# Final Report



# BART Analysis for

Naughton Unit 1

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Naughton Unit 1

Submitted to



# PacifiCorp

Decmeber 2007

# Executive Summary

Background

In response to the Regional Haze Rule 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 1 (hereafter referred to as Naughton 1). A BART analysis has

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

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

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

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

goal unless it is determined that an alternativ e control level is jus tified based on a careful

consideration of the statutory f actors. BART emissions limits mu st be achieved within 5 years

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

was assumed for this analysis.

In completing the BART analysis, technology 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:

− Low NO

x 

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

− Rotating opposed fire air (ROFA)

− LNBs with selective non-catal ytic reduction system (SNCR)

− LNBs with selective catalytic reduction (SCR) system

• SO 2 

# emission controls:

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

(ESP)

− Dry FGD system with new fabric filter

− Wet FGD system with existing ESP

• PM 10 

# emission controls:

− Sulfur trioxide (SO 3 

# ) injection flue gas conditioning (FGC) system on existing ESP

− Polishing fabric filter

− Replacement fabric filter

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR NAUGHTON UNIT 1



# 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 co ntrol 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 1 will be the low sulfur and high sulfur P&M

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

characteristics to bituminous coal in many of the parameters influencing NO

x 

# formation.

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR NAUGHTON UNIT 1



# considered the higher nitrogen content and differe nt combustion characteristics of PRB coals,

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

on NO

x 

# formation and achievable emission rates.



# Recommendations

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

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

identified as Scenario 1 throughout this report.



# NO

x 

# Emission Control

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

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

CH2M HILL recommends LNBs with OFA as BART for Naughton 1, based on the projected

significant reduction in NO

x 

# emissions, reasonable control co sts, and the advantages of no

additional power requirements or non-ai r quality environmental impacts. NO

x 

# reductions are

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

been installed on Unit 2. This selection of new LNBs with OFA at Naughton 1 is projected to

attain an emission rate at or below 0. 26 pound (lb) per million British thermal units

(MMBtu).



# SO 2 

# Emission Control

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

Naughton 1, assuming use of coal containing no more than 1.02 percent sulfur by weight,

based on the significant reduction in SO 2 

# emissions, reasonable control costs, and the

advantages of minimal additional powe r requirements and minimal non-air quality

environmental impacts. This appr oach is projected to have a SO 2 

# emission rate of

0.41 lb per MMBtu.



# PM 10



# Emission Control

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

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

in PM 10 

# emissions, reasonable control costs, and the advantages of mi nimal additional power

requirements and no 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 1 at Class I areas. The Class I areas potentially affected are located

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

The Class I areas include th e following wilderness areas:

• Bridger Wilderness Area

• Fitzpatrick Wilderness Area

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR NAUGHTON UNIT 1



# Because Naughton 1 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

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

conditioning for enhanced ESP performanc e and higher sulfur coal. As indicated

previously, this scenario represents CH 2M HILL’s preliminary BART recommendation.

• Scenario 2 : New LNB with OFA modifi cations, a dry FGD system, and new fabric filter.

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

fabric filter.

• Scenario 4 : New LNB with OFA modifications a nd SCR, wet FGD system, flue gas

conditioning for enhanced ESP performance, and a new stack.

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

were compared using a least-cost enve lope, as outlined in the draft EPA 1990 New Source

Review Workshop Manual

. 1



# Least-cost Envelope Analysis

EPA has adopted the least-cost envelope an alysis methodology as an accepted methodology

for selecting the most reasonable, cost-effec tive controls. Incremental cost-effectiveness

comparisons focus on annualized cost and emi ssion reduction differences between dominant

alternatives. The dominant set of control altern atives is determined by generating what is

called the envelope of least-cost alternatives. This is a graphical plot of total annualized costs

for a total emissions reductions for all control alternatives identified in the BART analysis.

To evaluate the impacts of the modeled 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 envel ope analysis validate the sele ction of Scenario 1, based on

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

following reasons:

• Scenario 2 (LNB with OFA, dry FGD, and fabric filter) is to the left of the curve formed

by the dominant control altern ative scenario, which indicates a scenario with lower

improvement and/or higher costs.

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC ES-5 

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

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

reduction.

• While Scenario 4 (LNB with OFA and SCR, wet FGD, ESP with SO 3 

# injection and new

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

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

Scenario 1 represents BART for Naughton 1.



# Just-Noticeable Differences in Atmospheric Haze

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

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

distinguished by the average pers on. Therefore, the modeling anal ysis results indicate that

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

expected under any of the cont rol scenarios. Thus, the resu lts indicate that only minimal

discernable visibility improvements may resu lt, even though PacifiCorp will spend many

millions of dollars at this single unit, and over $1 billion when considering its entire fleet of

coal-fired power plants.

