# Final Report



# BART Analysis for

Naughton Unit 3

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Naughton Unit 3

Submitted to



# PacifiCorp

December 2007

# Executive Summary

Background

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

regulations and guidelines, CH 2M HILL was requested to perform a BART analysis for

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

been conducted for the following criteria pollutants: ni trogen oxides (NO

x 

# ), sulfur dioxide

(SO 2 

# ), and particulate matter less than 10 mi crometers in aerodynamic diameter (PM 10 

# ). The

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

(MW). Presumptive BART limits therefore do no t directly apply to Naughton 3, based on the

United States Environmental Protection Agen cy’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 emi ssions limits must be achieved

within five years after the State Implementati on Plan (SIP) is approved by the EPA, and a

compliance date of 2014 was assumed for this analysis.

In completing the BART analysis, technology a lternatives were inve stigated a nd potential

reductions in NO

x 

# , SO 2 

# , and PM 10 

# emissions rates were identified. The following technology

alternatives were investigat ed, listed below by pollutant:

• NO

x 

# emission controls:

− Tune existing Low-NO

x 

# burners (LNBs) with over-fire air (OFA)

− Rotating opposed fire air (ROFA)

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

− LNBs with OFA and selective catal ytic reduction (SCR) system

• SO 2 

# emission controls:

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

− Upgrade wet sodium FGD system and use soda ash reagent

• PM 10 

# emission controls:

− Enhancements to existing electrostatic precipitator (ESP)

− Polishing fabric filter

− Replacement fabric filter

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR NAUGHTON UNIT 3



# BART Engineering Analysis

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

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

• The identification of available, techni cally feasible, retr ofit 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 envi ronmental impacts of compliance

• The degree of visibility improvement that ma y 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, techni cally feasible, retr ofit control options

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

the applicability of optio ns and their impacts)

• Step 3 – Evaluate Control Effectiven ess 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 envi ronmental 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 NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included

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

2014 BART implementation date.



# Coal Characteristics

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

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

characteristics to bituminous coal in many of the parameters influencing NO

x 

# formation.

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR NAUGHTON UNIT 3



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

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

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

qualities on NO

x 

# formation and achievable emission rates.



# Recommendations

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

low-NO

x 

# burners with over-fire air (LNB with OFA) for NO

x 

# , upgrading the wet waste

sodium liquor FGD system for SO 2 

# , and enhancements to the existing ESP for PM 10 

# . This

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



# NO

x 

# Emission Control

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

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

coals.

CH2M HILL recommends tuning the existing low-NO

x 

# burners with over-f ire air (LNB with

OFA) as BART for Naughton 3, based on the projected NO

x 

# emissions, reasonable control

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

environmental impacts.



# SO 2 

# Emission Control

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

Naughton 3, based on the significant reduction in SO 2 

# emissions, reasonable control costs,

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

impacts.



# PM 10



# Emission Control

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

based on the significant reduction in PM 10 

# emissions, reasonable control costs, as well as the

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

impacts.



# BART Modeling Analysis

CH2M HILL used the CALPUFF modeling syst em to assess the visibility impacts of

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

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

The Class I areas include the fo llowing wilderness areas (WAs):

• Bridger WA

• Fitzpatrick WA

Because Naughton 3 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four

post-control atmospheric dispersi on modeling scenarios were deve loped to cover the range of

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR NAUGHTON UNIT 3



# effectiveness for combining the individual NO

x 

# , SO 2 

# and PM 10 

# control technologies under

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

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

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

recommendation.

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

ESP.

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

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

new fabric filter.

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

were compared utilizing a Least-co st Envelope, as outlined in the New Source Review

Workshop Manual

. 1



# Least-cost Envelope Analysis

EPA has adopted the Least-cost Envelope Analysis Methodology as an accepted

methodology for selecting the most reasonabl e, cost-effective c ontrols. Incremental

cost-effectiveness comparisons focus on annuali zed cost and emission reduction differences

between dominant alternatives. The dominant se t of control alternatives is determined by

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

total annualized costs for total emissions reduction s for all control altern atives identified in

the BART analysis.

To evaluate the impacts of the modeled contro l scenarios on the three Class I areas, the total

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

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

costs between relevant scenario s for the three Class I areas; the total annua lized cost versus

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

# percentile

delta-deciview ( Δ dV) reduction.

Results of the Least-cost Envelope Analysis validate the selection of Scenario 1, based on

incremental cost and visibility improvements. The other scenarios were eliminated for the

following reasons:

• Scenario 2 (LNB with OFA, upgrade waste liquor FGD, and fabric filter) is to the left of

the curve formed by the “dominant” contro l alternative scenario, which indicates a

scenario with lower improvement and/or higher costs.

• Scenario 3 (LNB with OFA and SCR, upgrad e waste liquor FGD, and enhance ESP) has

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

per dV reduction.

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC ES-5 

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

new fabric filter) provides some potential visibility advantage over Scenario 1, the

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

Therefore, Scenario 1 represents BART for Naughton 3.



# Just-Noticeable Differences in Atmospheric Haze

Studies have been conducted th at demonstrate only dV differe nces of approximately 1.5 to

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

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

only minimal, if any, observable visibility im provements at the Class I areas studied would

be expected under any of the c ontrol scenarios. Thus, the resu lts indicate that only minimal

discernable visibility improvements may resu lt, even though PacifiCorp will be spending

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

entire fleet of coal-fired power plants.

# Contents

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

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

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

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

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

3.2.1 BART NO

x 

# Analysis .................................................................... 3-2

3.2.2 BART SO 2 

# Analysis .................................................................. 3-14

3.2.3 BART PM 10 

# Analysis ................................................................ 3-17

4.0 BART Modeling Analysis .................................................................................. 4-1

4.1 Model Selection ....................................................................................... 4-1

4.2 CALMET Methodology ........................................................................... 4-1

4.2.1 Dimensions of the Modeling Domain .......................................... 4-1

4.2.2 CALMET Input Data ................................................................... 4-3

4.2.3 Validation of CALMET Wind Field ............................................ 4-6

4.3 CALPUFF Modeling Approach ............................................................... 4-6

4.3.1 Background Ozone and Ammonia ............................................... 4-6

4.3.2 Stack Parameters .......................................................................... 4-6

4.3.3 Emission Rates ............................................................................. 4-6

4.3.4 Post-control Scenarios ................................................................. 4-7

4.3.5 Modeling Process ......................................................................... 4-9

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

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

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

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

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

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

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

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

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

5.2.1 NO

x 

# Emission Control ................................................................. 5-7

5.2.2 SO 2 

# Emission Control .................................................................. 5-7

5.2.3 PM 10 

# Emission Control ................................................................ 5-7

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

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

\\SNOWBIRD\PROJ\PACIFICORP\348295BART\OCT 2007 REVISIONS\NAUGHTON3_OCT2007_FINAL.DOC 

# iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC iv 

# Tables

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 Coal Source and Characteristics

3-2 NO

x 

# Control Technology Emission Rates

3-3 NO

x 

# Control Cost Comparison

3-4 SO 2 

# Control Cost Comparison (Increm ental to Existing FGD System)

3-5 PM 10 

# Control Technology Emission Rate Ranking

3-6 PM 10 

# Control Cost Comparison

4-1 User-specified CALMET Options

4-2 BART Model Input Data

4-3 Average Natural Levels of Aerosol Components

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

Class I Areas

5-1 Bridger WA Class I Agent Control Data

5-2 Fitzpatrick WA Class I Area Control Data

5-3 Bridger WA Class I Agent Incremental Data

5-4 Fitzpatrick WA Class I Area Incremental Data

Figures

3-1 Illustration of the Effect of Agglomer ation on the Speed of Coal Combustion

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

BART NO

x 

# Limits

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

NO

x 

# Limits

3-4 First Year Control Cost for NO

x 

# Air Pollution Control Options

3-5 First Year Control Cost for SO 2 

# Air Pollution Control Options

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

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

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

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

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

# Percentile

5-3 Least-cost Envelope Fitzpatr ick WA Class I Area Reduction

5-4 Least-cost Envelope Fitzpa trick WA Class I Area 98 th 

# Percentile

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

$/Ton Dollars per Ton

BACT Best Availabl e Control Technology

BART Best Availabl e Retrofit Technology

CALDESK Program to Display Data and Results

CALMET Meteorological data pr eprocessing program for CALPUFF

CALPOST Post-processing Program fo r Calculating Visibility Impacts

CALPUFF Gaussian Puff Dispersion Model

CFR Code of Federal Regulations

COHPAC Compact Hybrid Particulate Collector

dV Deciview

Δ dV 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-NO

x 

# burner

MMBtu Million British thermal units

MM5 Mesoscale Meteorologi cal Model, Version 5

MW Megawatt

NO

x 

# Nitrogen Oxides

NH 4 

# )HSO 4 

# Ammonium bisulfate

(NH 4 

# ) 2 

# SO 4 

# Ammonium sulfate

OFA Over-fire Air

P&M P&M Kemmerer Mine

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC vi 

# PM 2.5 

# Particulate Matter less than 2.5 Mi crometers in Aerodynamic Diameter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Sargent & Lundy

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

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction

SO 2 

# Sulfur Dioxide

SO 3 

# 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 Envir onmental Quality – Air Quality Division

# 1.0 Introduction

Best Available Retrofit Technol ogy (BART) guidelines were esta blished as a result of United

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

occurrence of regional haze in na tional parks and other Class I pr otected air quality areas in

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

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

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

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

The Wyoming Department of Environmental Qu ality (WDEQ) BART re gulations state that

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

December 15, 2006. PacifiCorp received an exte nsion from the Wyoming DEQ to submit the

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

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

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

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

February 2007 version.

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

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

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

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

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

5 years of EPA’s approval of the SIP.

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

• The cost of the controls

• The energy and non-air quality envi ronmental impacts of compliance

• Any existing pollution control tech nology 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 analys is that was performed on Naughton 3 by

CH2M HILL for PacifiCorp. The analysis was performed for the pollutants: nitrogen oxide

(NO

x 

# ), sulfur dioxide (SO 2 

# ), and particulate matter less th an 10 micrometers in aerodynamic

diameter (PM 10 

# ), because they are the primary criteri a pollutants that affect visibility.

Section 2 of this report provi des a description of the pres ent 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 methodol ogy and results of the BART

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

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

Wyoming BART Protocol.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 1-1

# 2.0 Present Unit Operation

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

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

Engineering (now Alstom). Alstom LCCFS II low-NO

x 

# burners (LNBs) were installed in

1999. Particulate emissions are co llected by a Buell weighted wi re electrostatic precipitator

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

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

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

however, this analysis is based on a 20-year life for BART control t echnologies. Assuming a

BART implementation date of 2014, this will re sult in an approximate remaining useful life

for Naughton 3 of 20 years from the installation date of any new or modified BART-related

equipment. This report does not attempt to quantify any additional life extension costs

needed to allow the unit at Naughton 3 to operate until 2033.

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

Coal sources and characteristic s are summarized in Table 2-2.

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

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

of the parameters influencing NO

x 

# formation. This coal has higher nitrogen content than

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

use in the U.S.

