Final Report 

BART Analysis for 

Naughton Unit 1 

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 1 

Submitted to 

PacifiCorp 

Decmeber 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 1 (hereafter referred to as Naughton 1). A BART analysis has 

been conducted for the following criteria pollutants: oxides of nitrogen (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 710 megawatts 

(MW). Because the total generating capacity of the Naughton Station does not exceed 

750 MW, presumptive BART limits do not directly apply to Naughton 1, based on the United 

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

goal unless it is determined that an alternative control level is justified based on a careful 

consideration of the statutory factors. BART emissions limits must be achieved within 5 years 

after the State Implementation Plan (SIP) is approved by the EPA. A compliance date of 2014 

was assumed for this analysis. 

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

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

alternatives were investigated, listed below by pollutant: 

• NOx emission controls: 

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

− Rotating opposed fire air (ROFA) 

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

− LNBs 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 1 

BART Engineering Analysis 

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

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

• The identification of available, technically feasible, retrofit control options 

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

availability of options and their impacts) 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

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

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

BART 

The following steps are incorporated into the BART analysis: 

• Step 1 – Identify All Available Retrofit Control Technologies 

• Step 2 – Eliminate Technically Infeasible Options 

− The identification of available, technically feasible, retrofit control options 

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

the applicability of options and their impacts) 

• Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

• Step 4 – Evaluate Impacts and Document the Results 

− The costs of compliance with the control options 

− The remaining useful life of the facility 

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

• Step 5 – Evaluate Visibility Impacts 

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

of BART 

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

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

2014 BART implementation date. 

Coal Characteristics 

The main source of coal burned at Naughton 1 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 U.S. This BART analysis has 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-2
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

as compared to those coals used at Naughton 1, and has evaluated the effect of these qualities 

on NOx formation and achievable emission rates. 

Recommendations 

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

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

identified as Scenario 1 throughout this report. 

NOx Emission Control 

Naughton 1 burns coal from P&M. As documented in this analysis, the characteristics of the 

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

CH2M HILL recommends LNBs with OFA as BART for Naughton 1, 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 LNBs with OFA at Naughton 1 is projected to 

attain an emission rate at or below 0.26 pound (lb) 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 1, 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 approach is projected to have a SO2 emission rate of 

0.41 lb per MMBtu. 

PM10 Emission Control 

CH2M HILL recommends the addition of a flue gas conditioning system to enhance the 

performance of the existing ESP as BART for Naughton 1, based on the significant reduction 

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

requirements and no non-air quality environmental impacts. 

BART Modeling Analysis 

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

emissions from Naughton 1 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: 

• Bridger Wilderness Area 

• Fitzpatrick Wilderness Area 

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BART ANALYSIS FOR NAUGHTON UNIT 1 

Because Naughton 1 will simultaneously control NOx, SO2, and PM10 emissions, four 

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

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

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

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

conditioning for enhanced ESP performance and higher sulfur coal. As indicated 

previously, this scenario represents CH2M HILL’s preliminary BART recommendation. 

• Scenario 2: New LNB 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, flue gas 

conditioning for enhanced ESP performance, and 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 draft EPA 1990 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 a 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 1 

JMS EY102007001SLC\BART_NAUGHTON1_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, ESP with SO3 injection and new 

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

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

Scenario 1 represents BART for Naughton 1. 

Just-Noticeable Differences in Atmospheric Haze 

Studies have been conducted that demonstrate dV differences of only approximately 1.5 to 

2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot be 

distinguished by the average person. Therefore, the modeling analysis results indicate that 

only minimal, if any, observable visibility improvements at the Class I areas studied would be 

expected under any of the control scenarios. Thus, the results indicate that only minimal 

discernable visibility improvements may result, even though PacifiCorp will spend many 

millions of dollars at this single unit, and over $1 billion 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.................................................................................... 5-7 

5.2.1 NOx Emission Control ................................................................. 5-7 

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

5.2.3 PM10 Emission Control................................................................ 5-7 

5.3 Just-Noticeable Differences in Atmospheric Haze.................................. 5-7 

6.0 References ......................................................................................................... 6-1

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

JMS EY102007001SLC\BART_NAUGHTON1_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 Wilderness Area Class I Agent Control Data

5-2 Fitzpatrick Wilderness Area Class I Area Control Data

5-3 Bridger Wilderness Area Class I Agent Incremental Data

5-4 Fitzpatrick Wilderness Area 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 Wilderness Area Class I Area Days Reduction 

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

Reduction 

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

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

Reduction 

Appendices 

A Economic Analysis

B 2006 Wyoming BART Protocol
Acronyms and Abbreviations 

acfm Actual Cubic Feet per Minute 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CALDESK Program to display data and results 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing program for calculating visibility impacts 

CALPUFF Gaussian puff dispersion model 

CFR Code of Federal Regulations 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

ESP Electrostatic Precipitator 

EPA United States Environmental Protection Agency 

FGC Flue Gas Conditioning 

FGD Flue Gas Desulfurization 

kWh Kilowatt-hour 

LAER Lowest Achievable Emission Rate 

lb Pound 

LNB Low-NOx burner 

LOI Loss on Ignition 

MMBtu Million British Thermal Units 

MM5 Mesoscale Meteorological Model, Version 5 

MW Megawatt 

N2 Nitrogen 

NOx Nitrogen Oxide 

(NH4)2SO4 Ammonium Sulfate 

OFA Over-fire Air 

P&M P&M Kemmerer Mine 

PM10 Particulate Matter less than 10 Micrometers in Aerodynamic Diameter 

PRB Powder River Basin 

ROFA Rotating Opposed Fire Air 

S&L Sargent & Lundy 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC v
ACRONYMS AND ABBREVIATIONS (CONTINUED) 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC vi

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

SCR Selective Catalytic Reduction System 

SIP State Implementation Plan 

SNCR Selective Non-catalytic Reduction System 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

TRC TRC Companies, Inc. 

USGS United States Geological Survey 

WA Wilderness Area 

WDEQ Wyoming Department of Environmental Quality 

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

Best Available Retrofit Technology (BART) guidelines were established as a result of United 

States Environmental Protection Agency (EPA) regulations intended to reduce the 

occurrence of regional haze in national parks and other Class I-protected air quality areas in 

the United States. These guidelines provide guidance for states when determining which 

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

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

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

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

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

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

report for Naughton 1 by February 9, 2007. The BART Report that was submitted to WDEQ 

in February 2007 included a BART analysis, and a proposal and justification for BART at the 

source. This revised report—submitted in October 2007—incorporates editorial revisions and 

new model revisions since the January 2007 version. 

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

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

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

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

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

5 years of EPA’s approval of the SIP. 

There are five basic elements related to BART, when addressing the issue of emissions for 

the identified facilities: 

• The cost of the controls 

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

• Any existing pollution control technology in use at the source 

• The remaining useful life of the source 

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

of such technology 

This report documents the BART analysis that was performed on Naughton 1 by 

CH2M HILL for PacifiCorp. The analysis was performed for the pollutants NOx, sulfur 

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

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

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

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

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

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

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

Wyoming BART Protocol. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 1-1
2.0 Present Unit Operation 

Naughton 1 is a nominal 160-megawatts (MW) unit located approximately 6 miles southwest 

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

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

Cottrell mechanical dust collector for particulate matter control, and a Lodge Cottrell 

electrostatic precipitator (ESP) was added in 1974. The unit presently uses low sulfur coal to 

control SOx below 1.2 pounds (lb) per million British thermal units (MMBtu) and an ESP to 

control particulate matter. The unit uses good combustion practices for NOx control. 

Naughton 1 began operation in 1963. 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 1 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 1 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 1 is the P&M Kemmerer Mine (P&M). This 

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

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

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

use in the U.S. 

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

characteristics of PRB coals, as compared to those coals used Naughton 1 and the effect of 

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

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

source were used in the modeling analysis. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 2-1
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 2-2

TABLE 2-1 

Present Unit Operation 

Naughton 1 

General Plant Data 

Site Elevation (feet above mean sea level) 6939 

Stack Height (feet) 200 

Stack Exit Internal Diameter (feet) /Exit Area (square feet). 14 / 153.9 

Stack Exit Temperature (degrees Fahrenheit) 280 

Stack Exit Velocity (feet/second) 76 

Stack Flow actual cubic feet per minute (actual cubic feet per 

minute) 

701,784 

Latitude (deg: min : sec) 41:45:26.84 

Longitude (deg: min : sec) 110:35:54.01 

Annual Unit Capacity Factor (percentage) 90 

Net Unit Output (megawatts) 160 

Net Unit Heat Rate (British thermal units [Btu] per kilowatt hour 

[kWh])(100% load) 

10,680 (as measured by fuel 

throughput) 

Boiler Heat Input (million Btu [MMBtu] per hour)(100% load) 1,850 (as measured by CEM) 

Type of Boiler Tangentially fired 

Boiler Fuel Coal 

Coal Sources P & M Kemmerer Mine 

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

Coal Sulfur Content (wt. percentage)(a) 0.58 

Coal Ash Content (wt. percentage)(a) 5.00 

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

Coal Nitrogen Content (wt. %) 1.3 

Current NOx Controls Good combustion practices 

Pre-project NOx Emission Rate (lb per MMBtu) 0.58 

Current Sulfur Dioxide Controls Use of low sulfur coal 

Pre-project Sulfur Dioxide Emission Rate (lb per MMBtu) 1.20 

Current PM10 Controls(b) Electrostatic precipitator 

Pre-project particulate matter Emission Rate (lb per MMBtu) 0.056 

NOTES:

(a)Coal characteristics vary between coal sources (b)PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter
BA

TABLE 2-2 Coal Sources and Characteristics Naughton 1 

Ultimate Analys

Mines 

Moist. 