# Contents

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

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

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

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

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

3.2.1 BART NO

x 

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

3.2.2 BART SO 2 

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

3.2.3 BART PM 10 

# Analysis ................................................................ 3-19

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

5.2.1 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 

# iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC iv 

# Tables

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 Coal Characteristics Comparison

3-2 NO

x 

# Control Technology Projected Emission Rates

3-3 NO

x 

# Control Cost Comparison

3-4 SO 2 

# Control Technology Emission Rates

3-5 SO 2 

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

3-6 PM 10 

# Control Technology Emission Rates

3-7 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 Wilderness Area Class I Agent Control Data

5-2 Fitzpatrick Wilderness Area Class I Area Control Data

5-3 Bridger Wilderness Area Class I Agent Incremental Data

5-4 Fitzpatrick Wilderness Area Class I Area Incremental Data

Figures

3-1 Illustration of the Effect of 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 Vari ous 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 Wilderness Area Class I Area Days Reduction

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

# Percentile dV

Reduction

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

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

# Percentile dV

Reduction

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

acfm Actual Cubic Feet per Minute

BACT Best Availa ble 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

LOI Loss on Ignition

MMBtu Million British Thermal Units

MM5 Mesoscale Meteorologi cal Model, Version 5

MW Megawatt

N 2 

# Nitrogen

NO

x 

# Nitrogen Oxide

(NH 4 

# ) 2 

# SO 4 

# Ammonium Sulfate

OFA Over-fire Air

P&M P&M Kemmerer Mine

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC vi 

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

SCR Selective Catalytic Reduction System

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction System

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 WDEQ to submit the BART

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

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

source. This revised report—submitted in Oc tober 2007—incorporates ed itorial revisions and

new model revisions since the January 2007 version.

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

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

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

which the State has estimated will be 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.

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

the identified facilities:

• The cost of the controls

• The energy and non-air quality 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 1 by

CH2M HILL for PacifiCorp. The analys is was performed for the pollutants NO

x 

# , sulfur

dioxide (SO 2 

# ), and particulate matter less than 10 micrometers in aerodynamic diameter

(PM 10 

# ), because they are the primary criteria pollutants that a ffect 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\BART_NAUGHTON1_OCT2007_FINAL.DOC 1-1

# 2.0 Present Unit Operation

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

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

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

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

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

control SO

x 

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

control particulate matter. The unit uses good combustion practices for NO

x 

# control.

Naughton 1 began operation in 1963. Its current economic depreciation life is through 2032;

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

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

for Naughton 1 of 20 years from the installation date of any new or modified BART-related

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

needed to allow the unit at Naughton 1 to operate until 2034.

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

The main source of coal burned at Naughton 1 is the P&M Kemmerer Mine (P&M). This

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

of the parameters influencing 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 1 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\BART_NAUGHTON1_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 2-2 

# TABLE 2-1



# Present Unit Operation

Naughton 1

General Plant Data

Site Elevation (feet above mean sea level) 6939

Stack Height (feet) 200

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

Stack Exit Temperature (degrees Fahrenheit) 280

Stack Exit Velocity (feet/second) 76

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

minute) 701,784

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

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

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 160

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

[kWh])(100% load) 10,680 (as measured by fuel

throughput)

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

Type of Boiler Tangentially fired

Boiler Fuel Coal

Coal Sources P & M Kemmerer Mine

Coal Heating Value (Btu per lb) (a) 

# 9,800

Coal Sulfur Content (wt. percentage) (a) 

# 0.58

Coal Ash Content (wt. percentage) (a) 

# 5.00

Coal Moisture Content (wt. %) (a) 

# 21.0

Coal Nitrogen Content (wt. %) 1.3

Current NO

x 

# Controls Good combustion practices

Pre-project NO

x 

# Emission Rate (lb per MMBtu) 0.58

Current Sulfur Dioxide Controls Use of low sulfur coal

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

Current PM 10 

# Controls (b) 

# Electrostatic precipitator

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

NOTES:

(a) 

# Coal characteristics vary between coal sources

(b) 

# PM 10 

# refers to particulate matter less than 10 micrometers in aerodynamic diameterBART ANALYSIS FOR NAUGHTON UNIT 1TABLE 2-2Coal Sources and CharacteristicsNaughton 1Ultimate Analysis (% dry basis)MinesMoist.(%)Ash(%)VolatileMatter(%)FixedCarbon(%)BritishthermalunitsperpoundSulfur(%)HydrogenCarbonSulfurNitrogenOxygenAshLow Sulfur P&M MineAverage20.904.4933.4641.1799700.595.0671.670.731.3315.355.86Standard 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\BART_NAUGHTON1_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 al l 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 co ntrol 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 equipment in use at the source (which affects the

applicability of options 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\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR NAUGHTON UNIT 1



# • Step 5 – Evaluate Visibility Impacts

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

of BART

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

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

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

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

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

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

implementation date).



# 3.2.1 BART NO

x 

# Analysis

NO

x 

# formation in coal-fired boilers is a comple x process depends on a number of variables,

including operating conditi ons, equipment design, and coal characteristics.

Formation of NO

x



# During coal combustion, NO

x 

# forms in three 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 vola tile matter, and part is retained in the solid

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

oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen (N 2 

# ). A

smaller part of NO

x 

# formation is caused by high temperatur e fixation of atmospheric nitrogen

in the combustion air (thermal NO

x 

# ). 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 ac cording to their degree of metamorphism in the

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

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

x 

# emissions than

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

fixed carbon to volatile matter ra tio (fuel ratio), coal oxygen cont ent, and rank are good relative

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

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

low-NO

x 

# burners (LNBs), sub-bituminous coals create a longer 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-bitu minous C and demonstrate the high reactivity and

low NO

x 

# production characteristics previously desc ribed. Based on data from the Energy

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR NAUGHTON UNIT 1



# infer PRB origin and characteristics. Emissions standards differentiating between bituminous

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

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

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

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

including most of the low NO

x 

# forming characteristics. Coals from the P&M mine fall into this

category.