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

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

these qualities on NO

x 

# formation. Coal sources and char acteristics 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 th e modeling analysis.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 2-2 

# TABLE 2-1



# Present Unit Operation

Naughton 3

General Plant Data

Site Elevation (feet above mean sea level) 6939

Stack Height (feet) 475

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

Stack Exit Temperature °F (degrees Fahrenheit) 120

Stack Exit Velocity (feet per second) 43

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

Latitude (degree: minut e: second) 41:45:31.91

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

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 330

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

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

(100% load) 3,700

Type of Boiler Tangentially Fired

Boiler Fuel Coal

Coal Sources P&M Kemmerer Mine

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

# 9,950

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

# 1.45

Coal Ash Content (wt. %) (a) 

# 5.50

Coal Moisture Content (wt. %) (a) 

# 21.0

Coal Nitrogen Content (wt. %) (a) 

# 1.3

Current Nitrogen Oxide (NO

x 

# ) Controls Low-NO

x 

# Burners

Pre-project NO

x 

# Emission Rate (lb per MMBtu) 0.45

Current Sulfur Dioxide (SO 2 

# ) Controls Wet Scrubber

Pre-project SO 2 

# Emission Rate (lb per MMBtu) 0.50

Current PM 10 

# Controls ESP

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

# 0.094

(a) 

# Coal characteristics vary between coal sources

(b) 

# Emission rates stated from test resultsBART ANALYSIS FOR NAUGHTON UNIT 3TABLE 2-2Coal Sources and CharacteristicsNaughton 3Ultimate Analysis (% dry basis)MinesMoisture(%)Ash(%)VolatileMatter(%)FixedCarbon(%)Britishthermalunitsperpound(Btu/lb)Sulfur(%)HydrogenCarbonSulfurNitrogenOxygenAshLow Sulfur P&M Kemmerer Mine (P&M)Average20.904.4933.4641.1799700.595.0671.670.731.3315.355.86Standard Deviation *0.971.110.571.183030.050.191.430.060.160.971.04High Sulfur P&M MineAverage20.265.5033.7740.4899651.295.0270.871.681.2214.576.64Standard Deviation *0.841.410.501.442320.290.201.340.330.170.921.08NOTES:* Statistics are based on daily delivered samples except for ultimate analysis, which is based on weekly composites of daily samplesJMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC2-3

# 3.0 BART Engineering Analysis

This section presents the requi red 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 engineer ing analysis are identified in the Code of Federal

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

• The identification of available, techni cally feasible, retr ofit 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 envi ronmental impacts of compliance

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

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Availabl e Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

− The identification of available, techni cally feasible, retr ofit control options

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

the applicability of optio ns and their impacts)

• Step 3 – Evaluate Control Effectiven ess 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 envi ronmental impacts of compliance

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR NAUGHTON UNIT 3



# • Step 5 – Evaluate Visibility Impacts

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

of BART

In order to minimize costs in the BART anal ysis, consideration was made of any pollution

control equipment in use at the source, the co sts of compliance associated with the control

options, and the energy and non-air quality envi ronmental impacts of compliance using these

existing control devices. In some cases, enha ncing the performance of the existing control

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

developed.

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

implementation date).



# 3.2.1 BART NO

x 

# Analysis

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

number of variables, including operati ng conditions, equipment design, and coal

characteristics.

Formation of NO

x



# During coal combustion, NO

x 

# is formed in three different ways. The dominant source of NO

x 

# formation is the oxidation of fuel-bound nitrogen (fuel NO

x 

# ). During combustion, part of the

fuel-bound nitrogen is released from the coal with the volatile ma tter, 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 di oxide) and partially reduced to molecular

nitrogen. A smaller part of NO

x 

# formation is due to high temp erature fixation of atmospheric

nitrogen in the combustion air. A very small amount of NO

x 

# is called prompt NO

x 

# . Prompt

NO

x 

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

In a conventional pulverized co al burner, air is introduced wi th turbulence to promote good

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

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

NO

x 

# .

Coal characteristics directly and significantly affect NO

x 

# 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-bitumi nous to bituminous and on to anthracite. Lower

rank coals, such as the sub-bituminous coals from the PRB, produce lower NO

x 

# emissions

than higher rank bituminous coals, due to their higher reactivity and lower nitrogen content.

The fixed carbon to volatile matter ratio (fuel ratio), coal oxygen c ontent, and rank are good

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

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

with low-NO

x 

# burners, sub-bituminous coals create a l onger time for the kinetics to promote

more stable molecular nitroge n, and hence result in lower NO

x 

# emissions.

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

and low-NO

x 

# production characteristics described above. Based on data from the Energy

Information Administration, PRB coals cu rrently represent 88 percent of total

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR NAUGHTON UNIT 3



# U.S. sub-bituminous production and 73 per cent of western coal production (Energy

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

infer PRB origin and characteristics. Emissions standards differentiating between bituminous

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

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

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

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

including most of the low NO

x 

# forming characteristics. Coal s from P&M Kemmerer Mine

(P&M) fall into this category.

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

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

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

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

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

semi-liquid state when heated, it reflects a chan ge in surface area of th e particle. Thus, with

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

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

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

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

assists in making sub-bituminous coal s more amenable to controlling NO

x 

# 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 c onsidered non-agglomerating—they either do not exhibit those

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

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

control NO

x 

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR NAUGHTON UNIT 3



# FIGURE 3-1



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

Naughton 3



# Table 3-1 shows key NO

x 

# forming characteristics of a t ypical PRB coal compared to low

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

representative western bituminous coal.

TABLE 3-1



# Coal Source and Characteristics

Naughton 3

Parameter PRB P&M Low

Sulfur P&M

High

Sulfur Twentymile

Nitrogen (% dry) 1.10 1.33 1.22 1.85

Oxygen (% dry) 16.2 15.35 14.5 7.19

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



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

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

an indication that more nitrogen is ava ilable to the combustion process and higher NO

x 

# emissions are likely. Oxygen content can be correlated to the reac tivity of the coal with more

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

produce lower NO

x 

# emissions, and they are also mo re conducive to reduction of NO

x

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR NAUGHTON UNIT 3



# emissions, through use of combustion control measures such as low NO

x 

# burners and over

fire air (OFA). These characte ristics indicate that higher NO

x 

# formation is likely with coal

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

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

coal that produces higher NO

x 

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

Figures 3-2 and 3-3 illustrate the relationshi p of nitrogen and oxyge n content to related

BART presumptive NO

x 

# limits for the coals listed in Table 3-1. Each chart identifies the

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

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

Twentymile shows achievement of the BART presumptive NO

x 

# limit for a bituminous coal

and the PRB coal corresponds to the sub-bituminous BART presumptive NO

x 

# limit. The

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

indicates the average NO

x 

# emission rate of 0.40 lb per MMBtu achieved during 2005. The

tune data point indicates the projected NO

x 

# emission rate of 0.35 lb per MMBtu that

PacifiCorp believes is achievable with additional boiler tuning and optimization.

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

and burning P&M coal, the likely NO

x 

# emission rate will be above the bituminous BART

presumptive NO

x 

# limit of 0.28 and considerably highe r than the sub-bituminous BART

presumptive NO

x 

# limit of 0.15 lb per MMBtu.

FIGURE 3-2



# Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART NO

x 

# Limits

Naughton 3

Typical Coal Nitrogen Content vs. NOx Limit

PRB Subbituminous Present

Tune

Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

Typical Nitrogen Content (%-Dry Basis)NOx Limit (lb/MMBtu)



# Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu



# JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR NAUGHTON UNIT 3



# FIGURE 3-3



# Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART NO

x 

# Limits

Naughton 3

Typical Coal Oxygen Content vs. NOx Limit

PRB Subbituminous Twentymile Bituminous Present

Tune

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

Typical Oxygen Content (%-Dry Basis)NOx Limit (lb/MMBtu)



# Subbituminous Presum p tive Limit - 0.15lb/MMBtu Bituminous Presum p tive Limit - 0.28 lb/MMBtu



# Coal quality characteristics also impact the de sign and operation of th e boiler and associated

auxiliary equipment. Minor changes in qua lity can sometimes be accommodated through

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

consistent variations in qua lity or assumptions of “aver age” quality for performance

projections can be problematic. This is pa rticularly troublesome when dealing with

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

such as NO

x 

# formation. There can be significant variab ility in the quality of coals at mines,

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

Several of the coal quality char acteristics and their effect on NO

x 

# formation have been

previously discussed. There are some additional c onsiderations that illustrate the complexity

of achieving and maintaining low NO

x 

# emissions with pulverized co al on a consistent shorter

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

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

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

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

requirement such as NO

x 

# emission limits is subsequen tly changed, conf licts with and

between other performance issues can result.

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

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

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

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR NAUGHTON UNIT 3



# air flows and distri bution to reduce NO

x 

# emissions using low NO

x 

# burners with over-fire air,

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

achieve satisfactory combustion performance.

Another significant factor in controlling NO

x 

# emissions is the fineness of the coal entering

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

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

exposed to air. NO

x 

# reduction with high volatile coals is improved with greater fineness and

with proper air staging. Coal fi neness can deteriorate over ti me periods between pulverizer

maintenance and service as pul verizer grinding surfaces wear.

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

nitrogen and oxygen content of the coals, a nd the grindability i ndex – this analysis

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

configuration of the Na ughton 3 boiler), the low NO

x 

# burner technology referred to in the

EPA’s presumptive BART analysis will achieve a NO

x 

# emission rate of 0.35 lb per MMBtu.

The BART analysis for NO

x 

# emissions from Naughton 1 is fu rther described in this section.

Step 1: Identify All Availabl e Retrofit Control Technologies

The first step of the BART process is to evaluate NO

x 

# control technologies with practical

potential for application to Naughton 3, includ ing those control technologies identified as

Best Available Control Technol ogy (BACT) or lowest achieva ble emission rate (LAER) by

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

reviewed in an effort to identify potentially applicable emission control technologies. NO

x 

# from Naughton 3 emissions are currently cont rolled through the use of LNBs and OFA

The following potential NO

x 

# control technology options were considered:

• Tune existing LNB with OFA

• Mobotec rotating opposed fire air (ROFA)

• Conventional selectiv e non-catalytic reduc tion system (SNCR)

• Selective catalytic reduction system (SCR)

Step 2: Eliminate Technically Infeasible Options

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

and the current boiler co nfiguration and size. Na ughton 3 had an average NO

x 

# emission rate

of 0.40 lb per MMBtu during 2005.

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

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

additional emissions data for boiler tuning. Also, CH2M HILL solicited a proposal from

Mobotec for their ROFA technology.

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

into the furnace within a temperature range of 1,600°F to 2,100°F, where it reduces NO

x 

# to

nitrogen and water. NO

x 

# reductions of up to 60 percent have been achieved, although 20 to

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 40 percent is more realistic for most applica tions. SNCR is typically applied on smaller units.

Adequate reagent distribution in the furn aces of large units can be problematic.

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

with projected NO

x 

# emission rates. All of the technol ogies except tuning the existing LNB

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

TABLE 3-2



# NO

x 

# Control Technology Emission Rates

Naughton 3

Technology Projected Emission Rate (lb per

MMBtu)

Tune Existing LNB with OFA 0.35

ROFA 0.28

LNB with OFA & SNCR 0.28

LNB with OFA & SCR 0.07



# Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

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

may be technically feasible and provide expe cted or guaranteed emission rates; however,

they include inherent uncertainties. These propo sals are usually prepared in a limited time

frame, may be based on incomplete informa tion, may contain over-optimistic conclusions,

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

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

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

control technologies and the control effectiv eness evaluated in this BART analysis.

Tuning Existing LNB/OFA System. The mechanism used to lower NO

x 

# with low NO

x 

# burners

is to stage the combustion process and provide a fuel rich condition initially; this is so

oxygen needed for combustion is not diverted to combine with nitrogen and form NO

x 

# . Fuel-rich conditions favor the conversion of fuel nitrogen to nitrogen, instead of NO

x 

# . Additional air (or OFA) is then introduced downstream in a lo wer temperature zone to burn

out the char.

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

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

be tuned to achieve an expected NO

x 

# emission rate of 0.35 lb per MMBtu.

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

system. Mobotec states that: “the flue gas volume of the furnace is set in rotation by

asymmetrically placed air nozzles. Rotation is re ported 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 maximu m temperature of the flames and increases

heat absorption. The combustion air is also mixed more effectively.” A typical ROFA

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR NAUGHTON UNIT 3



# installation would have a booster fan(s) to supply the high velo city air to th e ROFA boxes,

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

Mobotec expects to achieve a NO

x 

# emission rate of 0.26 lb per MMBtu using ROFA

technology. An operating margin of 0.02 lb per MMB tu 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 eq uipment, the operation of existing burners

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

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

location of new ROFA ports. The Mobotec proposal includes be nt 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 se rvices. However, they do provide one onsite

construction supervisor duri ng 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 consider ed in the post1control modeling scenarios.

Selective Non-catalytic Reduction. This process is generally u tilized to achieve modest NO

x 

# reductions on smaller units. With SNCR, an am ine-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 NO

x 

# to nitrogen and water. NO

x 

# 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 NO

x 

# , 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 a mmonia to create problems

downstream. The ammonia may render fly ash unsa leable, react with su lfur 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 NO

x 

# reduction generally resulting in

lower reagent utilization and higher operating cost.

Reductions from higher baseline concentrations (inlet NO

x 

# ) are lower in cost per ton, but

result in higher operating costs due to greater reagent consumption. To reduce reagent costs,

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

providing a NO

x 

# emission rate of 0.35 lb per MMBtu, would be tuned in conjunction with

SNCR

. At Naughton 3, a further reduction of 20 percent in NO

x 

# emission rates results in a

projected emission rate of 0.28 lb per MMBtu for SNCR.