(%) 

Ash 

(%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

units 

per 

pound 

Sulfur 

(%) Hydrogen Carbon Sulfur 

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 sample

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 
3.0 BART Engineering Analysis 

This section presents the required BART engineering analysis. 

3.1 Applicability 

In compliance with regional haze requirements, the State of Wyoming must prepare and submit 

visibility SIPs to the EPA for Class I areas. The State has estimated that the formal submittal of 

the SIPs will occur by early 2008. The first phase of the regional haze program is the 

implementation of BART emission controls on all BART eligible units, within 5 years after 

EPA approval of the SIP. 

3.2 BART Process 

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

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

• The identification of available, technically feasible, retrofit control options 

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

availability of options and their impacts) 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

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

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

BART 

The following steps are incorporated into the BART analysis: 

• Step 1 – Identify All Available Retrofit Control Technologies 

• Step 2 – Eliminate Technically Infeasible Options 

− The identification of available, technically feasible, retrofit control options 

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

applicability of options and their impacts) 

• Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

• Step 4 – Evaluate Impacts and Document the Results 

− The costs of compliance with the control options 

− The remaining useful life of the facility 

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-1
BART ANALYSIS FOR NAUGHTON UNIT 1 

• Step 5 – Evaluate Visibility Impacts 

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

of BART 

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

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

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

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

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

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

implementation date). 

3.2.1 BART NOx Analysis 

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

including operating conditions, equipment design, and coal characteristics. 

Formation of NOx 

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

the oxidation of fuel-bound nitrogen (fuel NOx). During combustion, part of the fuel-bound 

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

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

oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen (N2). A 

smaller part of NOx formation is caused by high temperature fixation of atmospheric nitrogen 

in the combustion air (thermal NOx). A very small amount of NOx is called “prompt” NOx. 

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

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

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

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

NOx. 

Coal characteristics directly and significantly affect NOx emissions from coal combustion. 

Coal ranking is a means of classifying coals according to their degree of metamorphism in the 

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

coals, such as the sub-bituminous coals from the PRB, produce lower NOx emissions than 

higher rank bituminous coals because of their higher reactivity and lower nitrogen content. The 

fixed carbon to volatile matter ratio (fuel ratio), coal oxygen content, and rank are good relative 

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

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

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

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

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

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

Information Administration, PRB coals currently represent 88 percent of total 

U.S. sub-bituminous production and 73 percent of western coal production (Energy 

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-2
BART ANALYSIS FOR NAUGHTON UNIT 1 

infer PRB origin and characteristics. Emissions standards differentiating between bituminous 

and sub-bituminous coals are presumed to use PRB coal as the basis for the sub-bituminous 

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

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

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

including most of the low NOx forming characteristics. Coals from the P&M mine 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 by Figure 3-1, the increased porosity provides more 

particle surface area resulting in more favorable combustion conditions. This 

non-agglomerating property assists in making sub-bituminous coals more amenable to 

controlling NOx by allowing less air to be introduced during the initial ignition portion of the 

combustion process. The coals from the P&M mine just barely fall into the category of 

non-agglomerating coals. While each of these coals is considered non-agglomerating, they 

either do not exhibit the properties of non-agglomerating coals or exhibit them to only a minor 

degree. The conditions during combustion of typical non-agglomerating coals that make it 

easier to control NOx emissions do not exist for the coal used at Naughton 1. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-3
BART ANALYSIS FOR NAUGHTON UNIT 1 

FIGURE 3-1 

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

Naughton 1 

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

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

representative western bituminous coal. 

TABLE 3-1 

Coal Characteristics Comparison 

Naughton 1 

Parameter PRB 

P&M 

Low 

Sulfur 

P&M High 

Sulfur Twentymile 

Nitrogen (% dry) 1.10 1.33 1.22 1.85 

Oxygen (% dry) 16.2 15.35 14.57 7.19 

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-4
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

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

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

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

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

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

emissions, through use of combustion control measures such as LNBs and over fire air (OFA). 

These characteristics indicate that higher NOx formation is likely with coal from the P&M 

mine, rather than with PRB coal. The P&M coal contains quality characteristics that fall 

between a typical PRB coal and Twentymile, a clearly bituminous coal that produces higher 

NOx—as has been demonstrated at power plants burning this fuel. 

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

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

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

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

Twentymile is used to graphically illustrate 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 the P&M mine that is used at 

Naughton 1, and indicates the average NOx emission rate of 0.57 lb 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 Naughton 1 with a 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 lb per MMBtu. 

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

0.24 lb per MMBtu for the control device that has been installed at Jim Bridger 2. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-5
BART ANALYSIS FOR NAUGHTON UNIT 1 

FIGURE 3-2 

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

Naughton 1 

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 1 

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)

ptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15lb/MMBtu

Bituminous Presum

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

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

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

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

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

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

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

the P&M mine that is burned at Naughton 1. 

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

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

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

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

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

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

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

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

other performance issues can result. 

Naughton 1 is located at an altitude of 6,936 feet above sea level. At this elevation, 

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

14.7 lbs per square inch. This lower pressure means that less oxygen is available for 

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

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

flows and distribution to reduce NOx emissions using LNBs and 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 release of volatiles and assist char burnout due to more surface area exposed 

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

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

and service as pulverizer grinding surfaces wear. 

When all the factors—of agglomeration versus non-agglomeration, nitrogen and oxygen 

content of the coals, and the grindability index—are taken into account, this analysis 

demonstrates that for the coal used at Naughton 1, LNB technology referred to in the EPA’s 

presumptive BART analysis will achieve NOx reductions similar the rates identified for 

tangentially fired boilers that burn bituminous coals. The current NOx emission rate at 

Naughton 1 is 0.58 lb per MMBtu. 

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 1, including those control technologies identified as Best 

Available Control Technology (BACT) or lowest achievable emission rate by permitting 

agencies across the United States. A broad range of information sources have been reviewed in 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-7
BART ANALYSIS FOR NAUGHTON UNIT 1 

an effort to identify potentially applicable emission control technologies. NOx emissions from 

Naughton 1 are currently controlled through the use of good combustion practices and OFA. 

The following potential NOx control technology options were considered: 

• New/modified LNB with advanced OFA 

• Mobotec rotating opposed fire air (ROFA) 

• Conventional selective non-catalytic reduction (SNCR) system 

• Selective catalytic reduction (SCR) system 

Step 2: Eliminate Technically Infeasible Options 

For Naughton 1 technical feasibility will primarily be determined by physical constraints and 

boiler configuration. Naughton 1 has an uncontrolled NOx emission rate of 0.58 lb per MMBtu. 

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

on the Multi-Pollutant Control Report (Sargent and Lundy, 2002, hereafter referred to as the 

S&L Study). Updated cost estimates for SCR and SNCR were used (Sargent & Lundy, 2006). 

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

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

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

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

it reduces NOx to nitrogen and water. NOx reductions of up to 40 to 60 percent have been 

achieved, although 15 to 30 percent is more realistic for most applications. SNCR is typically 

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

problematic. 

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

with projected NOx emission rates. 

TABLE 3-2 

NOx Control Technology Projected Emission Rates 

Naughton 1 

Technology Projected Emission Rate (pounds 

per million British thermal units) 

Bituminous Presumptive Limit 0.28 

Low-NOx Burner (LNB) with 

Over-fire Air (OFA) 

0.24 

Rotating Opposed Fire Air 0.26 

LNB with OFA and Selective 

Non-catalytic Reduction 

System 

0.19 

LNB with OFA and Selective 

Catalytic Reduction System 

0.07 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-8
BART ANALYSIS FOR NAUGHTON UNIT 1 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

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

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

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

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

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

must be qualified, and it must be recognized that contractual guarantees are established only 

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

control technologies and the control effectiveness evaluated in this BART analysis. 

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

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

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

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

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

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

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

boiler vendors—indicates that new LNB and OFA retrofit at Naughton 1 would result in an 

expected NOx emission rate of 0.24 lb per MMBtu. PacifiCorp has indicated that this rate 

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

and they believe that this emission rate can be sustained as an average between overhauls. This 

emission rate represents a significant reduction from the NOx emission rate of 

0.58 lb per MMBtu. 

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

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

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

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

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

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

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

one 1,900-horsepower fan for Naughton 1. 

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

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

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

proposal, primarily based on ROFA equipment, the operation of existing burners was analyzed. 

While a typical installation does not require modification to the existing burner system, results 

of computational fluid dynamics modeling will determine the quantity and location of new 

ROFA ports. The Mobotec proposal includes bent tube assemblies for ROFA port installation. 

Mobotec does not provide installation services, because they believe that the Owner can more 

cost-effectively contract for these services. However, they do provide one onsite construction 

supervisor during installation and startup. 

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-9
BART ANALYSIS FOR NAUGHTON UNIT 1 

SNCR. Selective non-catalytic reduction is generally used to achieve modest NOx reductions on 

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

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

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

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

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

can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating 

conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or 

inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to create problems 

downstream. The ammonia may render fly ash unsaleable, react with sulfur to foul heat 

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

significant impact on economics, with higher levels of NOx reduction generally resulting in 

lower reagent utilization and higher operating cost. 

Reductions from higher baseline concentrations (inlet NOx) are lower in cost per ton, but result 

in higher operating costs because of greater reagent consumption. To reduce reagent costs, 

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

of achieving a projected NOx emission rate of 0.24 lb per MMBtu. At a further reduction of 

20 percent in NOx emission rates for SNCR would result in a projected emission rate of 

0.19 lb per MMBtu. 