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

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

“the property of softening when it is heated to above about 400 degrees Celsius (°C) in a

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

temperature.” Because the agglomerating prop erty of coals is th e result of particles

transforming into a plastic or semi-liquid state wh en heated, it reflects a change in surface area

of the particle. Thus, with the application of heat, agglomerating coals would tend to develop a

non-porous surface while the surface of non-aggl omerating coals would become even more

porous with combustion. As shown by Figure 3- 1, the increased porosity provides more

particle surface area resulti ng in more favorable combustion conditions. This

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

controlling NO

x 

# by allowing less air to be introduced dur ing the initial ignition portion of the

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

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

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

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

easier to control NO

x 

# emissions do not exist for the coal used at Naughton 1.

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR NAUGHTON UNIT 1



# FIGURE 3-1



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

Naughton 1



# Table 3-1 shows key NO

x 

# forming characteristics of a typical PRB coal compared to low sulfur

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

representative western bituminous coal.

TABLE 3-1



# Coal Characteristics Comparison

Naughton 1

Parameter PRB P&M

Low

Sulfur P&M High

Sulfur Twentymile

Nitrogen (% dry) 1.10 1.33 1.22 1.85

Oxygen (% dry) 16.2 15.35 14.57 7.19

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR NAUGHTON UNIT 1



# As shown in Table 3-1, although P&M is classi fied 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 

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

These characteristics indicate that higher NO

x 

# formation is likely with coal from the P&M

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

between a typical PRB 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 graphically illustrate the relationship of nitrogen and oxygen 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 typical bituminous and sub-bituminous coal,

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

Twentymile is used to graphically illustrate achievement of the BART-presumptive 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 the P&M mine that is used at

Naughton 1, and indicates the average NO

x 

# emission rate of 0.57 lb per MMBtu achieved

during 2005. The “LNB with OFA” data point indicates the projected NO

x 

# emission rate of

0.24 after installation of new LNBs and OFA.

Figures 3-2 and 3-3 both demonstrate th at for Naughton 1 with a TFS2000 low NO

x 

# emission

system installed and burning P&M coal. The likely NO

x 

# emission rate will be closer to the

bituminous end (0.28) of the BART presumptive NO

x 

# limit range than to the sub-bituminous

BART-presumptive NO

x 

# limit of 0.15 lb per MMBtu.

All these factors are consistent with th e observed sustainable emission rate of

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR NAUGHTON UNIT 1



# FIGURE 3-2



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

x 

# Limits

Naughton 1

PRB Subbituminous Present

LNB w/OFA Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 0.6

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

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



# Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu



# FIGURE 3-3



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

x 

# Limits

Naughton 1

PRB Subbituminous Twentymile Bituminous Present

LNB w/OFA

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 0.6

6.00 8.00 10.00 12.00 14.00 16.00 18.00

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



# p tive Limit - 0.28 lb/MMBtu

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



# JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR NAUGHTON UNIT 1



# Coal quality characteristics also impact the 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 variability in the quality of coals at mines, such as

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

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

x 

# formation have been

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

achieving and maintaining low NO

x 

# emissions with pulverized co al on a consistently shorter

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

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

parameters, along with a “design” coal, are 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 subsequently changed, conflicts with and between

other performance i ssues can result.

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

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

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

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

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

flows and distribution to reduce NO

x 

# emissions using LNBs and OFA, original boiler design

restrictions again limit the m odifications 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 grindability index (Hardgr ove) of the coal. Finer coal

particles promote release of vola tiles and assist char burnout due to more surface area exposed

to air. NO

x 

# reduction with high-volatile coals is impr oved with greater fineness and with proper

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

and service as pulverizer grinding surfaces wear.

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

content of the coals, and th e grindability index—are take n into account, this analysis

demonstrates that for the coal used at Na ughton 1, LNB technology refe rred to in the EPA’s

presumptive BART analysis will achieve NO

x 

# reductions similar the rates identified for

tangentially fired boilers that burn bituminous coals. The current NO

x 

# emission rate at

Naughton 1 is 0.58 lb per MMBtu.

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 Naught on 1, including those control t echnologies identified as Best

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR NAUGHTON UNIT 1



# an effort to identify potentially appl icable emission control technologies. NO

x 

# emissions from

Naughton 1 are currently contro lled through the use of good com bustion practices and OFA.

The following potential NO

x 

# control technology options were considered:

• New/modified LNB with advanced OFA

• Mobotec rotating opposed fire air (ROFA)

• Conventional selective non-catalytic reduction (SNCR) system

• Selective catalytic reduction (SCR) system

Step 2: Eliminate Technically Infeasible Options

For Naughton 1 technical feasibil ity will primarily be determin ed by physical constraints and

boiler configuration. Naughton 1 has an uncontrolled NO

x 

# emission rate of 0.58 lb per MMBtu.

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

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

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

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

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

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

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

it reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 40 to 60 percent have been

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

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

problematic.