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

ongoing parasitic costs, the operating difficultie s, and the potential ammonia slip emission

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

SCR. SCR works on the same principle as SNCR, but a catalyst is used to promote the

reaction. Ammonia is injected into the flue-gas stream, where it reduces NO

x 

# to nitrogen and

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 750°F. Due to the catalyst, the SCR process is more efficient than SNCR. The most common

type of SCR is the high-dust configuration, where the catalyst is located upstream of the air

heater and downstream from the economizer. The high-dust configurat ion is assumed for

Naughton 3. In a full-scale SCR, the flue ducts are routed to a separate large reactor

containing the catalyst. With in-duct SCR, the catalyst is located in the existing gas duct,

which may be expanded in the area of the catalyst to increase flue gas residence time. Due to

the higher removal rate, a full-sc ale SCR was used as the basis for analysis at Naughton 3.

S&L prepared the design conditions and cost estimates for SCR at Naughton 3. As with SNCR,

it is generally more cost effective to reduce NO

x 

# emission levels as much as possible through

combustion modifications, in order to mini mize the catalyst surface area and ammonia

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

modifications, including LN Bs and OFA, providing a NO

x 

# emission rate of 0.35 lb per MMBtu,

would be tuned in conjunction with the SCR. The S&L design basis results in a projected NO

x 

# emission rate of 0.07 lb per MMBtu. Additiona l catalyst surface was included in the SCR

design to accommodate the characteristi cs of the coal used at Naughton 3.

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

level of NO

x 

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

review of typical NO

x 

# emissions from coal-fired generati ng units was completed. As a result

of this review, it was noted that NO

x 

# emissions can vary signif icantly around an average

emissions level. Variations may result for ma ny reasons, including coal characteristics, unit

load, boiler operation including ex cess air, boiler slagging, burner equipment condition, coal

mill fineness, and so forth.

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

expected value:

• Establish expected NO

x 

# emissions value from vendor.

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

• Review and evaluate unit physical and opera tional characteristics and restrictions. The

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

variant the NO

x 

# emissions are.

• For each technology expected value, there is a corresponding potential for actual NO

x 

# emissions to vary from this expected valu e. From the vendor information presented, along

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

Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration of energy, environmental, and economic impacts

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

considered during the evaluation.

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

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

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

ROFA fan.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR NAUGHTON UNIT 3



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

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

requirements for SCR instal lation at Naughton 3 are estim ated at approximately

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

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

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

to as loss on ignition would be the same or lo wer than prior levels. In stallation of LNBs with

OFA may also result in higher carbon monoxi de 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 invol ve the storage of am monia (especially if

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

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

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

supplemented (as needed) by vendor-obtained pr ice 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 wh ich 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 NO

x 

# removed is summarized in Table 3-3, and th e first year control costs in Figure 3-4.

The complete economic analysis is contained in Appendix A.

TABLE 3-3



# NO

x 

# Control Cost Comparison

Naughton 3

Factor Tune LNB with

OFA ROFA LNB with OFA

& SNCR LNB with OFA

& SCR

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

Total First Year Fixed & Variable

O&M Costs NA $1.9 million $0.9 million $2.6 million

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

Power Consumption (MW) NA 4.5 0.3 2.0

Annual Power Usage (1000 megawatt

hours per year) NA 35.3 2.6 15.7

NO

x

# Design Control Efficiency 22.2% 37.8% 37.8% 84.4%

Tons NO

x

# Removed per Year 1,459 2,479 2,479 5,542

First Year Average Control Cost

(dollars per ton [$/Ton] of NO

x 

# Removed) 0 1,326 984 2,049

Incremental Control Cost

($/Ton of NO

x

# Removed) 0 1,326 2,390 2,635

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-12 

# Preliminary BART Selection. CH2M HILL recommends tuning the low-NO

x 

# burners with

OFA as BART for Naughton 3; this is based on its significa nt reduction in NO

x 

# emissions,

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

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

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

technology and the achieved emission rate ar e deemed appropriate as BART for NO

x 

# emissions when considering the coals combuste d and the size and confi guration of the boiler

at Naughton 3.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 3FIGURE 3-4First Year Control Cost for NOxAir Pollution Control OptionsNaughton 305001,0001,5002,0002,5003,000Tune Exist. LNB w/OFAROFASNCRSCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 3.2.2 BART SO 2 

# Analysis

Sulfur dioxide (SO 2 

# ) forms in the boiler during the combustion process, and is primarily

dependent on coal sulfur content. The BART analysis for SO 2 

# emissions on Naughton 3 is

described below.

Step 1: Identify All Availabl e Retrofit Control Technologies

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

applicable emission control technologies for SO 2 

# at Naughton 3; this included control

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

The following potential SO 2 

# control technology options were considered:

• Upgrade wet waste sodium liquor FGD

• Upgrade wet FGD and use soda ash reagent

Step 2: Eliminate Technically Infeasible Options

Naughton 3 currently has a controlled SO 2 

# emission rate of 0.50 lb per MMBtu. The

following summarizes the technical feasibility analysis performed.

Upgrade Wet Waste Sodium Liquor FGD. Wet SO 2 

# scrubbers operate by flowing the flue gas

upward through a large reactor vessel that has an alkaline reagent flowing down from the top.

The scrubber mixes the flue gas and alkaline reagent using a series of spray nozzles to

distribute the reagent across the scrubber vessel. The sodium in the reagent reacts with the

SO 2 

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

scrubber and disposed.

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

83 percent SO 2 

# removal to achieve an SO 2 

# outlet emission rate of 0.50 lb per MMBtu. To

achieve 90 to 95 percent SO 2 

# removal, the wet FGD system operation would be changed by

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

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

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

0.21 lb per MMBtu (90 percent total SO 2 

# removal or 58 percent incremental SO 2 

# removal).

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

achieve an outlet emission rate of 0.1 0 lb per MMBtu (95 percent overall SO 2 

# removal or

80 percent incremental SO 2 

# removal).

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

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

with a new fabric filter, are infe rior technologies for removing SO 2 

# , they were not evaluated

further.

Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration of energy, environmental, and economic impacts

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

considered during the evaluation.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-15 

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

of additional power.

Environmental Impacts. There are no anticipated environm ental impacts from upgrading the

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

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

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

Economic Impacts. A summary of the costs and amount of SO 2 

# removed for the upgraded wet

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

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

Appendix A.

TABLE 3-4



# SO 2 

# Control Cost Comparison (Incremental to Existing FGD System)

Naughton 3

Factor Upgraded Wet Flue Gas Desulfurization

(FGD) with Waste Liquor Upgraded Wet FGD

with Soda Ash

Total Installed Capital Costs $4.5 million $14.5 million

Total First Year Fixed and Variable

Operation and Maintenance Costs $0.5 million $1.6 million

Total First Year Annualized Cost $0.9 million $3.0 million

Incremental Power Consumption (MW) 0.3 0.3

Incremental Annual Power Usage

(1000 megawatt hours per year) 2.6 2.6

Incremental SO 2 

# Design Control

Efficiency 58.0% 80.0%

Incremental Tons SO 2 

# Removed per

Year 4,230 5,834

First Year Average Control Cost ($/Ton

of SO 2 

# Removed) 223 519

Incremental Control Cost

($/Ton of SO 2 

# Removed) 223 1,299



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

waste liquor as BART for Naughton 3. This is based on its significant reduction in SO 2 

# emissions, reasonable control costs, and th e advantages of minimal additional power

requirements and environmental impacts.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 3FIGURE 3-5First Year Control Cost for SO2Air Pollution Control OptionsNaughton 302004006008001,0001,2001,400N/AWet FGD w/Waste LiquorWet FGD w/Soda AshAir Pollution Control Option

Control Cost ($/Ton SO2 Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC3-16

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 3.2.3 BART PM 10



# Analysis

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

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

attracting these particles to grounded collection pl ates. A layer of collected particulate matter

forms on the collecting plates and is rem oved by periodically rapping the plates. The

collected ash particles drop into hoppers below the precipitator and are removed periodically

by the fly ash-handling system. The ESP at Naughton 3 controls PM emissions to

0.094 lb per MMBtu.

The BART analysis for PM emissions on Naught on 3 is described below. For the modeling

analysis to be completed in Section 4, PM 10 

# will be used as an indicator for PM, and PM 10 

# includes particulate matter less than 2.5 micrometers in aerodynamic diameter (PM 2.5 

# ) as a

subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

Two retrofit control t echnologies have been identified for additional PM control:

• Enhance existing ESP

• Polishing fabric filter

• Replacement fabric filter

Step 2: Eliminate Technically Infeasible Options

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

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

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

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

improvements in collection efficiency for small ESPs.

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

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

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

the ash that is not collected by the ESP, thus acting as a polishing device. The ESP needs to

be kept in service for the C OHPAC fabric filter to work.

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

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

jet fabric filter (3.5 to 4:1).

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

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

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

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

at lower costs—installation of a full-size fabric filter was not considered in the analysis.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

The existing ESP at Naughton 3 is achieving a controlled PM emission rate of 0.094 lb per

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-17

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 0.040 lb per MMBtu. Adding a COHPAC fabric f ilter downstream of th e existing ESP would

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

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

Step 4: Evaluate Impacts and Document the Results

This step involves the cons ideration 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 a ssociated ductwork. Therefore, a COHPAC retrofit will require

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

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

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

based on a 90 percent annua l plant capacity factor.

There are no negative environm ental impacts from upgrading th e ESP and the addition of a

flue gas conditioning system.

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

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

system. The PM 10 

# control technology emission rate ra nking is summarized in Table 3-5.

TABLE 3-5



# PM 10



# Control Technology Emission Rate Ranking

Naughton 3

Control Technology Projected PM 10 (a) 

# Emission Rate

(pound per million

British thermal units)

Upgrade Electrostatic Precipitator

(ESP) and Flue Gas Conditioning 0.040

Polishing Fabric Filter 0.015

Replacement Fabric Filter 0.015

NOTES:

(a) 

# PM 10 

# refers to particulate matter less than 10 micrometers in aerodynamic diameter



# Economic Impacts. A summary of the costs and PM re moved for COHPAC and flue gas

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

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

contained in Appendix A.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-18

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 3-19 

# TABLE 3-6



# PM 10



# Control Cost Comparison

Naughton 3

Factor Flue Gas

Conditioning Polishing Fabric Filter

Total Installed Capital Costs $13.3 million $80.3 million

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

Total First Year Annualized Cost $1.3 million $8.8 million

Power Consumption (MW) 0 2.1

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

PM Design Control Efficiency 57.4% 84.0%

Tons PM Removed per Year 788 1,152

First Year Average Control Cost

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

Incremental Control Cost

($/Ton of SO 2 

# Removed) 1,606 20,553



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

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

reduction in PM 10 

# emissions, reasonable control costs, as well as the advantages of creating

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

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 3FIGURE 3-6First Year Control Cost for PM Air Pollution Control OptionsNaughton 305,00010,00015,00020,00025,000Enhancements to Existing ESPFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC3-20

# 4.0 BART Modeling Analysis

4.1 Model Selection

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

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

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

Naughton 3 Plant. These wilder ness areas (WA) include:

• Bridger WA

• Fitzpatrick WA

The CALPUFF modeling system includes th e CALMET meteorological model CALPUFF

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

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

modeling system was applied in a full, refi ned mode. Version numbers of the various

programs in the CALPUFF system used by CH2M HILL were as follows:

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

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

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

established to encompass the Naughton 3 facility and allow for a 50-km buffer around the

Class I areas that were within 300 km of the facility. Grid resolution was 4 km. Figure 4-1

shows the extent of the modeling domain. Excep t when specifically instructed otherwise by

the Wyoming Department of Environmental Quality- Air Qualit y Division (WDEQ-AQD),

CH2M HILL followed the methodology spelled out in the BART Modeling Protocol which

is included in this report as Appendix B. Th is 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 orig in and the longitude of the

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

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

minimize distortion in the north-south direction.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-1BridgerWilderness AreaFitzpatrickWilderness AreaIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinLEGEND300 KilometersClass I AreasCALMET DomainStandard Parallels0 100 200 300KilometersFigure 4-1Naughton Source-SpecificClass I Areas to be AddressedStandard Parallel 1: 40 12' 2.30"Standard Parallel 2: 45 14' 28.09"Domain Dimensions 1060 x 780 KM114° 5' 20.40" Longitude39° 3' 53.37" Latitude100° 56' 34.08" Longitude45° 51' 57.22" Latitude101° 54' 25.88" Longitude38° 54' 0.04" Latitude114° 28' 37.96" Longitude46° 6' 26.20" LatitudeNaughtonSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\NAUGHTON_CLASSI.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR NAUGHTON UNIT 3



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

CALMET.inp file were used for CALMET. Verti cal resolution of the wind field included ten

layers, with vertical face hei ghts as follows (in meters):

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

Other user-specified model options were se t to values established by WDEQ-AQD which

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

analysis.