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

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

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

SCR. SCR works on the same principle as SNCR but 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. As a result 

of 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 downstream from the boiler 

economizer and upstream of the air heater and any particulate control equipment. In this 

location, the SCR is exposed to the full concentration of fly ash in the flue gas that is leaving 

the boiler. The high-dust configuration is assumed for Naughton 1. In a full-scale SCR, the flue 

ducts are routed to a separate large reactor containing the catalyst. With in-duct SCR, the 

catalyst is located in the existing gas duct, which may be expanded in the area of the catalyst to 

increase flue gas residence time. Due to the higher removal rate, a full-scale SCR was used as 

the basis for analysis at Naughton 1. 

S&L prepared the design conditions and cost estimates for SCR at Naughton 1. As with SNCR, 

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

combustion modifications to minimize the catalyst surface area and ammonia requirements of 

the SCR. To reduce reagent costs, S&L has assumed that combustion modifications, including 

LNBs and OFA, providing a NOx emission rate of 0.24 lb 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 lb per MMBtu. Additional catalyst surface was included in the SCR design to 

accommodate the characteristics of the coal used at Naughton 1. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-10
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

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

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

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

level. Variations may result for many reasons, including coal characteristics, unit load, boiler 

operation including excess air, boiler slagging, burner equipment condition, coal mill fineness, 

and so forth. 

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

follows: 

1. Establish expected NOx emissions value from vendor. 

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

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

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

NOx emissions are. 

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

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

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

Step 4: Evaluate Impacts and Document the Results 

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

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

considered during the evaluation. 

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

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

energy impacts. 

The Mobotec ROFA system would require installation and operation of one 1,900 horsepower 

ROFA fan. 

SCR retrofit impacts the existing flue gas fan systems, due to the additional pressure drop 

associated with the catalyst, which is typically a 6- to 8-inch increase. Total additional power 

requirements for SCR installation at Naughton 1 are estimated at approximately 980 kilowatts, 

based on the S&L Study. 

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

in CO emissions and 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 may also 

result in higher carbon monoxide emissions and loss on ignition, which will result in unburned 

carbon in the ash. 

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-11
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-12

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

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

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

estimates is stated by S&L to be in the range of plus or minus 20 percent. Cost for the ROFA 

system was obtained from Mobotec to which construction and other costs were added to make 

a comparable estimate. 

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

NOx removed is summarized in Table 3-3, and the first year control costs are presented in 

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

TABLE 3-3 

NOx Control Cost Comparison 

Naughton 1 

Factor 

Low NOx 

Burner with 

(LNB) with 

Over-fire Air 

(OFA) 

Rotating 

Opposed 

Fire Air 

LNB with 

OFA and 

Selective 

Non-catalytic 

Reduction 

System 

LNB with 

OFA and 

Selective 

Catalytic 

Reduction 

System 

Total Installed Capital Costs $7.3 million $9.1 million $17.5 million $58.2 million 

Total First Year Fixed & Variable 

Operation and Maintenance Costs $0.1 million $0.7 million $0.7 million $1.2 million 

Total First Year Annualized Cost $0.8 million $1.5 million $2.3 million $6.7 million 

Power Consumption (megawatts) -- 1.4 0.2 1.0 

Annual Power Usage (1000 megawatthours per year) -- 11.2 1.3 7.7 

NOx Design Control Efficiency 58.6% 55.2% 67.2% 87.9% 

Tons NOx Removed per Year 2,480 2,334 2,844 3,719 

First Year Average Control Cost ($ per 

Ton of Nitrogen Oxides Removed) 312 660 822 1,812 

Incremental Control Cost ($ per Ton of 

Nitrogen Oxides Removed) 312 660 4,287 3,751 

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

for Naughton 1, based on its significant reduction in NOx emissions, reasonable control cost, 

and no additional power requirements or environmental impacts. As discussed in the section on 

coal quality, the recommended technology and the achieved emission rate are deemed 

appropriate as BART for NOx emissions from the coals combusted at Naughton 1.

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 1 

0

500

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

LNB w/OFA ROFA LNB w/OFA & SNCR 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 1 

3.2.2 BART SO2 Analysis 

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

on coal sulfur content. The BART analysis for SO2 emissions on Naughton 1 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 1, including control 

technologies identified as BACT or lowest achievable emission rate 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 1 currently has an uncontrolled SO2 emission rate of approximately 

1.20 lb 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 1, this dry particulate matter would be 

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

typically produces a dry waste product suitable for landfill disposal. 

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

lower sulfur coal. This would result in a controlled SO2 emission rate from Naughton 1 equal 

to 0.18 lb per MMBtu, based on an average coal sulfur content of 0.58 percent by weight. 

Therefore, this option cannot meet a limit of 0.15 lb per MMBtu. 

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

emission rate is projected to be 0.41 lb per MMBtu. Therefore, this option cannot meet a 

limit of 0.15 lb 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; by using the lower sulfur coal, an 

87.5 percent SO2 removal is projected, allowing the facility to meet a limit of 

0.15 lb per MMBtu. 

However, if higher sulfur coal at 1.02 percent sulfur is used, the controlled SO2 emission rate 

is projected to be 0.21 lb per MMBtu. Therefore, this option cannot meet a limit of 

0.15 lb 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) 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-14
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

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

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

which are removed from the scrubber with the sludge, and disposed. Most wet FGD systems 

use forced oxidation to assure that only calcium sulfate sludge is produced. The wet 

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

variations on wet FGD technology are offered by various process developers. These 

variations include using a jet bubbling reactor as a combination SO2 absorber and calcium 

sulfite oxidation vessel, and using magnesium enhanced lime as the alkaline reagent. 

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

Naughton 1, this removal efficiency is projected to meet a limit of 0.15 lb per MMBtu if low 

or high sulfur coal is used with the existing ESP. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Table 3-4 summarizes the projected emission rates for the FGD technologies being evaluated 

for Naughton 1. 

TABLE 3-4 

SO2 Control Technology Emission Rates 

Naughton 1 

Control Technology Projected Sulfur Dioxide Emission Rate 

(pounds per million British thermal units) 

Bituminous Presumptive Limit 0.15 

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 the Results 

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

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

considered during the evaluation. 

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

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

Naughton 1 using the existing ESP would require approximately 1.6 MW of power, 

compared to approximately 2.4 MW for wet FGD. Based on a 90 percent annual plant 

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

5.9 million kilowatt-hours (kWh) for dry FGD versus wet FGD. 

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

when compared to wet FGD technology: 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-15
BART ANALYSIS FOR NAUGHTON UNIT 1 

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

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

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

require the addition of a wet ESP or hydrated lime injection when medium to high sulfur 

coal is burned in a unit to remove the balance of SO3. Otherwise, the emission rate 

rankings are shown in Table 3-4 of sulfuric acid mist, if above a threshold value, may 

result in a visible plume after the vapor plume dissipates. 

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

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

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

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

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

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

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

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

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

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

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

metals and may 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. 

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

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

a valuable commodity in Wyoming, the reduced water consumption required for dry 

FGD is major advantage for this technology. 

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

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

ton removed) is shown in Figure 3-5. The complete Economic Analysis is contained in 

Appendix A. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-16
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-17

TABLE 3-5 

SO2 Control Cost Comparison (Incremental to Existing FGD System) 

Naughton 1 

Factor 

Dry Flue Gas 

Desulfurization 

(FGD) with 

Electrostatic 

precipitator 

(ESP) 

Dry FGD 

with Fabric 

Filter Wet FGD 

Total Installed Capital 

Costs 

$64.3 million $109.0 million $91.7 million 

Total First Year Fixed & 

Variable Operation and 

Maintenance Costs 

$5.0 million $4.2 million $4.7 million 

Total First Year 

Annualized Cost 

$11.1 million $14.5 million $13.5 million 

Power Consumption 

(megawatts) 

1.6 2.7 2.4 

Annual Power Usage 

(1000 megawatt-hours per 

year) 

13.0 20.9 18.9 

Sulfur Dioxide Design 

Control Efficiency 

80.1% 87.3% 91.5% 

Tons Sulfur Dioxide 

Removed per Year 

12,061 7,530 7,895 

First Year Average Control 

Cost ($ per ton of Sulfur 

Dioxide Removed) 

918 1,929 1,705 

Incremental Control Cost 

($ per ton of Sulfur Dioxide 

Removed) 

918 1,929 1,705 

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 1 based on its significant reduction in SO2

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

requirements and environmental impacts.

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BA

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

Naughton 1 

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_NAUGHTON1_OCT2007_FINAL.DOC 
BART ANALYSIS FOR NAUGHTON UNIT 1 

3.2.3 BART PM10 Analysis 

Naughton 1 is currently equipped with a mechanical dust collector and an ESP. ESPs remove 

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

direct current voltage, and attracting these particles to grounded collection plates. A layer of 

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

rapping the plates. The collected ash particles drop into hoppers below the precipitator and 

are removed periodically by the fly ash-handling system. Historically, the ESP at Naughton 1 

has controlled PM10 emissions to levels of 0.056 lb per MMBtu. 

The BART analysis for PM10 emissions from Naughton 1 is described in this section. For the 

modeling analysis in Section 4, PM10 was used as an indicator for particulate matter, and 

PM10 includes PM2.5 as a subset. 

Step 1: Identify All Available Retrofit Control Technologies 

Three retrofit control technologies have been identified for additional particulate matter 

control: 

• Flue gas conditioning (FGC) 

• Polishing fabric filter 

• Replacement fabric filter 

Step 2: Eliminate Technically Infeasible Options 

FGC. 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. This is because the high resistivity makes 

the particles less willing to accept an electrical charge. Adding FGC, which is typically 

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

accept more charge and allow the ESP to collect the ash more effectively. Adding FGC can 

account for large improvements in collection efficiency for small ESPs. 

