

(% of PW) 5.0% 0.0% 31.4% 0.0% 0.0% 9.9% 41.3% 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
Naughton Unit 2 Fabric Filter

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

0 20131 2014 112,540 - - 124,072 - 545,179 669,251 

 

2 2015 114,791 - - 126,553 - 556,082 682,636 

 

3 2016 117,087 - - 129,085 - 567,204 696,288 

 

4 2017 119,429 - - 131,666 - 578,548 710,214 

 

5 2018 121,817 - - 134,300 - 590,119 724,418 

 

6 2019 124,254 - - 136,986 - 601,921 738,907 

 

7 2020 126,739 - - 139,725 - 613,960 753,685 

 

8 2021 129,274 - - 142,520 - 626,239 768,759 

 

9 2022 131,859 - - 145,370 - 638,764 784,134 

 

10 2023 134,496 - - 148,278 - 651,539 799,816 

 

11 2024 137,186 - - 151,243 - 664,570 815,813 

 

12 2025 139,930 - - 154,268 - 677,861 832,129 

 

13 2026 142,728 - - 157,353 - 691,418 848,772 

 

14 2027 145,583 - - 160,500 - 705,247 865,747 

 

15 2028 148,495 - - 163,710 - 719,352 883,062 

 

16 2029 151,465 - - 166,985 - 733,739 900,723 

 

17 2030 154,494 - - 170,324 - 748,413 918,738 

 

18 2031 157,584 - - 173,731 - 763,382 937,112 

 

19 2032 160,735 - - 177,205 - 778,649 955,855 

 

20 2033 163,950 - - 180,749 - 794,222 974,972 

 

Present Worth - 1,375,002 - 1,515,893 - 6,660,912 8,176,806 3

 

(% of PW) 3.1% 0.0% 0.0% 3.4% 0.0% 15.0% 18.4% 

EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 
EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 

First Year Cost for Air Pollution Control Options

0

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

10,000,00012,000,00014,000,00016,000,00018,000,00020,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Dry FGDw/ESP &

Higher S Coal

Dry FGD

w/Fabric

Filter

Wet FGD

w/ESP

F

Co

Air Pollution Control Option

First Year Cost ($)
EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 

Present Worth Cost for Air Pollution Control Options

0

50,000,000

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

LNB w/OFA ROFA LNB w/OFA

& SNCR

LNB w/OFA

& SCR

Dry FGD

w/ESP &

Higher S

Coal

Dry FGD

w/Fabric

Filter

Wet FGD

w/ESP

F

Co

Air Pollution Control Options

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

2006 Wyoming BART Protocol