TABLE 4-1



# User-specified CALMET Options

Naughton 3

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500



# 4.2.2 CALMET Input Data

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

WDEQ-AQD provided 12-km resolution Meso scale Meteorological Model, Version 5

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

These three data sets were chosen because th ey 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\NAUGHTON3_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-4 

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

generate a Step 1 wind field, and further refine d 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 stat ions from the National Weather Service’s

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

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

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

SMERGE preprocessor and CALMET.

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

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

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

categories. Surface properties such as albe do, 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 pr imarily derive from USGS 1:250,000 scale

topographic maps. Missing land use da ta 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 fo r 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 CALM ET 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)P60WRLTORSHRRKSRIW (UA)RWLLARLNDGEYGCCEVWDGWCYSCPRBYGBPIVELSLC (UA)PUCOGDLGUDLNRXEPIHIDALLJBYIRILEEOLICLXVGJTDEN (UA)APACAGITRASEAKOIENPHPD07CUT2WXSNYBFFCDRAIALVMDLNBTMBZNBILBridgerWilderness AreaFitzpatrickWilderness AreaIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinLEGENDClass I AreasCALMET DomainASOS Surface StationsUpper Air Station0 100 200 300KilometersFigure 4-2Surface and Upper Air Stations Used in theNaughton BART AnalysisStandard Parallel 1: 40 12' 2.30"Standard Parallel 2: 45 14' 28.09"Domain Dimensions 1060 x 780 KM114° 5' 20.40" Longitude39° 3' 53.37" Latitude100° 56' 34.08" Longitude45° 51' 57.22" Latitude101° 54' 25.88" Longitude38° 54' 0.04" Latitude114° 28' 37.96" Longitude46° 6' 26.20" LatitudeNaughtonSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\NAUGHTON_ASOS.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 4.2.3 Validation of CALMET Wind Field

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

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

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

conditions, as depicted in surface and upper-a ir 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 wa s used to predict

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

impacts for post-control scenarios for Naughton 3.



# 4.3.1 Background Ozone and Ammonia

Hourly values of background ozone concen trations were used by CALPUFF for the

calculation of SO 2 

# and NO

x 

# 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 a mmonia 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 m odeling reflect those that are in place under the

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

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



# 4.3.3 Emission Rates

Pre-control emission rates for Naughton 3 reflec t peak 24-hour average emissions that may

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-7 

# Guidelines for Best Available Retrofit Technology Determinations; Final Rule (40 CFR

Part 51).

CH2M HILL used available continuous emissi on 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:

• SO 2



# • NO

x



# • Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• Fine particulate (diameter<PM 2.5 

# )

• Sulfates

Post-control emission rates reflect the effect s 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 develo ped to cover the range of effectiveness for

the combination of the individual NO

x 

# , SO 2 

# , and PM control technol ogies being evaluated.

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

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

levels for each pollutant, unless it was determined that an alternative control level is justified,

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

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

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

recommendation.

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

ESP.

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

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

new fabric filter.

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

for baseline and post-control modeling. In accordance with the WD EQ BART modeling

protocol, elemental carbon stack emissions and organic aerosol emissions were not modeled.TABLE 4-2BART Model Input DataNaughton 3BaselinePost-control Scenario 1Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Model Input DataCurrent Operations with WetFGD and ElectrostaticPrecipitator (ESP)Low-NOxBurners (LNBs) with Overfire Air (OFA), Wet Flue GasDesulfurization (FGD) with WasteLiquor, Existing ESPLNB with OFA & SCR, WetFGD with Waste Liquor,Enhanced ESPLNB with OFA and SCR, WetFGD with Waste Liquor, FabricFilterLNB with OFA and SCR, WetFGD with Soda Ash, FabricFilterSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])1,840 777 777 777 368Nitrogen Oxide (NOx) Stack Emissions (lb/hr)1,6561,295259259258PM10Stack Emissions (lb/hr)348 148 148 55.5 55.5Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)149 63.6 63.6 31.6 31.5Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)198 84.4 84.4 23.9 23.7Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 34.0 34.0 58.7 58.7 58.7H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 33.4 33.4 57.3 57.3 57.3Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)4.264.264.26(NH4)2SO4as SO4Stack Emissions (lb/hr)3.093.093.09(NH4)HSO4Stack Emissions (lb/hr)7.407.407.40(NH4)HSO4as SO4Stack Emissions (lb/hr)6.186.186.18Total Sulfate (SO4) (lb/hr)33.2 33.3 66.5 66.5 66.2Stack ConditionsStack Height (meters)145 145 145 145 145Stack Exit Diameter (meters) 8.088.088.088.088.08Stack Exit Temperature (Kelvin)323322322322323Stack Exit Velocity (meters persecond)23.820.2 20.2 20.2 18.6NOTES:(a)Based on AP-42, Table 1.1-6, the coarse particulates are countedas a percentage of PM10.This equates to 43 percentESP 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) = H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4as SO4Stack Emissions (lb/hr) + (NH4)HSO4as SO4Stack Emissions (lb/hr)

# BART ANALYSIS FOR NAUGHTON UNIT 3



# 4.3.5 Modeling Process

The CALPUFF modeling for the control techno logy options for Naughton 3 followed this

sequence:

• Model pre-control (baseline) emissions

• Model preferred post-control scenario (if applicable)

• Determine degree of visibility improvement

• Model other control scenarios

• Determine degree of visibility improvement

• Factor visibility results into the BART “five-step” evaluation



# 4.3.6 Receptor Grids

Discrete receptors for the CALPUFF modeli ng were placed at uniform receptor spacing

along the boundary and in the interior of each ar ea 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 rece ptors, meteorological stations, and source

locations.



# 4.4 CALPOST

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

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

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

( Δ dV) change relative to natura l background. The following default extinction coefficients

for each pollutant, were used:

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 

# ) 0.6

• PM fine (PM 2.5 

# ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0

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

humidity factors were used in the light exti nction 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 fact ors for the Class I areas. These

values were used for the partic ular Class I area being modeled.

The natural background conditions as a reference for determining the Δ dV change

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

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

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

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-9

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 4-10 

# Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule

(EPA, 2003). A separate scaling factor was deri ved for each Class I area such that, when

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

for that area would be calculate d. 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 a nnual average species concentrations from the BART protocol.

TABLE 4-3



# Average Natural Levels of Aerosol Components

Naughton 3

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Fitzpatrick and Bridger Class I Wilderness Areas

Ammonium Sulfate 0.045

Ammonium Nitrate 0.038

Organic Carbon 0.178

Elemental Carbon 0.008

Soil 0.189

Coarse Mass 1.136

NOTE:

Source: Table 6 of the Wyoming BART Air Modeling Protocol



# 4.5 Presentation of Modeling Results

This section presents the resu lts of the CALPUFF visibility improvement modeling analysis

for Naughton 3.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

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

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

rates for SO 2 

# , NO

x, 

# and PM 10 

# that would be achieved if BA RT state-of-the-art technology

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

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

the selection of an alternative control device may be warranted.

Baseline (and post-control) 98 th 

# percentile results were greater than 0.5 Δ dV for the

Bridger WA and Fitzpatrick WA. The 98 th 

# percentile results for each Class I area are

presented in Table 4-4.BART ANALYSIS FOR NAUGHTON UNIT3TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasNaughton 3ModelingResultsScenarioTotal FirstYearAnnualizedCostClass IWilderness AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)Number (No.) of DaysAbove 0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2001Bridger5.6571.97866----Baseline: Current Operation with wet flue gas desulfurization(FGD), Electrostatic Precipitator (ESP)Fitzpatrick3.2141.12624----$2,207,011Bridger4.4981.41312$3,906,214$40,871Scenario 1: Low-NOxBurners (LNBs) with Over-fire Air(OFA), wet waste liquor FGD, enhanced ESP$2,207,011Fitzpatrick2.1100.73516$5,644,529$275,876$13,563,715Bridger2.3460.71619$10,747,793$288,590$16,293,693NAScenario 2: LNB with OFA, wet waste liquor FGD, enhancedESP$13,563,715Fitzpatrick1.0960.3714$17,965,185$678,186$31,199,736$946,392$21,057,857Bridger2.2760.69716$16,438,608$421,157$394,428,526$2,498,047Scenario 3: LNB with OFA and Selective CatalyticReduction (SCR), wet wasteliquor FGD, fabric filter$21,057,857Fitzpatrick1.0760.3634$27,598,764$1,052,893$936,767,750NA$23,141,792Bridger1.9140.55312$16,239,854$428,552$14,471,771$520,984Scenario 4: LNB with OFA and SCR, wet soda ash FGD,fabric filter$23,141,792Fitzpatrick0.7700.2652$26,877,807$1,051,900$21,264,643$1,041,9682002Bridger4.7831.61855----Baseline: Current Operation with wet FGD, ESPFitzpatrick3.8620.89321----$2,207,011Bridger3.4011.17532$4,981,966$95,957Scenario 1: LNB with OFA, wet waste liquor FGD, enhancedESP$2,207,011Fitzpatrick2.8640.56411$6,708,240$220,701$13,563,715Bridger1.6830.65010$14,012,102$301,416$21,631,817$516,214Scenario 2: LNB with OFA, wet waste liquor FGD, enhancedESP$13,563,715Fitzpatrick1.4780.2903$22,493,723$753,540$41,447,825$1,419,588$21,057,857Bridger1.6310.63510$21,422,032$467,952$499,609,467NAScenario 3: LNB with OFA and SCR, wet waste liquor FGD,fabric filter$21,057,857Fitzpatrick1.4400.2793$34,296,184$1,169,881$681,285,636NA$23,141,792Bridger1.3410.4947$20,588,783$482,121$14,779,681$694,645Scenario 4: LNB with OFA and SCR, wet soda ash FGD,fabric filter$23,141,792Fitzpatrick1.1440.2033$33,538,829$1,285,655$27,420,197NAJMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC4-11BART ANALYSIS FOR NAUGHTON UNIT 3JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC4-12TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasNaughton 3ModelingResultsScenarioTotal FirstYearAnnualizedCostClass IWilderness AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)Number (No.) of DaysAbove 0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2003Bridger4.0562.17153----Baseline: Current Operation with wet FGD, ESPFitzpatrick1.7100.87121----$2,207,011Bridger3.0161.55539$3,582,810$157,644Scenario 1: LNB with OFA, wet waste liquor FGD, enhancedESP$2,207,011Fitzpatrick1.2330.5499$6,854,071$183,918$13,563,715Bridger1.4440.82814$10,099,564$347,788$15,621,326$454,268Scenario 2: LNB with OFA, wet waste liquor FGD, enhancedESP$13,563,715Fitzpatrick0.6040.2601$22,199,206$678,186$39,296,554$1,419,588$21,057,857Bridger1.3930.81014$15,472,342$539,945$416,341,222NAScenario 3: LNB with OFA and SCR, wet waste liquor FGD,fabric filter$21,057,857Fitzpatrick0.5850.2531$34,074,202$1,052,893$1,070,591,714NA$23,141,792Bridger1.1980.66211$15,335,846$550,995$14,080,642$694,645Scenario 4: LNB with OFA and SCR, wet soda ash FGD,fabric filter$23,141,792Fitzpatrick0.4800.2140$35,223,428$1,101,990$53,434,231$2,083,9353-Year AveragesBridger1.92258.0Baseline: Current Operation with wet FGD, ESPFitzpatrick0.96322.0$2,207,011Bridger1.38127.7$4,076,991$72,759Scenario 1: LNB with OFA, wet waste liquor FGD, enhancedESP$2,207,011Fitzpatrick0.61612.0$6,354,158$220,701$13,563,715Bridger0.73114.3$11,388,510$310,619$17,480,817$851,753Scenario 2: LNB with OFA, wet waste liquor FGD, enhancedESP$13,563,715Fitzpatrick0.3072.7$20,665,894$701,571$36,753,087$1,216,790$21,057,857Bridger0.71413.3$17,427,192$471,445$432,354,346$7,494,142Scenario 3: LNB with OFA and SCR, wet waste liquor FGD,fabric filter$21,057,857Fitzpatrick0.2982.7$31,665,950$1,089,200$864,708,692NA$23,141,792Bridger0.57010.0$17,108,274$482,121$14,438,349$625,181Scenario 4: LNB with OFA and SCR, wet soda ash FGD,fabric filter$23,141,792Fitzpatrick0.2271.7$31,442,652$1,138,121$29,351,197$2,083,935NOTES:Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $2,207,011 / (2.569 - 1.782) = $2,804,334Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $2,207,011 / (72 - 48) = $91,959

# 5.0 Preliminary Assessment and

Recommendations

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

modeling analysis completed for Naughton 3, th e preliminary recommended BART controls

for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# Tune LNBs and OFA system for NO

x 

# control

• 

# Upgrade wet waste sodium liquor scrubber for SO 2 

# control

• 

# Enhance existing ESP for PM control

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

Section 4. Visibility improvements for all emi ssion control scenarios we re 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 Se ction 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 tota l annualized cost versus 98 th 

# percentile Δ dV 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 Ma nual, the EPA states that “Incremental

cost-effectiveness comparisons should focu s 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 annua lized costs for a total emissions reductions for all control

alternatives identified in the BACT analysis...”