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

ESP at Naughton 1. One such technology is licensed by the Electric Power Research 

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

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

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

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

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

jet fabric filter (3.5 to 4:1). 

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

with a new fabric filter. However, because the environmental benefits that would be achieved 

by a replacement fabric filter are also achieved by installing a polishing fabric filter 

downstream of the existing ESP at lower costs, installation of a full fabric filter was not 

considered to be cost-effective in the analysis. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-19
BART ANALYSIS FOR NAUGHTON UNIT 1 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

The existing ESP at Naughton 1 is achieving a controlled particulate matter emission rate of 

0.056 lb per MMBtu. Adding FGC upstream of the existing ESP is projected to reduce 

particulate matter emissions to approximately 0.040 lb per MMBtu. Adding a COHPAC 

fabric filter downstream of the existing ESP is projected to reduce particulate matter 

emissions to approximately 0.015 lb per MMBtu. A replacement fabric filter is also projected 

to reduce particulate matter emissions to approximately 0.015 lb per MMBtu. 

The PM10 control technology emission rates are summarized in Table 3-6. 

TABLE 3-6 

PM10 Control Technology Emission Rates 

Naughton 1 

Control Technology 

Projected PM10 Emission Rate 

(pounds 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 the Results 

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

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

considered during the evaluation. 

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

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

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

A COHPAC fabric filter at Naughton 1 would require approximately 1.0 MW of power, 

equating to an annual power usage of approximately 8.0 million kWh, based on a 90 percent 

annual plant capacity factor. 

There are no negative environmental impacts from the addition of an FGC system. 

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

COHPAC polishing fabric filter or FGC system. 

Economic Impacts. A summary of the costs and particulate matter removed for COHPAC and 

FGCs are recorded in Table 3-7, and the first-year 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_NAUGHTON1_OCT2007_FINAL.DOC 3-20
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-21

TABLE 3-7 

PM10 Control Cost Comparison 

Naughton 1 

Factor 

Flue Gas 

Conditioning Polishing Fabric Filter 

Total Installed Capital Costs $1.3 million $29.8 million 

Total First Year Fixed & Variable O&M Costs $0.1 million $0.6 million 

Total First Year Annualized Cost $0.2 million $3.4 million 

Power Consumption (megawatts) 0.1 1.01 

Annual Power Usage (kilowatt-hours per year) 0.4 8.0 

Particulate Matter Design Control Efficiency 28.6% 73.2% 

Tons PM Removed per Year 117 299 

First Year Average Control Cost 

($ per Ton of Particulate Matter Removed) 1,721 11,493 

Incremental Control Cost 

($ per Ton of Sulfur Dioxide Removed) 1,721 17,747 

Preliminary BART Selection. CH2M HILL recommends adding FCG to the existing ESP as 

BART for Naughton 1, based on the significant reduction in PM10 emissions, reasonable 

control costs, and the advantages that both do not create additional power requirements or 

non-air quality environmental impacts. 

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
BA

FIGURE 3-6 First Year Control Cost for PM Air Pollution Control Options Naughton 1 

0

2,0004,0006,0008,000

10,00012,00014,00016,00018,00020,000

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_NAUGHTON1_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 1 at Class I areas. The Class I areas potentially 

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

Naughton 1 Plant. These wilderness areas include the following: 

• Bridger Wilderness Area 

• Fitzpatrick Wilderness Area 

The CALPUFF modeling system includes the CALMET meteorological model, CALPUFF 

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

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

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

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

• CALMET Version 5.53a, Level 040716 

• CALPUFF Version 5.711a, Level 040716 

• CALPOST Version 5.51, Level 030709 

4.2 CALMET Methodology 

4.2.1 Dimensions of the Modeling Domain 

CH2M HILL used the CALMET model to generate a three-dimensional wind field and other 

meteorological parameters suitable for use by the CALPUFF model. A modeling domain was 

established to encompass the Naughton 1 facility and allow for a 50-kilometer buffer around 

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

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

instructed otherwise by the Wyoming Department of Environmental Quality—Air Quality 

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

Modeling Protocol, which is included in this report as Appendix B. This protocol was 

prepared by the WDEQ-AQD. 

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

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

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

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

minimize distortion in the north-south direction. 

JMS EY102007001SLC\BART_NAUGHTON1_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 1 

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

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

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

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

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

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

analysis. 

TABLE 4-1 

User-specified CALMET Options 

Naughton 1 

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-kilometers resolution Mesoscale Meteorological Model, Version 5 

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-3
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-4

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

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

final Step 2 wind field. 

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

CH2M HILL processed the data for all stations from the National Weather Service’s 

Automated Surface Observing System network that are in the domain. The surface data were 

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

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

SMERGE preprocessor and CALMET. 

Land use and terrain data were obtained from the 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 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

SLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\NAUGHTON_ASOS.MXD 11/9/2006 MSLAYDEN
BART ANALYSIS FOR NAUGHTON UNIT 1 

4.2.3 Validation of CALMET Wind Field 

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

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

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

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

Atmospheric Administration, 2006). 

4.3 CALPUFF Modeling Approach 

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

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

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

over the modeling domain described earlier. The CALPUFF model was used to predict 

visibility impacts for the pre-control (baseline) scenario for comparison to the predicted 

impacts for post-control scenarios for Naughton 1. 

4.3.1 Background Ozone and Ammonia 

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

calculation of SO2 and NOx transformation with the MESOPUFF II chemical transformation 

scheme. CH2M HILL obtained hourly ozone data from the following stations located within 

the modeling domain for 2001, 2002, and 2003: 

• Rocky Mountain National Park, Colorado 

• Craters of the Moon National Park, Idaho 

• Highland, Utah 

• Thunder Basin National Grasslands, Wyoming 

• Yellowstone National Park, Wyoming 

• Centennial, Wyoming 

• Pinedale, Wyoming 

For periods of missing hourly ozone data, the chemical transformation relied on a monthly 

default value of 44 parts per billion. Background ammonia was set to 2 parts per billion. Both 

of these background values were taken from the guidance document (WDEQ-AQD, 2006). 

4.3.2 Stack Parameters 

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

current permit for Naughton 1. Post-control stack parameters reflect the anticipated changes 

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

4.3.3 Emission Rates 

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

may occur under the source’s current permit. The emission rates reflect actual emissions 

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-6
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_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-hour or shorter 

period) emissions or short-term emission limits were used if continuous emission monitoring 

data were not available. 

Emissions were modeled for the following pollutants: 

• SO2

• NOx

• Coarse particulate (PM2.5<diameter<PM10) 

• Fine particulate (diameter<PM2.5) 

• Sulfates 

Post-control emission rates reflect the effects of the emissions control scenario under 

consideration. Modeled pollutants were the same as those listed for the pre-control scenario. 

4.3.4 Post-control Scenarios 

Four post-control modeling scenarios were developed to cover the range of effectiveness for 

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

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

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

presumptive BART levels for each pollutant—unless it was determined that an alternative 

control level is justified, based on a careful consideration of the statutory factors evaluated in 

Sections 3, 4, and 5. 

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

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

represents CH2M HILL’s preliminary BART recommendation. 

• Scenario 2: New LNB 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, flue gas 

conditioning for enhanced ESP performance, and a new stack. 

Table 4-2 presents the stack parameters and emission rates used for the Naughton 1 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 1 

Baseline Post-control Scenario 1 Post-control 

Model Input Data 

Current Operations with 

Electrostatic Precipitator 

(ESP) 

Low-NOx Burner (LNB) with 

Over-fire air (OFA), Dry Flue Gas 

Desulfurization (FGD), ESP 

LNB with OFA, 

Fabric 

Sulfur Dioxide (SO2) Stack Emissions 

(pounds per hour [lb/hr]) 2,220 759 27

Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,073 444 44

PM10 Stack Emissions (lb/hr) 104 74.0 27

Coarse Particulate (PM2.5 <diameter< PM10) Stack Emissions (lb/hr)(a) 44.5 31.8 15

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 59.1 42.2 11Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 34.0 1.67 1.6

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 33.3 1.63 1.6

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) 33.3 1.63 1.6

Stack Conditions

Stack Height (meters) 61 61 61 Stack Exit Diameter (meters) 4.27 4.27 4.2Stack Exit Temperature (Kelvin) 411 350 342

Stack Exit Velocity (meters per second) 28.1 19.69 24.

NOTES: 

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

Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack Emissions (lb/hr)
BART ANALYSIS FOR NAUGHTON UNIT 1 

4.3.5 Modeling Process 

The CALPUFF modeling for the control technology options for Naughton 1 followed this 

sequence: 

• Model pre-control (baseline) emissions 

• Model preferred post-control scenario (if applicable) 

• Determine degree of visibility improvement 

• Model other control scenarios 

• Determine degree of visibility improvement 

• Factor visibility results into the BART five-step evaluation 

4.3.6 Receptor Grids 

Discrete receptors for the CALPUFF modeling were placed at uniform receptor spacing 

along the boundary and in the interior of each area of concern. Class I area receptors were 

taken from the National Park Service database for Class I area modeling receptors. The TRC 

COORDS program was used to convert all latitude/longitude coordinates to Lambert 

Conformal Conic coordinates, including receptors, meteorological stations, and source 

locations. 