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

with projected NO

x 

# emission rates.

TABLE 3-2



# NO

x 

# Control Technology Projected Emission Rates

Naughton 1

Technology Projected Emission Rate (pounds

per million British thermal units)

Bituminous Presumptive Limit 0.28

Low-NO

x

# Burner (LNB) with

Over-fire Air (OFA) 0.24

Rotating Opposed Fire Air 0.26

LNB with OFA and Selective

Non-catalytic Reduction

System 0.19

LNB with OFA and Selective

Catalytic Reduction System 0.07

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR NAUGHTON UNIT 1



# Step 3: Evaluate Control 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 expect ed or guaranteed emission rates; however, the

proposals include inherent uncer tainties. These proposals are us ually prepared in a limited

timeframe, may be based on incomplete information, 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.

New LNBs with OFA System. The mechanism used to lower NO

x 

# with LNBs is to stage the

combustion process and provide a fuel-rich condi tion 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 N 2 

# instead of NO

x 

# . Additional air (or OFA) is then

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

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

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

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

expected NO

x 

# emission rate of 0.24 lb per MMBtu. Paci fiCorp has indicated that this rate

corresponds to a vendor guarantee plus an a dded operating margin, no t a vendor prediction,

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

emission rate represents a si gnificant reduction from the NO

x 

# emission rate of

0.58 lb per MMBtu.

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

states that “the flue gas volume of the furn ace is set in rotation by as ymmetrically placed air

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

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

reduces the maximum temperature of the fl ames and increases heat absorption. The

combustion air is also mixed more effectivel y.” A typical ROFA inst allation would have a

booster fan(s) to supply the hi gh-velocity air to the ROFA bo xes, and Mobotec would propose

one 1,900-horsepower fan for Naughton 1.

Mobotec expects to achieve a NO

x 

# emission rate of 0.24 lb per MMBtu using ROFA

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

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

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

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

of computational fluid dynamics modeling wi ll determine the quantity and location of new

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

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

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

supervisor during inst allation 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 post-contro l modeling scenarios.

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR NAUGHTON UNIT 1



# SNCR. Selective non-catalytic re duction is generally used to achieve modest NO

x 

# reductions on

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

urea—is injected into the fu rnace within a temperature rang e 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 re alistic 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 because of greater reagent consumption. To reduce reagent costs,

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

of achieving a projected NO

x 

# emission rate of 0.24 lb per MMBtu

. At a further reduction of

20 percent in NO

x 

# emission rates for SNCR would result in a projected emission rate of

0.19 lb per MMBtu.

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

ongoing parasitic costs, the operating 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 it uses a catalyst 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 required for SNCR , the reaction takes plac e on the surface of a

vanadium/titanium-based catalyst at a temperatur e range between 580°F to 750°F. As a result

of the catalyst, the SCR process is more effi cient than SNCR. The most common type of SCR

is the high-dust configuration where the cata lyst is located downstream from the boiler

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

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

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

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

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

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

the basis for analysis at Naughton 1.

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

it is generally more cost effective to reduce NO

x 

# emission levels as much as possible through

combustion modifications to minimize the cataly st surface area and ammonia requirements of

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

LNBs and OFA, providing a NO

x 

# emission rate of 0.24 lb per MMBtu, would be installed in

conjunction with the SCR. The S&L de sign basis results in a projected NO

x 

# emission rate of

0.07 lb per MMBtu. Additional catalyst su rface was included in the SCR design to

accommodate the characteristics of the coal used at Naughton 1.

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR NAUGHTON UNIT 1



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

NO

x 

# emissions needed to consistent ly achieve compliance with an established goal, a review of

typical NO

x 

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

review, it was noted that NO

x 

# emissions can vary significan tly around an average emissions

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

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

and so forth.

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

follows:

1. Establish expected NO

x 

# emissions value from vendor.

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

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

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

NO

x 

# emissions are.

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

boiler efficiency or forced-draft fan power usag e. Therefore, these tec hnologies will not have

energy impacts.

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

ROFA fan.

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

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

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

based on the S&L Study.

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

in CO emissions and unburned carbon in th e ash, commonly referred to as loss on ignition

would be the same or lower than previous le vels. Installation of LN Bs with OFA may also

result in higher carbon monoxide emissions a nd 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 amm onia, especially if

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-12 

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

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

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

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

system was obtained from Mobotec to which cons truction 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 co sts are presented in

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

TABLE 3-3



# NO

x 

# Control Cost Comparison

Naughton 1

Factor Low NOx

Burner with

(LNB) with

Over-fire Air

(OFA) Rotating

Opposed

Fire Air LNB with

OFA and

Selective

Non-catalytic

Reduction

System LNB with

OFA and

Selective

Catalytic

Reduction

System

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

Total First Year Fixed & Variable

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

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

Power Consumption (megawatts)

-- 1.4 0.2 1.0

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

NO

x

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

Tons NO

x

# Removed per Year 2,480 2,334 2,844 3,719

First Year Average Control Cost ($ per

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

Incremental Control Cost ($ per Ton of

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



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

for Naughton 1, based on its significant reduction in NO

x 

# emissions, reasonable control cost,

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

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

appropriate as BART for NO

x 

# emissions from the coals combusted at Naughton 1.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 1FIGURE 3-4First Year Control Cost for NOxAir Pollution Control OptionsNaughton 105001,0001,5002,0002,5003,0003,5004,0004,5005,000LNB w/OFAROFALNB w/OFA & SNCRLNB w/OFA & SCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR NAUGHTON UNIT 1



# 3.2.2 BART SO 2 

# Analysis

Sulfur dioxide 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 1 is described in

this section.