An analysis of incremental cost-effectiven ess has been conducted. This analysis was

performed in the following way: First, the cont rol option scenarios are ranked in ascending

order of annualized total costs, as show n 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 opti on scenarios is plotted

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

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

impacted by the operation of Naughton 3.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR NAUGHTON UNIT 3



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

number of days above 0.5 dV. The EPA states that: “in calculating in cremental costs, the

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

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

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

inferior options and should not be cons idered in the derivation of incremental

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

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

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

for less cost than Scenario 4. The incremen tal cost-effectiveness is determined by the

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

in emissions reduction.

TABLE 5-1



# Bridger WA Class I Agent Control Data

Naughton 3

Scenario Controls 98 th 

# 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-NO

x

# Burners

(LNBs) with Over-fire

Air (OFA), Waste

Liquor Flue Gas

Desulfurization (FGD),

Enhanced ESP 0.54 30.3 $2.2 $4.1 $0.1

2 LNB with OFA and

Selective Catalytic

Reduction (SCR),

Waste Liquor FGD,

Enhanced ESP 1.19 43.7 $13. 6 $11.4 $0.3

3 LNB with OFA and

SCR, Waste Liquor

FGD, New Fabric Filter 1.21 44.7 $21. 1 $17.4 $0.5

4 LNB with OFA & SCR,

Wet Soda Ash FGD,

New Fabric filter 1.35 48.0 $23. 1 $17.1 $0.5

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR NAUGHTON UNIT 3



# TABLE 5-2



# Fitzpatrick WA Class I Area Control Data

Naughton 3

Scenario Controls 98 th



# 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-NO

x

# Burners (LNBs)

with Over-fire Air (OFA),

Waste Liquor Flue Gas

Desulfurization (FGD),

Enhanced ESP 0.35 10.0 $2.2 $6.4 $0.2

2 LNB with OFA and

Selective Catalytic

Reduction (SCR), Waste

Liquor FGD, Enhanced

ESP 0.66 19.3 $13. 6 $20.7 $0.7

3 LNB with OFA and SCR,

Dry FGD, Fabric Filter 0.67 19.3 $21. 1 $31.7 $1.1

4 LNB with OFA & SCR, Wet

FGD, New stack 0.74 20.3 $23. 1 $31.4 $1.1

TABLE 5-3



# Bridger WA Class I Agent Incremental Data

Naughton 3

Options Compared Incremental

Reduction in

Days Above

0.5 deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental

Cost-effectiveness

(million$/Days) Incremental

Cost-effectiveness

(million$/dV)

Baseline and Scenario 1 30.3 0.54 $0.07 $4.08

Scenario 1 and Scenario 2 13.3 0.65 $0.9 $17.5

Scenario 1 and Scenario 3 14.3 0.67 $1.3 $28.3

Scenario 1 and Scenario 4 17.7 0.81 $1.2 $25.8

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR NAUGHTON UNIT 3



# TABLE 5-4



# Fitzpatrick WA Class I Area Incremental Data

Naughton 3

Options Compared Incremental

Reduction in

Days Above

0.5 deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental

Cost-effectiveness

(million$/Days) Incremental

Cost-effectiveness

(million$/dV)

Baseline and Scenario 1 10.0 0.35 $0.22 $6.35

Scenario 1 and Scenario 2 9.3 0.31 $1.2 $36.8

Scenario 1 and Scenario 3 9.3 0.32 $2.0 $59.3

Scenario 1 and Scenario 4 10.3 0.39 $2.0 $53.9

FIGURE 5-1



# Least-cost Envelope Bridger WA Class I Area Reduction

Naughton 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



# $0.0 $5.0 $10.0 $15.0 $20.0 $25.0

0 1 0 2 0 3 0 4 0 5 0 6



# Reduction in Days of Exceeding 0.5 dV (days)Total Annualized Cost (Mil $)



# 0



# JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR NAUGHTON UNIT 3



# FIGURE 5-2



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



# Percentile

Naughton 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



# $0.0 $5.0 $10.0 $15.0 $20.0 $25.0

0.00 0.20 0.40 0.60 0. 80 1.00 1.20 1.40 1.60



# 98th Percentile Delta-Deciview Reduction ( dV )Total Annualized Cost (Mil $)



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick WA Class I Area Reduction

Naughton 3

Scenario 3

Scenario 2

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\NAUGHTON3_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR NAUGHTON UNIT 3



# FIGURE 5-4



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



# Percentile

Naughton 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



# $0.0 $5.0 $10.0 $15.0 $20.0 $25.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80



# 98th Percentile Delta-Deciview Reduction (dV)Total Annualized Cost (Mil $)



# 5.1.2 Analysis of Results

Results of the least-cost analysis—shown in Ta bles 5-1 to 5-4 and Figures 5-1 to 5-4 on the

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

visibility improvements. The other scenarios were eliminated for the following reasons:

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

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

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

improvement and a cost per dV reduction.

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

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

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

Figures 5-1 and 5-2 illustrate th e conclusions stated in this section. The greatest reduction in

98 th 

# 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 incr emental cost-effectiveness for Scenario 1,

compared to the Baseline, is reasonable at $70,000 per day and $4.08 million per dV to

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

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

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

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

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

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

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR NAUGHTON UNIT 3

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 5-7 

# improving visibility at the Fitzpatrick Wilder ness Area. In fact, the incremental costs are

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

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

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

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



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

CH2M HILL recommends tuning the low-NO

x 

# burners with over-fir e air as BART for

Naughton 3; this is based on the projected significant reduction in NO

x 

# emissions, reasonable

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

quality environmental impacts. With this approach, the NO

x 

# emission rate is projected to be

0.35 lb per MMBtu.



# 5.2.2 SO 2 

# Emission Control

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

for Naughton 3, based on the significant reduction in SO 2 

# emissions, reasonable control

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

quality environmental impacts. This a pproach is projected to meet an SO 2 

# emission rate of

0.21 lb per MMBtu.



# 5.2.3 PM 10



# Emission Control

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

this is based on the significant reduction in PM 10 

# emissions, reasonable c ontrol costs, as well

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

impacts.



# 5.3 Just-Noticeable Differences in Atmospheric Haze

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

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

1.5 to 2.0 dV or more are perceivable by the hu man 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 s cenarios. Thus the results i ndicate that even though many

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

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

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

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

natural obscuration were to reduce the visibil ity impacts modeled for the Naughton 3 facility,

it would increase the costs per dV reducti on 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 Visi bility Conditions U nder the Regional Haze

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

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

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

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

http://docs.lib.noaa.gov/rescue/dwm/d ata_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—Individu al Source Visibility Assessments

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

Quality Division. September 2006.