4.4 CALPOST 

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

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

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

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

for each pollutant were used: 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

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

relative humidity factors were used in the light extinction calculations to account for the 

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

Air Modeling Protocol (Appendix B) lists the monthly relative humidity factors for the 

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

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

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

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-9
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-10

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

2003). A separate scaling factor was derived for each Class I area such that, when multiplied 

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

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

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

2005). However, the Wyoming BART Air Modeling Protocol (see Appendix B) provided 

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

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

TABLE 4-3 

Average Natural Levels of Aerosol Components 

Naughton 1 

Aerosol Component 

Average Natural Concentration 

(micrograms per cubic meter) 

for Fitzpatrick and Bridger Class I Wilderness Areas 

Ammonium Sulfate 0.045 

Ammonium Nitrate 0.038 

Organic Carbon 0.178 

Elemental Carbon 0.008 

Soil 0.189 

Coarse Mass 1.136 

NOTE: 

Taken from Table 6 of the Wyoming BART Air Modeling Protocol 

4.5 Presentation of Modeling Results 

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

for Naughton 1. 

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario 

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

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

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

were installed on Naughton 1. Some scenarios included controls that would not be able to 

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

that the selection of an alternative control device may be warranted. 

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

Wilderness Area, and Fitzpatrick Wilderness Area. 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 1 

Scenario 

Total First Year 

Annualized 

Cost Class I Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

No. of Days Above 

0.5 Deciview (dV) 

2001 

Bridger 

Wilderness Area 

(WA) 4.649 1.777 48 

Baseline: current operation with Electrostatic Precipitator (ESP) 

Fitzpatrick WA 2.769 0.966 23 

$12,042,621 Bridger WA 2.015 0.644 14 

Scenario 1: Low-NOx Burner (LNB) with Over-fire Air (OFA), 

dry Flue Gas Desulfurization (FGD), ESP $12,042,621 Fitzpatrick WA 1.192 0.357 3 

$15,299,091 Bridger WA 1.519 0.479 7 

Scenario 2: LNB with OFA, dry FGD, fabric filter $15,299,091 Fitzpatrick WA 0.864 0.235 2 

$21,262,911 Bridger WA 0.692 0.217 1 

Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR) System, dry FGD, fabric filter $21,262,911 Fitzpatrick WA 0.399 0.119 0 Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $20,399,907 Bridger WA 1.292 0.387 4 stack $20,399,907 Fitzpatrick WA 0.597 0.153 1 2002 

Bridger WA 3.575 1.763 41 

Baseline: current operation with ESP 

Fitzpatrick WA 3.190 0.881 18 

$12,042,621 Bridger WA 1.424 0.741 14 

Scenario 1: LNB with OFA, dry FGD, ESP $12,042,621 Fitzpatrick WA 1.124 0.314 5 

$15,299,091 Bridger WA 1.034 0.635 9 

Scenario 2: LNB with OFA, dry FGD, fabric filter $15,299,091 Fitzpatrick WA 0.834 0.205 2 

$21,262,911 Bridger WA 0.505 0.274 1 

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $21,262,911 Fitzpatrick WA 0.389 0.105 0 Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $20,399,907 Bridger WA 0.775 0.288 3 stack $20,399,907 Fitzpatrick WA 0.591 0.108 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 

TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I Areas Naughton 1 

Scenario 

Total First Year 

Annualized 

Cost Class I Area 

Highest DeltaDeciview (ΔdV) 

98th Percentile 

Delta-Deciview 

(ΔdV) 

No. of Days Above 

0.5 Deciview (dV) 

2003 

Bridger WA 4.014 1.797 45 

Baseline: current operation with ESP 

Fitzpatrick WA 2.387 0.840 20 

$12,042,621 Bridger WA 1.559 0.694 16 

Scenario 1: LNB with OFA, dry FGD, ESP $12,042,621 Fitzpatrick WA 0.927 0.361 5 

$15,299,091 Bridger WA 1.306 0.493 7 

Scenario 2: LNB with OFA, dry FGD, fabric filter $15,299,091 Fitzpatrick WA 0.634 0.266 3 

$21,262,911 Bridger WA 0.572 0.234 3 

Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter $21,262,911 Fitzpatrick WA 0.344 0.123 0 Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new $20,399,907 Bridger WA 0.964 0.397 4 stack $20,399,907 Fitzpatrick WA 0.309 0.135 0 3-Year Averages 

Bridger WA 1.779 44.7 

Baseline: current operation with ESP 

Fitzpatrick WA 0.896 20.3 

$12,042,621 Bridger WA 0.693 14.7 

Scenario 1: LNB with OFA, dry FGD, ESP 

$12,042,621 Fitzpatrick WA 0.344 4.3 

$15,299,091 Bridger WA 0.536 7.7 

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

$15,299,091 Fitzpatrick WA 0.235 2.3 

$21,262,911 Bridger WA 0.242 1.7 

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

$21,262,911 Fitzpatrick WA 0.116 0.0 

Scenario 4: LNB with OFA and SCR, wet FGD, ESP, new stack $20,399,907 Bridger WA 0.357 3.7 

$20,399,907 Fitzpatrick WA 0.132 0.7 

NOTES:Scenario 4 produces worse results than Scenario 3. Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $12,042,621 / (1.910 - 0.695) = $9,911,622 Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001: = $12,042,621 / (58 - 19) = $308,785 
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 1, the preliminary recommended BART controls 

for NOx, SO2, and PM are as follows:

• New LNBs OFA system for NOx control

• Lime spray dryer FGD for SO2 control and a coal sulfur limit of 1.02 weight percent

• Addition of FGC ahead of the existing ESP for particulate matter control

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

Section 4. Visibility improvements for all emission control scenarios were analyzed, and the 

results are compared below, utilizing a least-cost envelope, as outlined in the New Source 

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

5.1 Least-cost Envelope Analysis 

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

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

Class I areas are listed in Tables 5-1 and 5-2. A comparison of the incremental costs between 

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

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

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

5.1.1 Analysis Methodology 

On page B-41 of the New Source Review Manual, the EPA states that “Incremental 

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

differences between dominant alternatives. Dominant set of control alternatives are 

determined by generating what is called the envelope of least-cost alternatives. This is a 

graphical plot of total annualized costs for a total emissions reductions for all control 

alternatives identified in the BACT analysis...” 

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

performed in the following way: 

• First, the control option scenarios are ranked in ascending order of annualized total costs 

as shown in Tables 5-1 and 5-2. The incremental cost effectiveness data, expressed per 

day and per dV reduction, represents a comparison of the different scenarios, and is 

summarized in Tables 5-3 and 5-4 for each of the two Class I areas. 

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-1
BART ANALYSIS FOR NAUGHTON UNIT 1 

and cost per reduction in number of days above 0.5 dV) for each of the two Class I areas 

impacted by the operation of Naughton 1. 

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

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

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

options.” In Figure 5-1, the dominant set of control options (Scenarios 1 and 3) represent the 

least-cost envelope depicted by the curvilinear line connecting them. Scenarios 2 and 4 are 

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

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

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

and similarly, Scenario 3 will provide approximately the same amount of visibility impact 

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

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

difference in emissions reduction. 

TABLE 5-1 

Bridger Wilderness Area Class I Agent Control Data 

Naughton 1 

Scenario Controls 

98th

Percentile 

Deciview 

(dV) 

Reduction 

Reduction in 

Average 

Number of 

Days Above 

0.5 dV (Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per dV 

Reduction 

(Million$/dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Above 0.5 dV 

(Million$/Day 

Reduced) 

Base Current Operation with 

Electrostatic Precipitator 

(ESP) 

0.00 0.0 $0.0 $0.0 $0.0 

1 Low-NOx Burner (LNB) with 

Over-fire Air (OFA), Dry Flue 

Gas Conditioning (FGD), 

ESP 

1.09 30.0 $12.0 $11.1 $0.4 

2 LNB with OFA, Dry FGD, 

New Fabric Filter 

1.24 37.0 $15.3 $12.3 $0.4 

3 LNB with OFA and Selective 

Catalytic Reduction (SCR) 

System, Dry FGD, Fabric 

Filter 

1.54 43.0 $21.3 $13.8 $0.5 

4 LNB with OFA and SCR, 

Wet FGD, New stack 

1.42 41.0 $20.4 $14.3 $0.5 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-2
BART ANALYSIS FOR NAUGHTON UNIT 1 

TABLE 5-2 

Fitzpatrick Wilderness Area Class I Area Control Data 

Naughton 1 

Scenario Controls 

98th

Percentile 

Deciview 

(dV) 

Reduction 

Reduction in 

Average 

Number of 

Days Above 

0.5 dV 

 (Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

dV 

Reduction 

(Million$ 

per dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Above 0.5 dV 

(Million$ per 

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 Overfire Air (OFA), Dry 

Flue Gas 

Conditioning 

(FGD), ESP 

0.55 16.0 $12.0 $21.8 $0.8 

2 LNB with OFA, 

Dry FGD, New 

Fabric Filter 

0.66 18.0 $15.3 $23.2 $0.8 

3 LNB with OFA 

and Selective 

Catalytic 

Reduction (SCR) 

System, Dry FGD, 

Fabric Filter 

0.78 20.3 $21.3 $27.3 $1.0 

4 LNB with OFA & 

SCR, Wet FGD, 

New stack 

0.76 19.7 $20.4 $26.7 $1.0 

TABLE 5-3 

Bridger Wilderness Area Class I Agent Incremental Data 

Naughton 1 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 Deciview 

(dV) (Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(Million$ per Day) 

Incremental 

Cost 

Effectiveness 

(Million$ per 

dV) 

Baseline and Scenario 1 30.00 1.09 $0.40 $11.1 

Scenario 1 and Scenario 2 7.0 0.16 $0.5 $20.7 

Scenario 1 and Scenario 3 13.0 0.45 $0.7 $20.4 

Scenario 1 and Scenario 4 11.0 0.34 $0.8 $24.9 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-3
BART ANALYSIS FOR NAUGHTON UNIT 1 

TABLE 5-4 

Fitzpatrick Wilderness Area Class I Area Incremental Data 

Naughton 1 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 Deciview 

(dV) (Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(Million$ per Day) 

Incremental 

Cost 

Effectiveness 

(Million$ per 

dV) 

Baseline and Scenario 1 16.00 0.55 $0.75 $21.8 

Scenario 1 and Scenario 2 2.0 0.11 $1.6 $30.0 

Scenario 1 and Scenario 3 4.3 0.23 $2.1 $40.4 

Scenario 1 and Scenario 4 3.7 0.21 $2.3 $39.4 

FIGURE 5-1 

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

Naughton 1 

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 30 35 40 45 50

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-4
BART ANALYSIS FOR NAUGHTON UNIT 1 

FIGURE 5-2 

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

Naughton 1 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

FIGURE 5-3 

Least-cost Envelope Fitzpatrick Wilderness Area Class I Area Days Reduction 

Naughton 1 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0 5 10 15 20 25

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-5
BART ANALYSIS FOR NAUGHTON UNIT 1 

FIGURE 5-4 

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

Naughton 1 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

5.1.2 Analysis of Results 

Results of the least-cost analysis, shown in Tables 5-1 to 5-4 and Figures 5-1 to 5-4 (on the 

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

visibility improvements. 