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 1, including control

technologies identified as BACT or lowest achievable emission rate by permitting agencies

across the United States.

The following potential SO 2 

# control technology options were considered:

• Dry flue gas desulfurizati on (FGD) with existing ESP

• Dry FGD with new fabric filter

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

Step 2: Eliminate Technically Infeasible Options

Naughton 1 currently has an uncontrolled SO 2 

# emission rate of approximately

1.20 lb per MMBtu.

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

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

wheel causes the lime slurry to separate into ve ry fine droplets that in termix with the flue

gas. The SO 2 

# in the flue gas reacts with the calcium in the lime slurry to form calcium sulfate

in the form of particulate matter. At Naught on 1, this dry particulate matter would be

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

typically produces a dry waste produ ct suitable for landfill disposal.

Dry FGD with the existing ESP is projected to achieve 85 percent SO 2 

# removal using the

lower sulfur coal. This w ould result in a controlled SO 2 

# emission rate from Naughton 1 equal

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

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

Similarly, with coal having a higher sulfur content of 1.02 percent, the controlled SO 2 

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

limit of 0.15 lb per MMBtu.

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

filter located downstream of the lime spray dr yer; by using the lower sulfur coal, an

87.5 percent SO 2 

# removal is projected, allowing the facility to meet a limit of

0.15 lb per MMBtu.

However, if higher sulfur coal at 1.02 percent sulfur is used, the controlled SO 2 

# emission rate

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

0.15 lb per MMBtu.

Wet Lime/Limestone FGD. Wet SO 2 

# scrubbers operate by flowi ng the flue gas upward through

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR NAUGHTON UNIT 1



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

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

reagent reacts with the SO 2 

# in the flue gas to form calcium sulfite and/or calcium sulfate,

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

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

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

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

variations include using a jet bubb ling reactor as a combination SO 2 

# absorber and calcium

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

Wet lime/limestone scrubbing is project ed to achieve 90 to 95 percent SO 2 

# removal. At

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

or high sulfur coal is used with the existing ESP.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

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

for Naughton 1.

TABLE 3-4



# SO 2 

# Control Technology Emission Rates

Naughton 1

Control Technology Projected Sulfur Dioxide Emission Rate

(pounds per million Br itish thermal units)

Bituminous Presumptive Limit 0.15

Dry Flue Gas Desulfurizat ion (FGD) with existing

Electrostatic Precipitator (ESP) 0.41

Dry FGD with fabric filter 0.15

Wet FGD with existing ESP and new stack 0.10



# Step 4: Evaluate Impacts and Document the Results

This step involves the 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. A dry FGD system with the existing E SP has the advantage of requiring less

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

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

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

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

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

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

when compared to wet FGD technology:

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR NAUGHTON UNIT 1



# • Sulfuric Acid Mist. Sulfur trioxide (SO 3 

# ) in the flue gas, which condenses to liquid

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

spray dryer system. Wet scrubbers capt ure less than 40 to 60 percent of SO 3 

# and may

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

coal is burned in a unit to remove the balance of SO 3 

# . Otherwise, the emission rate

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

result in a visible plume afte r the vapor plume dissipates.

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

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

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

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

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

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

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

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

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

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

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

metals and may require special considerations for disposal.

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

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

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

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

that needs to be disposed.

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

a dry waste material and requi ring less makeup water in the ab sorber. Given that water is

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

FGD is major advantage for this technology.

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

# removed for each technology

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

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

Appendix A.

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-17



# TABLE 3-5



# SO 2 

# Control Cost Comparison (Incremental to Existing FGD System)

Naughton 1

Factor Dry Flue Gas

Desulfurization

(FGD) with

Electrostatic

precipitator

(ESP) Dry FGD

with Fabric

Filter Wet FGD

Total Installed Capital

Costs $64.3 million $109.0 million $91.7 million

Total First Year Fixed &

Variable Operation and

Maintenance Costs $5.0 million $4.2 million $4.7 million

Total First Year

Annualized Cost $11.1 million $14.5 million $13.5 million

Power Consumption

(megawatts) 1.6 2.7 2.4

Annual Power Usage

(1000 megawatt-hours per

year) 13.0 20.9 18.9

Sulfur Dioxide Design

Control Efficiency 80.1% 87.3% 91.5%

Tons Sulfur Dioxide

Removed per Year 12,061 7,530 7,895

First Year Average Control

Cost ($ per ton of Sulfur

Dioxide Removed) 918 1,929 1,705

Incremental Control Cost

($ per ton of Sulfur Dioxide

Removed) 918 1,929 1,705



# Preliminary BART Selection. CH2M HILL recommends the comb ination of using a dry FGD

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

1.02 percent by weight, as BART for Naughton 1 based on its significant reduction in 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 1FIGURE 3-5First Year Control Cost for SO2Air Pollution Control OptionsNaughton 105001,0001,5002,0002,500Dry FGD w/ESP & Higher S CoalDry FGD w/Fabric FilterWet FGD w/ESPAir Pollution Control Option