JMS EY102007001SLC\NAUGHTON3_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios9Index No. Name of Unit1 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 310 WyodakScenario First Year Cost ScenarioFirst YearCost Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/A N/A N/A N/A $ 2,207,011N/A N/A N/A N/A $ 2,207,011N/A N/A N/A N/A $ 13,563,715N/A N/A N/A N/A $ 13,563,715N/A N/A N/A N/A $ 21,057,857N/A N/A N/A N/A $ 21,057,857N/A N/A N/A N/A $ 23,141,792N/A N/A N/A N/A $ 23,141,792Scenario First Year Cost Scenario First Year Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/AN/A N/A N/A N/AN/AN/A N/A N/A N/AN/A N/A N/A N/AN/AN/AN/A N/A N/A N/AN/A N/A N/A N/AN/AN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AN/A N/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AN/A N/A N/A N/AScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 1 - LNB with OFA, DryFGD, Fabric FilterBaseline - Current Operation withESPScenario 1 - LNB with OFA, DryFGD, Existing ESPScenario 2 - LNB with OFA, DryFGD, New Fabric FilterJim BridgerSelect Unit:Scenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterDJ Unit 4Scenario 4 - LNB with OFA andSCR, Wet FGD, Existing ESP,New StackDave JohnstonDJ Unit 3Baseline - Current Operation withVenturi ScrubberJB Unit 1 JB Unit 2 JB Unit 3 JB Unit 4Baseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, Fabric FilterScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPNaughtonScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterBaseline - Current Operation withESPBaseline - Current Operation withESPBaseline - Current Operation with Wet FGDand ESPNTN Unit 1 NTN Unit 2 NTN Unit 3Scenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA and SCR,Waste Liquor FGD, Enhance ESPScenario 1 - LNB with OFA, DryFGD, ESP and Higher Sulfur CoalScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, Waste LiquorFGD, Enhance ESPScenario 4 - LNB with OFA and SCR, SodaAsh FGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA and SCR,Waste Liquor FGD, New Fabric FilterScenario 4 - LNB with OFA and SCR, WetFGD, ESPNaughton Unit 3Scenario 3 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 2 - LNB with OFA, Dry FGD,Fabric FilterScenario 1 - LNB with OFA, Dry FGD, ESPBaseline - Current Operation with Dry FGD,ESPWyodakWyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYNaughton Unit 3Boiler Design: Tangential-Fired PCTune Exist.LNB w/OFAROFA SNCR SCRWet FGDw/Waste LiquorWet FGDw/Soda AshEnhancementsto Existing ESPFabric FilterCase1 2 3 4 5 7 8 9 10NOx Emission Control SystemLNCFS II LNBTune Exist. LNBw/OFA ROFA SNCR SCR LNCFS II LNB LNCFS II LNB LNCFS II LNB LNCFS II LNBSO2 Emission Control SystemWet FGD Wet FGD Wet FGD Wet FGD Wet FGDWet FGD w/WasteLiquorWet FGD w/SodaAsh Wet FGD Wet FGDPM Emission Control SystemESP ESP ESP ESP ESP ESP ESP Existing ESP Fabric FilterTOTAL INSTALLED CAPITAL COST ($)0 0 14,747,608 15,788,530 92,007,264 4,499,834 14,499,464 13,299,508 80,297,031FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 0 0 0 0Maintenance Material ($) 0 0 48,000 75,000 156,000 21,900 21,900 0 48,666Maintenance Labor ($) 0 0 72,000 112,500 234,000 14,600 14,600 0 72,999Administrative Labor ($) 0 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 0 120,000 187,500 390,000 36,500 36,500 0 121,665Makeup Water Cost 0 0 0 0 0 37,985 37,985 0 0Reagent Cost 0 0 0 620,285 927,219 0 787,613 0 0SCR Catalyst / FF Bag Cost 0 0 0 0 501,000 0 0 0 187,096Waste Disposal Cost 0 0 0 0 0 309,228 654,306 0 0Electric Power Cost 0 0 1,763,730 130,086 786,035 130,086 130,086 0 812,052TOTAL VARIABLE O&M COST0 0 1,763,730 750,371 2,214,254 477,298 1,609,990 0 999,148TOTAL FIRST YEAR O&M COST 0 0 1,883,730 937,871 2,604,254 513,798 1,646,490 0 1,120,813FIRST YEAR DEBT SERVICE ($)0 0 1,402,908 1,501,929 8,752,451 428,059 1,379,302 1,265,153 7,638,482TOTAL FIRST YEAR COST ($)0 0 3,286,638 2,439,799 11,356,705 941,857 3,025,792 1,265,153 8,759,295Power Consumption (MW) 0.0 0.0 4.5 0.3 2.0 0.3 0.3 0.0 2.1Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 35.3 2.6 15.7 2.6 2.6 0.0 16.2CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0% 22.2% 37.8% 37.8% 84.4% 0.0% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 1,459 2,479 2,479 5,542 0 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 0 1,326 984 2,049 0 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 0 1,326 2,390 2,635 0 0 0 02-1 3-1 4-2 5-3SO2 Removal Rate (%)82.8% 0.0% 0.0% 0.0% 0.0% 58.0% 80.0% 0.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 4,230 5,834 0 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 223 519 0 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 223 1,299 0 07-1 8-7PM Removal Rate (%) 97.87% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 57.45% 84.04%PM Removed (Tons/Yr) 0 0 0 0 0 0 0 788 1,152First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 0 1,606 7,602Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 0 1,606 20,5539-1 10-9PRESENT WORTH COST ($)0 0 37,762,741 27,247,297 123,825,654 10,777,343 34,616,036 13,299,508 93,990,964PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 1INPUT CALCULATIONSNaughton Unit 3Boiler Design:Tangential-Fired PCTune Exist.LNB w/OFAROFA SNCR SCRWet FGD w/WasteLiquorWet FGDw/Soda AshEnhancements toExisting ESPFabric FilterCase1 2 3 4 5 7 8 9 10NOx Emission Control SystemLNCFS II LNBTune Exist. LNBw/OFA ROFA SNCR SCRLNCFS II LNB LNCFS II LNB LNCFS II LNB LNCFS II LNBSO2 Emission Control SystemWet FGDWet FGD Wet FGD Wet FGD Wet FGDWet FGD w/Waste Liquor Wet FGD w/Soda AshWet FGD Wet FGDPM Emission Control SystemESPESP ESP ESP ESP ESP ESPEnhancements to ExistingESP Fabric FilterUnit Design and Coal CharacteristicsType of UnitPC PC PC PC PC PC PC PC PCNet Power Output (kW)330,000 330,000330,000 330,000 330,000 330,000 330,000 330,000 330,000Net Plant Heat Rate (Btu/kW-Hr)11,21211,212 11,212 11,212 11,212 11,212 11,212 11,212 11,212Boiler FuelKemmerer MineKemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer MineCoal Heating Value (Btu/Lb)9,950 9,8759,875 9,875 9,875 9,875 9,875 9,875 9,875Coal Sulfur Content (wt.%)1.45%1.02%1.02%1.02%1.02%1.02%1.020%1.02%1.02%Coal Ash Content (wt.%)5.50%5.25%5.25%5.25%5.25%5.25%5.25%5.25%5.25%Boiler Heat Input, each (MMBtu/Hr)3,700 3,700 3,700 3,700 3,700 3,700 3,700 3,700 3,700Coal Flow Rate (Lb/Hr)371,855 374,679 374,679 374,679 374,679 374,679 374,679 374,679 374,679(Ton/Yr)1,465,853 1,476,987 1,476,987 1,476,987 1,476,987 1,476,987 1,476,987 1,476,987 1,476,987(MMBtu/Yr)29,170,48529,170,48529,170,48529,170,48529,170,48529,170,48529,170,48529,170,48529,170,485EmissionsUncontrolled SO2 (Lb/Hr)10,773 7,636 7,636 7,636 7,636 1,850 1,850 7,636 7,636(Lb/MMBtu)2.91 2.06 2.06 2.06 2.060.50 0.502.06 2.06(Lb Moles/Hr)168.16 119.19 119.19 119.19 119.19 28.88 28.88 119.19 119.19(Tons/Yr)42,467 30,100 30,100 30,100 30,100 7,293 7,293 30,100 30,100SO2 Removal Rate (%)82.8%0.0%0.0%0.0%0.0%58.0%80.0%0.0%0.0%(Lb/Hr)8,923 0 0 0 0 1,073 1,480 0 0(Ton/Yr)35,175 0 0 0 0 4,230 5,834 0 0SO2 Emission Rate (Lb/Hr)1,850 7,636 7,636 7,636 7,636 777 370 7,636 7,636(Lb/MMBtu)0.502.06 2.06 2.06 2.060.21 0.102.06 2.06(Ton/Yr)7,293 30,100 30,100 30,100 30,100 3,063 1,459 30,100 30,100Uncontrolled NOx (Lb/Hr)1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665 1,665(Lb/MMBtu)0.450.45 0.45 0.45 0.45 0.45 0.45 0.45 0.45(Lb Moles/Hr)55.48 55.48 55.48 55.48 55.48 55.48 55.48 55.48 55.48(Tons/Yr)6,563 6,563 6,563 6,563 6,563 6,563 6,563 6,563 6,563NOx Removal Rate (%)0.0%22.2%37.8%37.8%84.4%0.0%0%0.0%0%(Lb/Hr)0 370 629 629 1,406 0 0 0 0(Lb Moles/Hr)0.00 12.33 20.96 20.96 46.85 0.00 0.00 0.00 0.00(Ton/Yr)0 1,459 2,479 2,479 5,542 0 0 0 0NOx Emission Rate (Lb/Hr)1,665 1,295 1,036 1,036 259 1,665 1,665 1,665 1,665(Lb/MMBtu)0.450.35 0.28 0.28 0.070.45 0.45 0.45 0.45(Ton/Yr)6,563 5,105 4,084 4,084 1,021 6,563 6,563 6,563 6,563Uncontrolled Fly Ash (Lb/Hr)16,362 348 348 348 348 348 348 348 348(Lb/MMBtu)4.422 0.094 0.094 0.094 0.094 0.094 0.094 0.094 0.094(Lb Moles/Hr)545.2 11.6 11.6 11.6 11.6 11.6 11.6 11.6 11.6(Tons/Yr)64,498 1,371 1,371 1,371 1,371 1,371 1,371 1,371 1,371Fly Ash Removal Rate (%)97.87%0.00%0.00%0.00%0.00%0.00%0.00%57.45%84.04%(Lb/Hr)16,014 0 0 0 0 0 0 200 292(Ton/Yr)63,127 0 0 0 0 0 0 788 1,152Fly Ash Emission Rate (Lb/Hr)348 348 348 348 348 348 348 148 55(Lb/MMBtu)0.0940.094 0.094 0.094 0.094 0.094 0.0940.040 0.015(Ton/Yr)1,371 1,371 1,371 1,371 1,371 1,371 1,371 583 219ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 2Tune Exist.LNB w/OFAROFA SNCR SCRWet FGD w/WasteLiquorWet FGDw/Soda AshEnhancements toExisting ESPFabric FilterCase1 2 3 4 5 7 8 9 10ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlGeneral Plant DataAnnual Operation (Hours/Year)7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884Annual On-Site Power Plant Capacity Factor0.900.90 0.90 0.90 0.90 0.90 0.90 0.90 0.90Economic FactorsInterest Rate (%)7.10%7.10%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%7.10%7.10%Plant Economic Life (Years)2020 20 20 20 20 20 20 20Installed Capital CostsNOx Emission Control System ($2006)00 14,747,608 15,788,530 92,007,264000 0SO2 Emission Control System ($2006)00 0 0 0 4,499,83414,499,4640 0PM Emission Control System ($2006)00 0 0 0 0 0 13,299,508 80,297,031Total Emission Control Systems ($2006)0 0 14,747,608 15,788,530 92,007,2644,499,83414,499,46413,299,508 80,297,031NOx Emission Control System ($/kW)0 0 45 48 279 0 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 14 44 0 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 40 243Total Emission Control Systems ($/kW)0 0 45 48 279 14 44 40 243Total Fixed Operating & Maintenance CostsOperating Labor ($)00000 0 0 0 0Maintenance Material ($)0 0 48,000 75,000 156,000 21,900 21,900 0 48,666Maintenance Labor ($)0 0 72,000 112,500 234,000 14,600 14,600 0 72,999Administrative Labor ($)00000 0 0 0 0Total Fixed O&M Cost ($)0 0 120,000 187,500 390,000 36,500 36,500 0 121,665Annual Fixed O&M Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Water CostMakeup Water Usage (Gpm)0 0 0 0 0 66 66 0 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 37,985 37,985 0 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Waste LiquorSoda Ash None NoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 0.00 80.00 370 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.000 0.040 0.185 0.000Molar Stoichiometry0.00 0.00 0.00 0.45 1.00 1.02 1.02 0.00 0.00Reagent Purity (Wt.%)100%100%100%100%100%90%100%100%90%Reagent Usage (Lb/Hr)0 0 0 425 588 1,835 2,49800First Year Reagent Cost ($)0 0 0 620,285 927,219 0 787,613 0 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000167 0 0 0 1,799SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000 104 104 3,000 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 501,000 0 0 0 187,096Annual SCR Catalyst / Bag Cost Esc. Rate (%)2.00%2.00%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 3,224 6,821 0 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 309,228 654,306 0 0Annual Waste Disposal Cost Esc. Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Auxiliary Power CostAuxiliary Power Requirement (% of Plant Output)0.00%0.00%1.36%0.10%0.60%0.10%0.10%0.00%0.62%(MW)0.00 0.00 4.47 0.33 1.99 0.33 0.33 0.00 2.06Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 1,763,730 130,086 786,035 130,086 130,086 0 812,052Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls2 of 2Input TablesTable 1 - CasesExisting1 2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESP N/A Fabric Filter2 Dave Johnston Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/ADry FGD w/FabricFilterWet FGD w/FabricFilter N/A Fabric Filter3 Jim Bridger Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter4 Jim Bridger Unit 2Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter5 Jim Bridger Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter6 Jim Bridger Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/A Upgraded Wet FGDFlue GasConditioning Fabric Filter7 Naughton Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCRDry FGD w/ESP &Higher S CoalDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter8 Naughton Unit 2Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCRDry FGD w/ESP &Higher S CoalDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter9 Naughton Unit 3Current OperationTune Exist. LNBw/OFA ROFA SNCR SCR N/AWet FGD w/WasteLiquor Wet FGD w/Soda AshEnhancements toExisting ESP Fabric Filter10 WyodakCurrent Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Upgraded Dry FGDDry FGD w/FabricFilter Wet FGD N/A Fabric FilterTable 2 - Unit Design and Coal CharacteristicsNOx SO2 PM Boiler DesignNet PowerOutput (kW)Net Plant HeatRate (Btu/kW-Hr) CoalHeating Value,HHV (Btu/Lb)Sulfur Content(Wt.