The other scenarios were eliminated because of the following reasons: 

• Scenario 2 is to the left of one of the four curves formed by the dominant control 

alternative scenarios; this indicates lower improvement and/or higher costs. 

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

improvement and a cost per dV reduction. 

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

projected improvement is less than 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. 

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

Figures 5-1 and 5-2 illustrates these conclusions. The greatest reduction in 98th percentile 

dV—and number of days above 0.5 dV—is between the Baseline and Scenario 1. For 

example, Table 5-3 shows that the incremental cost effectiveness for Scenario 1 compared to 

the Baseline is reasonable at $400,000 per day and $11.1 million per dV to improve visibility 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-6
BART ANALYSIS FOR NAUGHTON UNIT 1 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-7

at the Bridger WA. However, the incremental cost effectiveness for Scenario 2 compared to 

Scenario 1 is excessive at $500,000 per day and $20.7 million per dV. The incremental cost 

effectiveness for Scenario 3 compared to Scenario 1 is equally excessive at $700,000 per day 

and $20.4 million per dV. Using Table 5-4, a similar conclusion is reached for improving 

visibility at the Fitzpatrick Wilderness Area. Therefore, the EPA’s Least Cost Analysis 

confirms that Scenario 1 represents the proper BART control technology for Naughton 1; 

Scenario 2’s incremental cost effectiveness, compared to Scenario 1, is excessive. 

5.2 Recommendations 

5.2.1 NOx Emission Control 

CH2M HILL recommends LNB with OFA as BART for Naughton 1, 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 LNBs with OFA at Naughton 1 is projected to 

attain an emission rate below 0.26 lb per MMBtu. 

5.2.2 SO2 Emission Control 

CH2M HILL recommends a dry lime FGD system as BART for Naughton 1, 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. 

5.2.3 PM10 Emission Control 

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

existing ESP as BART for Naughton 1, based on the significant reduction in PM10 emissions, 

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

no non-air quality environmental impacts. 

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

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

1.5 to 2.0 dV or more are perceivable by the human eye. Deciview changes of less than 

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

indicate that only minimal, if any, visibility improvements at the Class I areas studied would 

be expected under any of the scenarios. Thus, the results indicate that even though many 

millions of dollars will be spent, only minimal visibility improvements may result. 

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

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

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

natural obscuration were to reduce the visibility impacts modeled for the Naughton 1 facility, 

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

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

Technology Determinations; Final Rule. July 6, 2005. 

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

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

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

and Nonattainment Area Permitting. Draft. October 1990. 

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

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

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

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

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

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

Accessed October 2006. North Dakota Department of Health, 2005. Protocol for 

BART-Related Visibility Improvement Modeling Analysis in North Dakota. North 

Dakota Department of Health. October 26, 2005. 

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

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

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

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

Quality Division. September 2006. 

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 6-1
APPENDIX A 

Economic Analysis 
PacifiCorp BART Analysis Scenarios

7

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 $ 12,042,621 

 N/A N/A $ 12,042,621 

 N/A N/A $ 15,299,091 

 N/A N/A $ 15,299,091 

 N/A N/A $ 21,262,911 

 N/A N/A $ 21,262,911 

 N/A N/A $ 20,399,907 

 N/A N/A $ 20,399,907 

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 1

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

Scenario 4 - LNB wSCR, Wet FGD, ES

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
ECONOMIC ANALYSIS SUMMARY

Naughton Unit 1 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 ($) 0 7,300,000 9,068,746 17,526,855 58,227,447 64,297,623 FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 506,128 Maintenance Material ($) 0 32,000 48,000 83,000 132,000 587,643 Maintenance Labor ($) 0 48,000 72,000 124,500 198,000 391,762 Administrative Labor ($) 0 0 0 0 0 0 TOTAL FIXED O&M COST 0 80,000 120,000 207,500 330,000 1,485,533 Makeup Water Cost 0 0 0 0 0 69,063 Reagent Cost 0 0 0 399,761 281,492 1,870,139 SCR Catalyst / FF Bag Cost 0 0 0 0 201,000 0 Waste Disposal Cost 0 0 0 0 0 878,461 Electric Power Cost 0 0 558,514 63,072 386,710 647,671 TOTAL VARIABLE O&M COST 0 0 558,514 462,833 869,203 3,465,334 

TOTAL FIRST YEAR O&M COST 0 80,000 678,514 670,333 1,199,203 4,950,867 

FIRST YEAR DEBT SERVICE ($) 0 694,433 862,690 1,667,292 5,539,050 6,116,493 TOTAL FIRST YEAR COST ($) 0 774,433 1,541,204 2,337,624 6,738,253 11,067,360 

Power Consumption (MW) 0.0 0.0 1.4 0.2 1.0 1.6 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 11.2 1.3 7.7 13.0 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 58.6% 55.2% 67.2% 87.9% 0.0% 

NOx Removed (Tons/Yr) 0 2,480 2,334 2,844 3,719 0 First Year Average Control Cost ($/Ton NOx Rem.) 0 312 660 822 1,812 0 

Incremental Control Cost ($/Ton NOx Removed) 0 312 660 4,287 3,751 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 12,061 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 918 Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 918 

6-1 

PM Removal Rate (%) 98.63% 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 8,277,429 17,358,735 25,716,881 72,879,129 124,786,587 

NOx Control 

Parameter Current Operation

SO

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
INPUT CALCULATIONS

Naughton Unit 1 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) 160,000 160,000 160,000 160,000 160,000 160,000 160,000 

Net Plant Heat Rate (Btu/kW-Hr) 11,563 11,563 11,563 11,563 11,563 11,563 11,563 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) 1,850 1,850 1,850 1,850 1,850 1,850 1,850 Coal Flow Rate (Lb/Hr) 188,784 188,784 188,784 188,784 188,784 187,350 188,784  (Ton/Yr) 744,185 744,185 744,185 744,185 744,185 738,533 744,185  (MMBtu/Yr) 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,03

Emissions

Uncontrolled SO2 (Lb/Hr) 2,188 2,188 2,188 2,188 2,188 3,818 2,188  (Lb/MMBtu) 1.18 1.18 1.18 1.18 1.18 2.06 1.18  (Lb Moles/Hr) 34.15 34.15 34.15 34.15 34.15 59.60 34.15  (Tons/Yr) 8,624 8,624 8,624 8,624 8,624 15,051 8,624 SO2 Removal Rate (%) 0.0% 0.0% 0.0% 0.0% 0.0% 80.1% 87.3%  (Lb/Hr) 0 0 0 0 0 3,060 1,910  (Ton/Yr) 0 0 0 0 0 12,061 7,530 SO2 Emission Rate (Lb/Hr) 2,188 2,188 2,188 2,188 2,188 759 278  (Lb/MMBtu) 1.18 1.18 1.18 1.18 1.18 0.41 0.15 

 (Ton/Yr) 8,624 8,624 8,624 8,624 8,624 2,990 1,094 Uncontrolled NOx (Lb/Hr) 1,073 1,073 1,073 1,073 1,073 1,073 1,073  (Lb/MMBtu) 0.58 0.58 0.58 0.58 0.58 0.58 0.58 

 (Lb Moles/Hr) 35.76 35.76 35.76 35.76 35.76 35.76 35.76  (Tons/Yr) 4,230 4,230 4,230 4,230 4,230 4,230 4,230 NOx Removal Rate (%) 0.0% 58.6% 55.2% 67.2% 87.9% 0.0% 0.0% 

 (Lb/Hr) 0 629 592 722 944 0 0  (Lb Moles/Hr) 0.00 20.96 19.73 24.04 31.44 0.00 0.00  (Ton/Yr) 0 2,480 2,334 2,844 3,719 0 0 NOx Emission Rate (Lb/Hr) 1,073 444 481 352 130 1,073 1,073  (Lb/MMBtu) 0.58 0.24 0.26 0.19 0.07 0.58 0.58 

 (Ton/Yr) 4,230 1,750 1,896 1,386 511 4,230 4,230 Uncontrolled Fly Ash (Lb/Hr) 7,551 104 104 104 104 104 104  (Lb/MMBtu) 4.082 0.056 0.056 0.056 0.056 0.056 0.056  (Lb Moles/Hr) 251.6 3.5 3.5 3.5 3.5 3.5 3.5  (Tons/Yr) 29,767 408 408 408 408 408 408 Fly Ash Removal Rate (%) 98.63% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 7,448 0 0 0 0 0 0  (Ton/Yr) 29,359 0 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 104 104 104 104 104 104 104  (Lb/MMBtu) 0.056 0.056 0.056 0.056 0.056 0.056 0.056 