Control Cost ($/Ton SO2 Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC3-18

# BART ANALYSIS FOR NAUGHTON UNIT 1



# 3.2.3 BART PM 10



# Analysis

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

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

direct current voltage, and attracting these par ticles to grounded collecti on plates. A layer of

collected particulate matter forms on the coll ecting plates and is re moved by periodically

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

are removed periodically by the fly ash-handli ng system. Historicall y, the ESP at Naughton 1

has controlled PM 10 

# emissions to levels of 0.056 lb per MMBtu.

The BART analysis for PM 10 

# emissions from Naughton 1 is desc ribed in this section. For the

modeling analysis in Section 4, PM 10 

# was used as an indicator for particulate matter, and

PM 10 

# includes PM 2.5 

# as a subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

Three retrofit control technologies have been identified for additional particulate matter

control:

• Flue gas conditioning (FGC)

• Polishing fabric filter

• Replacement fabric filter

Step 2: Eliminate Technically Infeasible Options

FGC. If the fly ash from coal has high resistiv ity, such as fly ash from sub-bituminous coal,

the ash is not collected effectiv ely in a small ESP. This is because the high resistivity makes

the particles less willing to accep t an electrical charge. Addi ng FGC, which is typically

accomplished by injection of SO 3 

# , will lower the resistivity of th e particles so that they will

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

account for large improvements in collection efficiency for small ESPs.

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

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

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

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

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

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

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

jet fabric filter (3.5 to 4:1).

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

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

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

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

considered to be cost-effective in the analysis.

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-19

# BART ANALYSIS FOR NAUGHTON UNIT 1



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

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

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

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

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

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

to reduce particulate matter emission s to approximately 0.015 lb per MMBtu.

The PM 10 

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

TABLE 3-6



# PM 10



# Control Technology Emission Rates

Naughton 1

Control Technology Projected PM 10 

# Emission Rate

(pounds per million British

thermal units)

Flue Gas Conditioning 0.040

Polishing Fabric Filter 0.015

Replacement Fabric Filter 0.015



# Step 4: Evaluate Impacts and Document the Results

This step involves the 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 1 would require approximately 1.0 MW of power,

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

annual plant capacity factor.

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

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

COHPAC polishing fabric filter or FGC system.

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-20

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 3-21 

# TABLE 3-7



# PM 10



# Control Cost Comparison

Naughton 1

Factor Flue Gas

Conditioning Polishing Fabric Filter

Total Installed Capital Costs $1.3 million $29.8 million

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

Total First Year Annualized Cost $0.2 million $3.4 million

Power Consumption (megawatts) 0.1 1.01

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

Particulate Matter Design Control Efficiency 28.6% 73.2%

Tons PM Removed per Year 117 299

First Year Average Control Cost

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

Incremental Control Cost

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



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

BART for Naughton 1, based on th e significant reduction in PM 10 

# emissions, reasonable

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

non-air quality environmental impacts.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 1FIGURE 3-6First Year Control Cost for PM Air Pollution Control OptionsNaughton 102,0004,0006,0008,00010,00012,00014,00016,00018,00020,000Flue Gas ConditioningFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC3-22

# 4.0 BART Modeling Analysis

4.1 Model Selection

CH2M HILL used a Gaussian puff dispersi on modeling system (CAL PUFF) to assess the

visibility impacts of emissions from Naughton 1 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 1 Plant. These wilderness areas include the following:

• Bridger Wilderness Area

• Fitzpatrick Wilderness Area

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, refine d mode. The following version numbers of the

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

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

CH2M HILL used the CALMET model to 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 1 facili ty and allow for a 50-kilometer buffer around

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

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

instructed otherwise by the Wyoming Departme nt of Environmental Quality—Air Quality

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

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

prepared by the WDEQ-AQD.

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

large extent of the domain. The latitude of the projection 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\BART_NAUGHTON1_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 1



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

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

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

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

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

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 1

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500



# 4.2.2 CALMET Input Data

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

WDEQ-AQD provided 12-kilometers resolution Mesoscale Mete orological 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\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-4 

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

generate a Step 1 wind field, and further 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 that are in the domain. The surface data were

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

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

SMERGE preprocessor and CALMET.

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

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

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

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

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

Digital Elevation Model data, which 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 1



# 4.2.3 Validation of CALMET Wind Field

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

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

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

conditions, as depicted in surface and upper-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 1.



# 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 mode ling reflect those that are in place under the

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

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



# 4.3.3 Emission Rates

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-7 

# Regulations and Guidelines for Best Availabl e Retrofit Technology De terminations; 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 particulate matter control technologies

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

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

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

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

Sections 3, 4, and 5.

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

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

represents CH2M HILL’s preliminary BART recommendation.