%)AshContent(Wt.%)1 Dave Johnston Unit 3None None ESP3-Cell Burner, OpposedWall-Fired PC250,000 11,200Dry Fork PRB7,784 0.47% 5.01%2 Dave Johnston Unit 4Windbox Mods.Lime Added to VenturiScrubber Venturi Scrubber Tangential-Fired PC360,000 11,390Dry Fork PRB7,784 0.47% 5.01%3 Jim Bridger Unit 1LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%4 Jim Bridger Unit 2LNB - TFS 2000 Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%5 Jim Bridger Unit 3LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%6 Jim Bridger Unit 4LNCFS-1 &Windbox Mods. Wet FGD ESP Tangential-Fired PC530,000 11,320Bridger MineUnderground9,660 0.58% 10.30%7 Naughton Unit 1None None ESP Tangential-Fired PC160,000 11,563Kemmerer Mine9,800 0.58% 5.00%8 Naughton Unit 2None None ESP Tangential-Fired PC210,000 11,428Kemmerer Mine9,800 0.58% 5.00%9 Naughton Unit 3LNCFS II LNB Wet FGD ESP Tangential-Fired PC330,000 11,212Kemmerer Mine9,875 1.02% 5.25%10 WyodakLNB Dry FGD ESP Opposed Wall-Fired PC365,000 12,877Clovis Point Mine8,050 0.65% 7.46%Coal QualityUnit DesignCurrent Emission Control SystemsIndex No. Name of UnitIndex No. Name of Unit | Case --->NOx Control SO2 Control PM ControlEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 5Table 3 - EmissionsControlledSO2 Controlled NOxControlledPM Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9 Case 101 Dave Johnston Unit 32.91 0.70 0.030 0.24 0.190.190.07 0.220.150.10N/A0.0152 Dave Johnston Unit 40.50 0.40 0.061 0.15 0.150.120.07 N/A0.150.10N/A0.0153 Jim Bridger Unit 10.27 0.45 0.045 0.24 0.220.200.07 N/AN/A0.100.030 0.0154 Jim Bridger Unit 20.27 0.24 0.074 0.24 0.220.200.07 N/AN/A0.100.030 0.0155 Jim Bridger Unit 30.27 0.45 0.057 0.24 0.220.200.07 N/AN/A0.100.030 0.0156 Jim Bridger Unit 40.17 0.45 0.030 0.24 0.220.200.07 N/AN/A0.100.030 0.0157 Naughton Unit 12.91 0.58 0.056 0.24 0.260.190.07 0.410.150.100.040 0.0158 Naughton Unit 22.91 0.54 0.064 0.24 0.260.190.07 0.410.150.100.040 0.0159 Naughton Unit 30.50 0.45 0.094 0.35 0.280.280.07 N/A0.210.100.040 0.01510 Wyodak0.50 0.31 0.0300.230.200.180.070.320.160.10N/A0.015Table 4 - Case 1 O&M Costs (Current Operation)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None - -2 Dave Johnston Unit 4-$ -$ -$ $ - -None - -3 Jim Bridger Unit 1-$ -$ -$ $ - -None - -4 Jim Bridger Unit 2-$ -$ -$ $ - -None - -5 Jim Bridger Unit 3-$ -$ -$ $ - -None - -6 Jim Bridger Unit 4-$ -$ -$ $ - -None - -7 Naughton Unit 1-$ -$ -$ $ - -None - -8 Naughton Unit 2-$ -$ -$ $ - -None - -9 Naughton Unit 3-$ -$ -$ $ - -None - -10 Wyodak-$ -$ -$$ --None--Table 5 - Case 2 O&M Costs (LNB w/OFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 40,000$ 60,000$ -$ -None - -2 Dave Johnston Unit 4-$ 36,000$ 54,000$ $ - -None - -3 Jim Bridger Unit 1-$ 28,000$ 42,000$ $ - -None - -4 Jim Bridger Unit 2-$ -$ -$ $ - -None - -5 Jim Bridger Unit 3-$ 28,000$ 42,000$ $ - -None - -6 Jim Bridger Unit 4-$ 28,000$ 42,000$ $ - -None - -7 Naughton Unit 1-$ 32,000$ 48,000$ $ - -None - -8 Naughton Unit 2-$ 32,000$ 48,000$ $ - -None - -9 Naughton Unit 3-$ -$ -$ $ - -None - -10 Wyodak-$ 24,000$ 36,000$$ --None--SO2 Control Emission Rates (Lb/MMBtu)Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsPM Emission Rates (Lb/MMBtu)Index No. Name of UnitCurrent Emission Rates (Lb/MMBtu) NOx Control Emission Rates (Lb/MMBtu)Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls2 of 5Table 6 - Case 3 O&M Costs (Mobotec ROFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 60,000$ 90,000$ -$ -None - 2.762 Dave Johnston Unit 4-$ 54,000$ 81,000$ $ - -None - 4.333 Jim Bridger Unit 1-$ 42,000$ 63,000$ $ - -None - 6.414 Jim Bridger Unit 2-$ 42,000$ 63,000$ $ - -None - 6.415 Jim Bridger Unit 3-$ 42,000$ 63,000$ $ - -None - 6.416 Jim Bridger Unit 4-$ 42,000$ 63,000$ $ - -None - 6.417 Naughton Unit 1-$ 48,000$ 72,000$ $ - -None - 1.428 Naughton Unit 2-$ 48,000$ 72,000$ $ - -None - 2.619 Naughton Unit 3-$ 48,000$ 72,000$ $ - -None - 4.4710 Wyodak-$ 36,000$ 54,000$$ --None-5.22Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 98,000$ 147,000$ -$ -Urea 0.41 0.232 Dave Johnston Unit 4-$ 105,000$ 157,500$ $ - -Urea 0.45 0.333 Jim Bridger Unit 1-$ 123,000$ 184,500$ $ - -Urea 0.45 0.534 Jim Bridger Unit 2-$ 95,000$ 142,500$ $ - -Urea 0.45 0.535 Jim Bridger Unit 3-$ 122,000$ 183,000$ $ - -Urea 0.45 0.526 Jim Bridger Unit 4-$ 123,000$ 184,500$ $ - -Urea 0.45 0.537 Naughton Unit 1-$ 83,000$ 124,500$ $ - -Urea 0.45 0.168 Naughton Unit 2-$ 93,000$ 139,500$ $ - -Urea 0.51 0.229 Naughton Unit 3-$ 75,000$ 112,500$ $ - -Urea 0.45 0.3310 Wyodak-$ 93,000$ 139,500$--Urea0.450.34Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.AnnualSCRCatalyst Replace.(m3)Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 155,000$ 232,500$ -$ -Anhydrous NH31.00 1281.572 Dave Johnston Unit 4-$ 166,000$ 249,000$ $ - -Anhydrous NH31.00 1232.293 Jim Bridger Unit 1-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 1983.284 Jim Bridger Unit 2-$ 162,000$ 243,000$ $ - -Anhydrous NH31.00 1983.255 Jim Bridger Unit 3-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2003.226 Jim Bridger Unit 4-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2143.367 Naughton Unit 1-$ 132,000$ 198,000$ $ - -Anhydrous NH31.00 670.988 Naughton Unit 2-$ 160,000$ 240,000$ $ - -Anhydrous NH31.00 1011.349 Naughton Unit 3-$ 156,000$ 234,000$ $ - -Anhydrous NH31.00 1671.9910 Wyodak-$ 181,000$ 271,500$$ --Anhydrous NH31.001602.42Annual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls3 of 5Table 9 - Case 6 O&M Costs (Dry FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 -2.492 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 1506,128$ 587,643$ 391,762$ $ - 120Lime1.40 -1.648 Naughton Unit 2506,128$ 860,174$ 573,044$ $ - 165Lime1.40 -2.259 Naughton Unit 3-$ -$ -$ $ - -Lime- --10 Wyodak-$ 21,900$ 14,600$-25Lime1.10-0.11Table 10 - Case 7 O&M Costs (Dry FGD w/Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 1,4573.882 Dave Johnston Unit 4506,128$ 1,102,288$ 734,858$ $ - 248Lime1.10 1,7984.543 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 1506,128$ 632,660$ 459,286$ $ - 120Lime1.15 8652.668 Naughton Unit 2506,128$ 905,190$ 640,568$ $ - 165Lime1.15 1,1933.639 Naughton Unit 3-$ 21,900$ 14,600$ $ - 66Waste Liquor1.02 -0.3310 Wyodak-$ 30,660$ 20,440$-30Lime1.10-0.15Table 11 - Case 8 O&M Costs (Wet FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3809,804$ 1,182,587$ 788,391$ -$ 230Lime1.02 -3.452 Dave Johnston Unit 4809,804$ 1,430,784$ 953,856$ $ - 330Lime1.02 1,7986.293 Jim Bridger Unit 1-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.534 Jim Bridger Unit 2-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.535 Jim Bridger Unit 3-$ 25,550$ 17,033$ $ - 52Soda Ash1.02 -0.526 Jim Bridger Unit 4-$ 25,550$ 17,033$ $ - 27Soda Ash1.02 -0.537 Naughton Unit 1809,804$ 963,589$ 642,393$ $ - 160Lime1.05 -2.408 Naughton Unit 2809,804$ 1,226,386$ 817,591$ $ - 220Lime1.05 -3.309 Naughton Unit 3-$ 21,900$ 14,600$ $ - 66Soda Ash1.02 -0.3310 Wyodak303,677$ 328,496$ 218,998$$ -82Lime1.02-1.75Variable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsEY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ -$ $ - -None- --10 Wyodak-$ -$ -$--None---Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak-$ 48,666$ 72,999$$ --None-1,7982.06Table 14 - Major Materials Design and Supply Costs2 3 4 5 6 7 8 9 101 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 $ - $ 18,359,0002 Dave Johnston Unit 4$ 2,673,501 $ 4,343,192 $ 7,171,085 $ 66,200,000 $ - $ 137,267,000 $ 178,174,384 $ - $ 30,853,5303 Jim Bridger Unit 1$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0004 Jim Bridger Unit 2$ - $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0005 Jim Bridger Unit 3$ 2,981,982 $ 6,056,955 $ 9,419,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0006 Jim Bridger Unit 4$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 93,009,000 $ - $- $ 3,549,000 $ - $ 29,814,0007 Naughton Unit 1$ 2,502,123 $ 2,675,792 $ 7,257,000 $ 37,292,000 $ 39,617,991 $ 57,979,051 $ 56,500,308 $ 800,000 $ 18,361,0608 Naughton Unit 2$ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 54,775,108 $ 76,278,497 $ 77,695,625 $ 800,000 $ 21,503,3899 Naughton Unit 3$ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $ 2,772,643 $ 8,934,073 $ 8,194,701 $ 49,476,27810 Wyodak$ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 16,487,985 $ 41,146,026 $ 58,619,840 $ - $ 20,106,000Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsNOx Control SO2 Control PM ControlIndex No. Name of Unit | Case --->EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls5 of 5CAPITAL COSTNaughton Unit 3CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control SystemCAPITAL COST COMPONENTFactor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source CostLNB w/OFA or ROFALNB w/OFA ROFA LNB w/OFA LNB w/OFAMajor Materials Design and SupplyVendor $0Vendor $4,351,377Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$085.3%$3,713,19485.3%$085.3%$085.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$051.7%$2,249,32051.7%$051.7%$051.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$1,305,4130.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$013.2%$576,48513.2%$013.2%$013.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$016.4%$714,73516.4%$016.4%$016.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$012.2%$531,67112.2%$012.2%$012.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal$0 $13,442,195$0 $0 $0 $0 $0 $0 $0Contingency12.8%$030.0%$1,305,41312.8%$012.8%$012.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $0 $14,747,608 $0 $0 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $11,203,578 S&L Report $67,373,000 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0Contingency20.0%$020.0%$020.0%$2,240,71610.0%$6,737,30020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$626,6165.6%$3,768,1725.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$5,690,9978.4%$08.4%$08.4%$08.4%$08.4%$0Boiler Reinforcement (Allowance)0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Sales Tax1.1%$01.1%$01.1%$123,4631.1%$742,4501.1%$01.1%$01.1%$01.1%$01.1%$0Escalation0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Contingency on Adders2.8%$02.8%$02.8%$314,4840.0%$02.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$1,279,67311.4%$7,695,34411.