 (Ton/Yr) 408 408 408 408 408 408 408 

Parameter 

Current Operation NOx Control SO2 Contr

EY102007001SLC\PCorp Naughton 1 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 7,300,000 9,068,746 17,526,855 58,227,447 0 0 

SO2 Emission Control System ($2006) 0 0 0 0 0 64,297,623 108,995,9

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

Total Emission Control Systems ($2006) 0 7,300,000 9,068,746 17,526,855 58,227,447 64,297,623 108,995,9

NOx Emission Control System ($/kW) 0 46 57 110 364 0 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 402 681 PM Emission Control System ($/kW) 0 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 46 57 110 364 402 681 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 0 0 0 0 0 506,128 506,128 Maintenance Material ($) 0 32,000 48,000 83,000 132,000 587,643 632,660 Maintenance Labor ($) 0 48,000 72,000 124,500 198,000 391,762 459,286 Administrative Labor ($) 00000 0 0 

Total Fixed O&M Cost ($) 0 80,000 120,000 207,500 330,000 1,485,533 1,598,07

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 0 120 120 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 69,063 69,063 

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 0.45 1.00 1.40 1.15 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 90% 90% 

Reagent Usage (Lb/Hr) 0 0 0 274 179 5,199 2,447 

First Year Reagent Cost ($) 0 0 0 399,761 281,492 1,870,139 880,203 

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 67 0 865 

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 0 201,000 0 89,960 

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 9,158 4,919 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 0 878,461 471,814 

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% 0.89% 0.10% 0.61% 1.03% 1.66%  (MW) 0.00 0.00 1.42 0.16 0.98 1.64 2.66 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 0 558,514 63,072 386,710 647,671 1,046,99

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

EY102007001SLC\PCorp Naughton 1 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\[File] 
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\[File] 
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\[File] 
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\[File] 
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\[File] 
CAPITAL COST

Naughton Unit 1

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 $2,502,123 Vendor $2,675,792 Vendor $2,502,123 Vendor $2,502,123 Vendor $0 Vendor 

Construction 85.3% $2,135,156 85.3% $2,283,354 85.3% $2,135,156 85.3% $2,135,156 85.3% $0 85.3% 

Balance of Plant 51.7% $1,293,401 51.7% $1,383,174 51.7% $1,293,401 51.7% $1,293,401 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $802,738 0.0% $0 0.0% $0 0.0% $0 0.0% Owner's Costs 13.2% $331,490 13.2% $354,498 13.2% $331,490 13.2% $331,490 13.2% $0 13.2% Surcharge 16.4% $410,986 16.4% $439,512 16.4% $410,986 16.4% $410,986 16.4% $0 16.4% AFUDC 12.2% $305,721 12.2% $326,941 12.2% $305,721 12.2% $305,721 12.2% $0 12.2% Subtotal $6,978,877 $8,266,008 $6,978,877 $6,978,877 $0 Contingency 12.8% $321,124 30.0% $802,738 12.8% $321,124 12.8% $321,124 12.8% $0 12.8% Total Capital Cost for LNB w/OFA or ROFA $7,300,000 $9,068,746 $7,300,000 $7,300,000 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $7,257,000 S&L Report $37,292,000 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $1,451,400 10.0% $3,729,200 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $405,884 5.6% $2,085,742 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $3,150,055 8.4% $0 8.4% Boiler Reinforcement (Allowance) 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% Sales Tax 1.1% $0 1.1% $0 1.1% $79,972 1.1% $410,958 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% $203,704 0.0% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $828,895 11.4% $4,259,492 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $10,226,855 $50,927,447 $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 $39,617,991 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% $7,923,598 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% $2,215,834 5.6% 

EPC Premium 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% $3,346,532 8.4% 

Boiler Reinforcement (Allowance) 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,114,850 2.8% 

Sales Tax 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% $436,590 1.1% 

Escalation 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% $4,004,983 10.1% 

Contingency on Adders 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $1,112,077 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% $4,525,167 11.4% 

Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $64,297,623 

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\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
Naughton Unit 1 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) 11.8% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Naughton Unit 1 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 - - - - 558,514 558,514 

 

2 2015 122,400 - - - - 569,685 569,685 

 

3 2016 124,848 - - - - 581,078 581,078 

 

4 2017 127,345 - - - - 592,700 592,700 

 

5 2018 129,892 - - - - 604,554 604,554 

 

6 2019 132,490 - - - - 616,645 616,645 

 

7 2020 135,139 - - - - 628,978 628,978 

 

8 2021 137,842 - - - - 641,557 641,557 

 

9 2022 140,599 - - - - 654,389 654,389 

 

10 2023 143,411 - - - - 667,476 667,476 

 

11 2024 146,279 - - - - 680,826 680,826 

 

12 2025 149,205 - - - - 694,442 694,442 

 

13 2026 152,189 - - - - 708,331 708,331 

 

14 2027 155,233 - - - - 722,498 722,498 

 

15 2028 158,337 - - - - 736,948 736,948 

 

16 2029 161,504 - - - - 751,687 751,687 

 

17 2030 164,734 - - - - 766,721 766,721 

 

18 2031 168,029 - - - - 782,055 782,055 

 

19 2032 171,390 - - - - 797,696 797,696 

 

20 2033 174,817 - - - - 813,650 813,650 

 

Present Worth - 1,466,142 - - - 6,823,847 6,823,847 

 

(% of PW) 8.4% 0.0% 0.0% 0.0% 0.0% 39.3% 39.3% 

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
Naughton Unit 1 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 207,500 - 399,761 - - 63,072 462,833 

 

2 2015 211,650 - 407,756 - - 64,333 472,089 

 

3 2016 215,883 - 415,911 - - 65,620 481,531 

 

4 2017 220,201 - 424,229 - - 66,933 491,162 

 

5 2018 224,605 - 432,714 - - 68,271 500,985 

 

6 2019 229,097 - 441,368 - - 69,637 511,005 

 

7 2020 233,679 - 450,195 - - 71,029 521,225 

 

8 2021 238,352 - 459,199 - - 72,450 531,649 

 

9 2022 243,119 - 468,383 - - 73,899 542,282 

 

10 2023 247,982 - 477,751 - - 75,377 553,128 

 

11 2024 252,941 - 487,306 - - 76,884 564,190 

 

12 2025 258,000 - 497,052 - - 78,422 575,474 

 

13 2026 263,160 - 506,993 - - 79,991 586,984 

 

14 2027 268,423 - 517,133 - - 81,590 598,723 

 

15 2028 273,792 - 527,476 - - 83,222 610,698 

 

16 2029 279,268 - 538,025 - - 84,887 622,912 

 

17 2030 284,853 - 548,786 - - 86,584 635,370 

 

18 2031 290,550 - 559,761 - - 88,316 648,077 

 

19 2032 296,361 - 570,957 - - 90,082 661,039 

 

20 2033 302,288 - 582,376 - - 91,884 674,260 

 

Present Worth - 2,535,205 4,884,217 - - 770,604 5,654,821 1

 

(% of PW) 9.9% 0.0% 19.0% 0.0% 0.0% 3.0% 22.0% 

Naughton Unit 1 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 330,000 - 281,492 201,000 - 386,710 869,203 

 

2 2015 336,600 - 287,122 205,020 - 394,444 886,587 

 

3 2016 343,332 - 292,865 209,120 - 402,333 904,318 

 

4 2017 350,199 - 298,722 213,303 - 410,380 922,405 

 

5 2018 357,203 - 304,696 217,569 - 418,588 940,853 

 

6 2019 364,347 - 310,790 221,920 - 426,959 959,670 

 

7 2020 371,634 - 317,006 226,359 - 435,498 978,863 

 

8 2021 379,066 - 323,346 230,886 - 444,208 998,441 

 

9 2022 386,648 - 329,813 235,504 - 453,093 1,018,409 

 

10 2023 394,381 - 336,409 240,214 - 462,154 1,038,778 

 

11 2024 402,268 - 343,138 245,018 - 471,398 1,059,553 

 

12 2025 410,314 - 350,000 249,918 - 480,826 1,080,744 

 

13 2026 418,520 - 357,000 254,917 - 490,442 1,102,359 

 

14 2027 426,890 - 364,140 260,015 - 500,251 1,124,406 

 

15 2028 435,428 - 371,423 265,215 - 510,256 1,146,894 

 

16 2029 444,137 - 378,852 270,520 - 520,461 1,169,832 

 

17 2030 453,019 - 386,429 275,930 - 530,870 1,193,229 

 

18 2031 462,080 - 394,157 281,449 - 541,488 1,217,093 

 

19 2032 471,321 - 402,040 287,077 - 552,317 1,241,435 

 

20 2033 480,748 - 410,081 292,819 - 563,364 1,266,264 

 

Present Worth - 4,031,892 3,439,233 2,455,789 - 4,724,768 10,619,790 5

 

(% of PW) 5.5% 0.0% 4.7% 3.4% 0.0% 6.5% 14.6% 

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
Naughton Unit 1 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 1,485,533 69,063 1,870,139 - 878,461 647,671 3,465,334 

 

2 2015 1,515,244 70,444 1,907,542 - 896,030 660,624 3,534,640 

 

3 2016 1,545,549 71,853 1,945,693 - 913,950 673,836 3,605,333 

 

4 2017 1,576,460 73,290 1,984,607 - 932,229 687,313 3,677,440 

 

5 2018 1,607,989 74,756 2,024,299 - 950,874 701,059 3,750,989 

 

6 2019 1,640,149 76,251 2,064,785 - 969,891 715,081 3,826,008 

 

7 2020 1,672,952 77,776 2,106,081 - 989,289 729,382 3,902,528 

 

8 2021 1,706,411 79,332 2,148,202 - 1,009,075 743,970 3,980,579 

 