• Scenario 2 : New LNB with OFA modifi cations, a dry FGD system, and new fabric filter.

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

fabric filter.

• Scenario 4 : New LNB with OFA modifications a nd SCR, wet FGD system, flue gas

conditioning for enhanced ESP performance, and a new stack.

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

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

protocol, elemental carbon stack emissions and organic aerosol emissi ons were not modeled.TABLE 4-2BART Model Input DataNaughton 1BaselinePost-control Scenario 1 Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Model Input DataCurrent Operations withElectrostatic Precipitator(ESP)Low-NOxBurner (LNB) withOver-fire air (OFA), Dry Flue GasDesulfurization (FGD), ESPLNB with OFA, Dry FGD, NewFabric FilterLNB with OFA and SelectiveCatalytic Reduction System(SCR), Dry FGD, New FabricFilterLNB with OFA and SCR, WetFGD, ESP with Sulfur TrioxideInjection, New StackSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])2,220759278278185Nitrogen Oxide (NOx) Stack Emissions (lb/hr)1,073444444130130PM10Stack Emissions (lb/hr)104 74.0 27.8 27.8 74.0Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)44.531.815.815.831.8Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)59.142.211.911.942.2Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 34.0 1.67 1.67 2.41 29.2H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 33.3 1.63 1.63 2.36 28.6Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)0.432.13(NH4)2SO4as SO4Stack Emissions (lb/hr)0.311.55(NH4)HSO4Stack Emissions (lb/hr)0.743.70(NH4)HSO4as SO4Stack Emissions (lb/hr)0.623.09Total Sulfate (SO4) (lb/hr)33.3 1.63 1.63 3.28 33.3Stack ConditionsStack Height (meters)61 61 61 61 152Stack Exit Diameter (meters)4.27 4.27 4.27 4.27 4.88Stack Exit Temperature(Kelvin) 411350342.6342.6323Stack Exit Velocity (meters per second)28.119.6924.624.618.1NOTES:(a)Based on AP-42, Table 1.1-6, the coarse particulates are countedas a percentage of PM10. This equates to 43 percent ESP and 57 percent Baghouse.(b)Based on AP-42, Table 1.1-6, the fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent Baghouse.Total Sulfate (SO4) (lb/hr) = H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4as SO4Stack Emissions (lb/hr) + (NH4)HSO4as SO4Stack Emissions (lb/hr)

# BART ANALYSIS FOR NAUGHTON UNIT 1



# 4.3.5 Modeling Process

The CALPUFF modeling for the control techno logy options for Naughton 1 followed this

sequence:

• Model pre-control (baseline) emissions

• Model preferred post-control scenario (if applicable)

• Determine degree of visibility improvement

• Model other control scenarios

• Determine degree of visibility improvement

• Factor visibility results into the BART five-step evaluation



# 4.3.6 Receptor Grids

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

along the boundary and in the interior of each 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 values were used to calculate the delta deciview

( 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 Me thod 6 was used to determine th e visibility impacts. Monthly

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

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

Air Modeling Protocol (Appendi x B) lists the monthly relati ve humidity factors for the

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

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

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

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-9

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 4-10 

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

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

by the guidance table annual concen trations, the 20 percent best da ys dV value for that area

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

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

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

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

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

TABLE 4-3



# Average Natural Levels of Aerosol Components

Naughton 1

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Fitzpatrick and Bridger Class I Wilderness Areas

Ammonium Sulfate 0.045

Ammonium Nitrate 0.038

Organic Carbon 0.178

Elemental Carbon 0.008

Soil 0.189

Coarse Mass 1.136

NOTE:

Taken from Table 6 of the Wyom ing 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 1.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Naughton 1 for the baseli ne and its post-contr ol Scenario 1. In

addition, three other scenarios were modeled. The post-control scenarios 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 1. Some scenarios included controls that would not be able to

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

that the selection of an alternat ive control device may be warranted.