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $15,788,530 $92,007,264 $0 $0 $0 $0 $0Dry or Wet FGD, FGC or Fabric FilterDry FGD Dry FGD w/FF Wet FGD FGC Fabric FilterMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $2,772,643 S&L Report $8,934,073 S&L Report $8,194,701 S&L Report $49,476,278Contingency20.0%$020.0%$020.0%$020.0%$020.0%$020.0%$554,52920.0%$1,786,81520.0%$1,638,94020.0%$9,895,256Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$05.6%$155,0745.6%$499,6835.6%$458,3305.6%$2,767,208EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$08.4%$234,2058.4%$754,6618.4%$692,2068.4%$4,179,261Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$78,0222.8%$251,4052.8%$230,5992.8%$1,392,262Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$01.1%$30,5551.1%$98,4531.1%$90,3061.1%$545,229Escalation10.1%$010.1%$010.1%$010.1%$010.1%$010.1%$280,28710.1%$903,14510.1%$828,40210.1%$5,001,557Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$77,8282.8%$250,7792.8%$230,0252.8%$1,388,799Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$011.4%$316,69111.4%$1,020,45011.4%$935,99911.4%$5,651,181Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 $4,499,834 $14,499,464 $13,299,508 $80,297,031Fabric Filter8LNCFS II LNBFabric Filter10LNCFS II LNBWet FGDLNCFS II LNBWet FGDEnhancements to Existing ESPWet FGD w/Waste LiquorN/ASNCRSO2 ControlWet FGD w/Soda AshWet FGD w/Soda AshESPTune Exist. LNB w/OFAWet FGDESP ESPROFAWet FGDLNCFS II LNBWet FGD w/Waste LiquorParameterTune Exist. LNB w/OFA ROFA SCRESPLNCFS II LNBN/AESPSNCRWet FGDESP ESPSCRWet FGDPM ControlEnhancements toNOx Control45 76293EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 1Naughton Unit 3Tune Exist. LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 ----------2 2015 ----------3 2016 ----------4 2017 ----------5 2018 ----------6 2019 ----------7 2020 ----------8 2021 ----------9 2022 ----------10 2023 ----------11 2024 ----------12 2025 ----------13 2026 ----------14 2027 ----------15 2028 ----------16 2029 ----------17 2030 ----------18 2031 ----------19 2032 ----------20 2033 ----------Present Worth----------Naughton Unit 3ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 120,000----1,763,7301,763,7301,402,9083,286,6381,3262 2015 122,400----1,799,0041,799,0041,402,9083,324,3121,3413 2016 124,848----1,834,9841,834,9841,402,9083,362,7401,3564 2017 127,345----1,871,6841,871,6841,402,9083,401,9371,3725 2018 129,892----1,909,1181,909,1181,402,9083,441,9171,3886 2019 132,490----1,947,3001,947,3001,402,9083,482,6981,4057 2020 135,139----1,986,2461,986,2461,402,9083,524,2931,4218 2021 137,842----2,025,9712,025,9711,402,9083,566,7211,4389 2022 140,599----2,066,4902,066,4901,402,9083,609,9971,45610 2023 143,411----2,107,8202,107,8201,402,9083,654,1391,47411 2024 146,279----2,149,9772,149,9771,402,9083,699,1641,49212 2025 149,205----2,192,9762,192,9761,402,9083,745,0891,51013 2026 152,189----2,236,8362,236,8361,402,9083,791,9331,52914 2027 155,233----2,281,5722,281,5721,402,9083,839,7131,54915 2028 158,337----2,327,2042,327,2041,402,9083,888,4491,56816 2029 161,504----2,373,7482,373,7481,402,9083,938,1601,58817 2030 164,734----2,421,2232,421,2231,402,9083,988,8651,60918 2031 168,029----2,469,6472,469,6471,402,9084,040,5841,63019 2032 171,390----2,519,0402,519,0401,402,9084,093,3381,65120 2033 174,817----2,569,4212,569,4211,402,9084,147,1461,673Present Worth1,466,142----21,548,99021,548,99014,747,60837,762,741762(% of PW)3.9% 0.0% 0.0% 0.0% 0.0% 57.1% 57.1% 39.1% 100.0%1 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls1 of 4Naughton Unit 3SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 187,500-620,285--130,086750,3711,501,9292,439,7999842 2015 191,250-632,690--132,688765,3781,501,9292,458,5579923 2016 195,075-645,344--135,341780,6861,501,9292,477,6899994 2017 198,977-658,251--138,048796,2991,501,9292,497,2041,0075 2018 202,956-671,416--140,809812,2251,501,9292,517,1101,0156 2019 207,015-684,844--143,625828,4701,501,9292,537,4141,0237 2020 211,155-698,541--146,498845,0391,501,9292,558,1231,0328 2021 215,379-712,512--149,428861,9401,501,9292,579,2471,0409 2022 219,686-726,762--152,416879,1791,501,9292,600,7931,04910 2023 224,080-741,298--155,465896,7621,501,9292,622,7711,05811 2024 228,561-756,124--158,574914,6981,501,9292,645,1881,06712 2025 233,133-771,246--161,746932,9921,501,9292,668,0531,07613 2026 237,795-786,671--164,981951,6511,501,9292,691,3751,08514 2027 242,551-802,404--168,280970,6841,501,9292,715,1641,09515 2028 247,402-818,452--171,646990,0981,501,9292,739,4291,10516 2029 252,350-834,821--175,0791,009,9001,501,9292,764,1791,11517 2030 257,397-851,518--178,5801,030,0981,501,9292,789,4241,12518 2031 262,545-868,548--182,1521,050,7001,501,9292,815,1741,13519 2032 267,796-885,919--185,7951,071,7141,501,9292,841,4391,14620 2033 273,152-903,638--189,5111,093,1481,501,9292,868,2291,157Present Worth2,290,847-7,578,547--1,589,3729,167,91915,788,53027,247,297549(% of PW)8.4% 0.0% 27.8% 0.0% 0.0% 5.8% 33.6% 57.9% 100.0%Naughton Unit 3SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 390,000-927,219501,000-786,0352,214,2548,752,45111,356,7052,0492 2015 397,800-945,763511,020-801,7552,258,5398,752,45111,408,7902,0583 2016 405,756-964,679521,240-817,7912,303,7108,752,45111,461,9162,0684 2017 413,871-983,972531,665-834,1462,349,7848,752,45111,516,1062,0785 2018 422,149-1,003,652542,299-850,8292,396,7808,752,45111,571,3792,0886 2019 430,592-1,023,725553,144-867,8462,444,7158,752,45111,627,7572,0987 2020 439,203-1,044,199564,207-885,2032,493,6098,752,45111,685,2632,1088 2021 447,987-1,065,083575,492-902,9072,543,4828,752,45111,743,9202,1199 2022 456,947-1,086,385587,001-920,9652,594,3518,752,45111,803,7492,13010 2023 466,086-1,108,113598,741-939,3842,646,2388,752,45111,864,7752,14111 2024 475,408-1,130,275610,716-958,1722,699,1638,752,45111,927,0222,15212 2025 484,916-1,152,880622,931-977,3352,753,1468,752,45111,990,5132,16313 2026 494,614-1,175,938635,389-996,8822,808,2098,752,45112,055,2742,17514 2027 504,507-1,199,457648,097-1,016,8202,864,3738,752,45112,121,3312,18715 2028 514,597-1,223,446661,059-1,037,1562,921,6618,752,45112,188,7082,19916 2029 524,889-1,247,915674,280-1,057,8992,980,0948,752,45112,257,4332,21217 2030 535,386-1,272,873687,766-1,079,0573,039,6968,752,45112,327,5332,22418 2031 546,094-1,298,330701,521-1,100,6383,100,4908,752,45112,399,0352,23719 2032 557,016-1,324,297715,551-1,122,6513,162,5008,752,45112,471,9662,25020 2033 568,156-1,350,783729,862-1,145,1043,225,7508,752,45112,546,3572,264Present Worth4,764,963-11,328,6266,121,144-9,603,65827,053,42892,007,264123,825,6541,117(% of PW)3.8% 0.0% 9.1% 4.9% 0.0% 7.8% 21.8% 74.3% 100.0%2 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls2 of 4Naughton Unit 3Wet FGD w/Waste LiquorYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 36,50037,985--309,228130,086477,298428,059941,8572232 2015 37,23038,744--315,412132,688486,844428,059952,1332253 2016 37,97439,519--321,721135,341496,581428,059962,6152284 2017 38,73440,310--328,155138,048506,513428,059973,3062305 2018 39,50841,116--334,718140,809516,643428,059984,2112336 2019 40,29841,938--341,412143,625526,976428,059995,3342357 2020 41,10442,777--348,241146,498537,516428,0591,006,6792388 2021 41,92743,632--355,206149,428548,266428,0591,018,2522419 2022 42,76544,505--362,310152,416559,231428,0591,030,05624410 2023 43,62045,395--369,556155,465570,416428,0591,042,09624611 2024 44,49346,303--376,947158,574581,824428,0591,054,37624912 2025 45,38347,229--384,486161,746593,461428,0591,066,90325213 2026 46,29048,174--392,176164,981605,330428,0591,079,68025514 2027 47,21649,137--400,019168,280617,436428,0591,092,71225815 2028 48,16050,120--408,019171,646629,785428,0591,106,00526116 2029 49,12451,122--416,180175,079642,381428,0591,119,56426517 2030 50,10652,145--424,503178,580655,229428,0591,133,39426818 2031 51,10853,188--432,994182,152668,333428,0591,147,50127119 2032 52,13054,251--441,653185,795681,700428,0591,161,89027520 2033 53,17355,337--450,486189,511695,334428,0591,176,566278Present Worth445,947464,091--3,778,1001,589,3725,831,5634,499,83410,777,343127(% of PW)4.1% 4.3% 0.0% 0.0% 35.1% 14.7% 54.1% 41.8% 100.0%Naughton Unit 3Wet FGD w/Soda AshYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 36,50037,985787,613-654,306130,0861,609,9901,379,3023,025,7925192 2015 37,23038,744803,365-667,393132,6881,642,1901,379,3023,058,7225243 2016 37,97439,519819,433-680,740135,3411,675,0341,379,3023,092,3115304 2017 38,73440,310835,821-694,355138,0481,708,5351,379,3023,126,5715365 2018 39,50841,116852,538-708,242140,8091,742,7051,379,3023,161,5165426 2019 40,29841,938869,589-722,407143,6251,777,5591,379,3023,197,1605487 2020 41,10442,777886,980-736,855146,4981,813,1111,379,3023,233,5175548 2021 41,92743,632904,720-751,592149,4281,849,3731,379,3023,270,6025619 2022 42,76544,505922,814-766,624152,4161,886,3601,379,3023,308,42856710 2023 43,62045,395941,271-781,957155,4651,924,0871,379,3023,347,01057411 2024 44,49346,303960,096-797,596158,5741,962,5691,379,3023,386,36458012 2025 45,38347,229979,298-813,548161,7462,001,8211,379,3023,426,50658713 2026 46,29048,174998,884-829,819164,9812,041,8571,379,3023,467,45059414 2027 47,21649,1371,018,862-846,415168,2802,082,6941,379,3023,509,21360215 2028 48,16050,1201,039,239-863,343171,6462,124,3481,379,3023,551,81160916 2029 49,12451,1221,060,024-880,610175,0792,166,8351,379,3023,595,26161617 2030 50,10652,1451,081,224-898,222178,5802,210,1721,379,3023,639,58062418 2031 51,10853,1881,102,849-916,187182,1522,254,3751,379,3023,684,78663219 2032 52,13054,2511,124,906-934,511185,7952,299,4631,379,3023,730,89563920 2033 53,17355,3371,147,404-953,201189,5112,345,4521,379,3023,777,927648Present Worth445,947464,0919,622,943-7,994,2191,589,37219,670,62514,499,46434,616,036297(% of PW)1.3% 1.3% 27.8% 0.0% 23.1% 4.6% 56.8% 41.9% 100.0%3 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls3 of 4Naughton Unit 3Enhancements to Existing ESPYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 -------1,265,1531,265,1531,6062 2015 -------1,265,1531,265,1531,6063 2016 -------1,265,1531,265,1531,6064 2017 -------1,265,1531,265,1531,6065 2018 -------1,265,1531,265,1531,6066 2019 -------1,265,1531,265,1531,6067 2020 -------1,265,1531,265,1531,6068 2021 -------1,265,1531,265,1531,6069 2022 -------1,265,1531,265,1531,60610 2023 -------1,265,1531,265,1531,60611 2024 -------1,265,1531,265,1531,60612 2025 -------1,265,1531,265,1531,60613 2026 -------1,265,1531,265,1531,60614 2027 -------1,265,1531,265,1531,60615 2028 -------1,265,1531,265,1531,60616 2029 -------1,265,1531,265,1531,60617 2030 -------1,265,1531,265,1531,60618 2031 -------1,265,1531,265,1531,60619 2032 -------1,265,1531,265,1531,60620 2033 -------1,265,1531,265,1531,606Present Worth-------13,299,50813,299,508844(% of PW)0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0% 100.0%Naughton Unit 3Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 121,665--187,096-812,052999,1487,638,4828,759,2957,6022 2015 124,099--190,838-828,2931,019,1317,638,4828,781,7117,6213 2016 126,581--194,655-844,8591,039,5147,638,4828,804,5767,6414 2017 129,112--198,548-861,7561,060,3047,638,4828,827,8987,6625 2018 131,694--202,519-878,9911,081,5107,638,4828,851,6867,6826 2019 134,328--206,569-896,5711,103,1407,638,4828,875,9507,7037 2020 137,015--210,700-914,5021,125,2037,638,4828,900,7007,7258 2021 139,755--214,914-932,7921,147,7077,638,4828,925,9447,7479 2022 142,550--219,213-951,4481,170,6617,638,4828,951,6937,76910 2023 145,401--223,597-970,4771,194,0747,638,4828,977,9577,79211 2024 148,309--228,069-989,8871,217,9567,638,4829,004,7477,81512 2025 151,275--232,630-1,009,6851,242,3157,638,4829,032,0727,83913 2026 154,301--237,283-1,029,8781,267,1617,638,4829,059,9447,86314 2027 157,387--242,029-1,050,4761,292,5047,638,4829,088,3737,88815 2028 160,535--246,869-1,071,4851,318,3557,638,4829,117,3717,91316 2029 163,745--251,807-1,092,9151,344,7227,638,4829,146,9497,93817 2030 167,020--256,843-1,114,7731,371,6167,638,4829,177,1187,96518 2031 170,361--261,980-1,137,0691,399,0487,638,4829,207,8917,99119 2032 173,768--267,219-1,159,8101,427,0297,638,4829,239,2798,01920 2033 177,243--272,564-1,183,0061,455,5707,638,4829,271,2958,046Present Worth1,486,489--2,285,911-9,921,53212,207,44480,297,03193,990,9644,079(% of PW)1.6% 0.0% 0.0% 2.4% 0.0% 10.6% 13.0% 85.4% 100.0%4 of 4\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls4 of 4EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 1 of 1First Year Cost for Air Pollution Control Options02,000,0004,000,0006,000,0008,000,00010,000,00012,000,000Tune Exist.LNB w/OFAROFA SNCR SCR Wet FGDw/Waste LiquorWet FGDw/Soda AshEnhancementsto Existing ESPFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\App A_PCorp Naughton 3 BART Economic Analysis_02-01-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options020,000,00040,000,00060,000,00080,000,000100,000,000120,000,000140,000,000Tune Exist.LNB w/OFAROFA SNCR SCR Wet FGDw/Waste LiquorWet FGDw/Soda AshEnhancementsto Existing ESPFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B 

# 2006 Wyoming BART Protocol