9 2022 1,740,539 80,918 2,191,166 - 1,029,257 758,849 4,060,191 

 

10 2023 1,775,350 82,537 2,234,990 - 1,049,842 774,026 4,141,394 

 

11 2024 1,810,857 84,187 2,279,690 - 1,070,838 789,507 4,224,222 

 

12 2025 1,847,074 85,871 2,325,283 - 1,092,255 805,297 4,308,707 

 

13 2026 1,884,015 87,589 2,371,789 - 1,114,100 821,403 4,394,881 

 

14 2027 1,921,696 89,340 2,419,225 - 1,136,382 837,831 4,482,779 

 

15 2028 1,960,130 91,127 2,467,609 - 1,159,110 854,588 4,572,434 

 

16 2029 1,999,332 92,950 2,516,961 - 1,182,292 871,679 4,663,883 

 

17 2030 2,039,319 94,809 2,567,301 - 1,205,938 889,113 4,757,160 

 

18 2031 2,080,105 96,705 2,618,647 - 1,230,057 906,895 4,852,304 

 

19 2032 2,121,707 98,639 2,671,020 - 1,254,658 925,033 4,949,350 

 

20 2033 2,164,141 100,612 2,724,440 - 1,279,751 943,534 5,048,337 

 

Present Worth 843,802 18,150,027 22,849,089 - 10,732,902 7,913,144 42,338,938 6

 

(% of PW) 14.5% 0.7% 18.3% 0.0% 8.6% 6.3% 33.9% 

Naughton Unit 1 Dry FGD w/Fabric Filte

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

0 20131 2014 1,598,074 69,063 880,203 89,960 471,814 1,046,995 2,558,035 1

 

2 2015 1,630,035 70,444 897,807 91,759 481,250 1,067,935 2,609,196 1

 

3 2016 1,662,636 71,853 915,763 93,594 490,875 1,089,294 2,661,380 1

 

4 2017 1,695,888 73,290 934,078 95,466 500,693 1,111,080 2,714,607 1

 

5 2018 1,729,806 74,756 952,760 97,376 510,707 1,133,301 2,768,899 1

 

6 2019 1,764,402 76,251 971,815 99,323 520,921 1,155,967 2,824,277 1

 

7 2020 1,799,690 77,776 991,251 101,310 531,339 1,179,087 2,880,763 1

 

8 2021 1,835,684 79,332 1,011,076 103,336 541,966 1,202,668 2,938,378 1

 

9 2022 1,872,398 80,918 1,031,298 105,402 552,805 1,226,722 2,997,146 1

 

10 2023 1,909,846 82,537 1,051,924 107,511 563,861 1,251,256 3,057,089 1

 

11 2024 1,948,043 84,187 1,072,962 109,661 575,139 1,276,281 3,118,230 1

 

12 2025 1,987,004 85,871 1,094,421 111,854 586,641 1,301,807 3,180,595 1

 

13 2026 2,026,744 87,589 1,116,310 114,091 598,374 1,327,843 3,244,207 1

 

14 2027 2,067,279 89,340 1,138,636 116,373 610,342 1,354,400 3,309,091 1

 

15 2028 2,108,624 91,127 1,161,409 118,700 622,549 1,381,488 3,375,273 1

 

16 2029 2,150,797 92,950 1,184,637 121,074 635,000 1,409,118 3,442,778 1

 

17 2030 2,193,813 94,809 1,208,330 123,496 647,700 1,437,300 3,511,634 1

 

18 2031 2,237,689 96,705 1,232,496 125,966 660,654 1,466,046 3,581,866 1

 

19 2032 2,282,443 98,639 1,257,146 128,485 673,867 1,495,367 3,653,504 1

 

20 2033 2,328,091 100,612 1,282,289 131,055 687,344 1,525,274 3,726,574 1

 

Present Worth 843,802 19,525,029 10,754,186 1,099,118 5,764,555 12,792,034 31,253,695 10

 

(% of PW) 12.2% 0.5% 6.7% 0.7% 3.6% 8.0% 19.6% 

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
Naughton Unit 1 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 2,415,786 92,084 735,700 - 548,278 946,080 2,322,141 

 

2 2015 2,464,102 93,926 750,414 - 559,243 965,002 2,368,584 

 

3 2016 2,513,384 95,804 765,422 - 570,428 984,302 2,415,956 

 

4 2017 2,563,651 97,720 780,730 - 581,836 1,003,988 2,464,275 

 

5 2018 2,614,924 99,675 796,345 - 593,473 1,024,067 2,513,560 

 

6 2019 2,667,223 101,668 812,272 - 605,343 1,044,549 2,563,832 

 

7 2020 2,720,567 103,702 828,517 - 617,450 1,065,440 2,615,108 

 

8 2021 2,774,979 105,776 845,088 - 629,799 1,086,749 2,667,410 

 

9 2022 2,830,478 107,891 861,989 - 642,394 1,108,484 2,720,759 

 

10 2023 2,887,088 110,049 879,229 - 655,242 1,130,653 2,775,174 

 

11 2024 2,944,830 112,250 896,814 - 668,347 1,153,266 2,830,677 

 

12 2025 3,003,726 114,495 914,750 - 681,714 1,176,332 2,887,291 

 

13 2026 3,063,801 116,785 933,045 - 695,348 1,199,858 2,945,037 

 

14 2027 3,125,077 119,121 951,706 - 709,255 1,223,855 3,003,937 

 

15 2028 3,187,578 121,503 970,740 - 723,441 1,248,332 3,064,016 

 

16 2029 3,251,330 123,933 990,155 - 737,909 1,273,299 3,125,296 

 

17 2030 3,316,356 126,412 1,009,958 - 752,668 1,298,765 3,187,802 

 

18 2031 3,382,684 128,940 1,030,157 - 767,721 1,324,740 3,251,558 

 

19 2032 3,450,337 131,519 1,050,760 - 783,075 1,351,235 3,316,590 

 

20 2033 3,519,344 134,149 1,071,776 - 798,737 1,378,260 3,382,921 

 

Present Worth 1,125,070 29,515,719 8,988,671 - 6,698,774 11,559,067 28,371,582 9

 

(% of PW) 19.7% 0.8% 6.0% 0.0% 4.5% 7.7% 19.0% 

Naughton Unit 1 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 - 47,609 - - 19,710 67,319 

 

2 2015 10,200 - 48,561 - - 20,104 68,665 

 

3 2016 10,404 - 49,532 - - 20,506 70,039 

 

4 2017 10,612 - 50,523 - - 20,916 71,439 

 

5 2018 10,824 - 51,533 - - 21,335 72,868 

 

6 2019 11,041 - 52,564 - - 21,761 74,326 

 

7 2020 11,262 - 53,615 - - 22,197 75,812 

 

8 2021 11,487 - 54,688 - - 22,641 77,328 

 

9 2022 11,717 - 55,781 - - 23,093 78,875 

 

10 2023 11,951 - 56,897 - - 23,555 80,452 

 

11 2024 12,190 - 58,035 - - 24,026 82,061 

 

12 2025 12,434 - 59,196 - - 24,507 83,703 

 

13 2026 12,682 - 60,380 - - 24,997 85,377 

 

14 2027 12,936 - 61,587 - - 25,497 87,084 

 

15 2028 13,195 - 62,819 - - 26,007 88,826 

 

16 2029 13,459 - 64,075 - - 26,527 90,602 

 

17 2030 13,728 - 65,357 - - 27,058 92,414 

 

18 2031 14,002 - 66,664 - - 27,599 94,263 

 

19 2032 14,282 - 67,997 - - 28,151 96,148 

 

20 2033 14,568 - 69,357 - - 28,714 98,071 

 

Present Worth - 122,179 581,679 - - 240,814 822,493 

 

(% of PW) 5.4% 0.0% 25.9% 0.0% 0.0% 10.7% 36.7% 

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
Naughton Unit 1 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 - - 89,960 - 399,325 489,285 

 

2 2015 114,791 - - 91,759 - 407,311 499,070 

 

3 2016 117,087 - - 93,594 - 415,457 509,052 

 

4 2017 119,429 - - 95,466 - 423,766 519,233 

 

5 2018 121,817 - - 97,376 - 432,242 529,617 

 

6 2019 124,254 - - 99,323 - 440,887 540,210 

 

7 2020 126,739 - - 101,310 - 449,704 551,014 

 

8 2021 129,274 - - 103,336 - 458,698 562,034 

 

9 2022 131,859 - - 105,402 - 467,872 573,275 

 

10 2023 134,496 - - 107,511 - 477,230 584,740 

 

11 2024 137,186 - - 109,661 - 486,774 596,435 

 

12 2025 139,930 - - 111,854 - 496,510 608,364 

 

13 2026 142,728 - - 114,091 - 506,440 620,531 

 

14 2027 145,583 - - 116,373 - 516,569 632,942 

 

15 2028 148,495 - - 118,700 - 526,900 645,601 

 

16 2029 151,465 - - 121,074 - 537,438 658,513 

 

17 2030 154,494 - - 123,496 - 548,187 671,683 

 

18 2031 157,584 - - 125,966 - 559,151 685,117 

 

19 2032 160,735 - - 128,485 - 570,334 698,819 

 

20 2033 163,950 - - 131,055 - 581,741 712,795 

 

Present Worth - 1,375,002 - 1,099,118 - 4,878,889 5,978,007 2

 

(% of PW) 3.7% 0.0% 0.0% 3.0% 0.0% 13.1% 16.1% 

EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 
EY102007001SLC\PCorp Naughton 1 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

10,000,00012,000,00014,000,00016,000,000

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\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 

Present Worth Cost for Air Pollution Control Options

0

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

100,000,000120,000,000140,000,000160,000,000180,000,000

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