Baseline and post-control 98 th 

# percentile results were greater than 0.5 Δ dV for the Bridger

Wilderness Area, and Fitzpatrick Wilderness Area. The 98 th 

# percentile results for each

Class I area are presented in Table 4-4.BART ANALYSIS FOR NAUGHTON UNIT 1TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I AreasNaughton 1ScenarioTotal First YearAnnualizedCostClass I AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)No. of Days Above0.5 Deciview (dV)Cost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Costper Reduction in No.of Days Above0.5 dV2001BridgerWilderness Area(WA)4.6491.77748----Baseline: current operation with Electrostatic Precipitator(ESP)Fitzpatrick WA2.7690.96623----$12,042,621Bridger WA2.0150.64414$10,628,968$354,195Scenario 1: Low-NOxBurner (LNB) with Over-fire Air (OFA),dry Flue Gas Desulfurization (FGD), ESP$12,042,621Fitzpatrick WA1.1920.3573$19,774,419$602,131$15,299,091Bridger WA1.5190.4797$11,786,665$373,149$19,736,182$465,210Scenario 2: LNB with OFA,dry FGD, fabric filter$15,299,091Fitzpatrick WA0.8640.2352$20,928,989$728,528$26,692,377$3,256,470$21,262,911Bridger WA0.6920.2171$13,630,071$452,402$22,762,672$993,970Scenario 3: LNB with OFA and Selective CatalyticReduction (SCR) System, dry FGD, fabric filter$21,262,911Fitzpatrick WA0.3990.1190$25,103,791$924,474$51,412,241$2,981,910$20,399,907Bridger WA1.2920.3874$14,676,192$463,634NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$20,399,907Fitzpatrick WA0.5970.1531$25,092,137$927,269NANA2002Bridger WA3.5751.76341----Baseline: current operation with ESPFitzpatrick WA3.1900.88118----$12,042,621Bridger WA1.4240.74114$11,783,386$446,023Scenario 1: LNB with OFA, dry FGD, ESP$12,042,621Fitzpatrick WA1.1240.3145$21,239,190$926,355$15,299,091Bridger WA1.0340.6359$13,563,024$478,097$30,721,415$651,294Scenario 2: LNB with OFA,dry FGD, fabric filter$15,299,091Fitzpatrick WA0.8340.2052$22,631,791$956,193$29,875,872$1,085,490$21,262,911Bridger WA0.5050.2741$14,279,994$531,573$16,520,277$745,478Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$21,262,911Fitzpatrick WA0.3890.1050$27,400,659$1,181,273$59,638,200$2,981,910$20,399,907Bridger WA0.7750.2883$13,830,445$536,840NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$20,399,907Fitzpatrick WA0.5910.1081$26,390,565$1,199,995NANAJMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC4-11BART ANALYSIS FOR NAUGHTON UNIT 1JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC4-12TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I AreasNaughton 1ScenarioTotal First YearAnnualizedCostClass I AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)No. of Days Above0.5 Deciview (dV)Cost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Costper Reduction in No.of Days Above0.5 dV2003Bridger WA4.0141.79745----Baseline: current operation with ESPFitzpatrick WA2.3870.84020----$12,042,621Bridger WA1.5590.69416$10,918,061$415,263Scenario 1: LNB with OFA, dry FGD, ESP$12,042,621Fitzpatrick WA0.9270.3615$25,141,171$802,841$15,299,091Bridger WA1.3060.4937$11,732,432$402,608$16,201,343$361,830Scenario 2: LNB with OFA,dry FGD, fabric filter$15,299,091Fitzpatrick WA0.6340.2663$26,653,469$899,947$34,278,632$1,628,235$21,262,911Bridger WA0.5720.2343$13,603,910$506,260$23,026,332$1,490,955Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$21,262,911Fitzpatrick WA0.3440.1230$29,655,385$1,063,146$41,705,035$1,987,940$20,399,907Bridger WA0.9640.3974$14,571,362$497,559NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$20,399,907Fitzpatrick WA0.3090.1350$28,936,038$1,019,995NANA3-Year AveragesBridger WA1.77944.7Baseline: current operation with ESPFitzpatrick WA0.89620.3$12,042,621Bridger WA0.69314.7$11,088,970$401,421Scenario 1: LNB with OFA, dry FGD, ESP$12,042,621Fitzpatrick WA0.3444.3$21,829,524$752,664$15,299,091Bridger WA0.5367.7$12,304,899$413,489$20,697,903$465,210Scenario 2: LNB with OFA,dry FGD, fabric filter$15,299,091Fitzpatrick WA0.2352.3$23,168,740$849,950$29,967,515$1,628,235$21,262,911Bridger WA0.2421.7$13,831,035$494,486$20,285,102$993,970Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$21,262,911Fitzpatrick WA0.1160.0$27,260,142$1,045,717$49,836,936$2,555,923Scenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$20,399,907Bridger WA0.3573.7$14,349,290$497,559NANA$20,399,907Fitzpatrick WA0.1320.7$26,713,104$1,037,283NANANOTES:Scenario 4 produces worse results than Scenario 3.Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $12,042,621 /(1.910 - 0.695) = $9,911,622Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: =$12,042,621 / (58 - 19) = $308,785

# 5.0 Preliminary Assessment and

Recommendations

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

modeling analysis completed for Naughton 1, th e preliminary recommended BART controls

for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# New LNBs OFA system for NO

x 

# control

• 

# Lime spray dryer FGD for SO 2 

# control and a coal sulfur limit of 1.02 weight percent

• 

# Addition of FGC ahead of the existi ng ESP for particulate matter 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 effectiv eness has been conducted. This analysis was

performed in the following way:

• First, the control option scen arios are ranked in ascending or der of annualized total costs

as shown in Tables 5-1 and 5-2. The incremen tal cost effectivene ss data, expressed per

day and per dV reduction, repres ents 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 leas t-cost control option scenarios is plotted

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR NAUGHTON UNIT 1



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

impacted by the operation of Naughton 1.

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

number of days above 0.5 dV. The EPA states that “In calculating 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 consider ed in the derivation of incremental cost

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

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

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

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

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

difference in emissions reduction.

TABLE 5-1



# Bridger Wilderness Area Class I Agent Control Data

Naughton 1

Scenario Controls 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

# Burner (LNB) with

Over-fire Air (OFA), Dry Flue

Gas Conditioning (FGD),

ESP 1.09 30.0 $12. 0 $11.1 $0.4

2 LNB with OFA, Dry FGD,

New Fabric Filter 1.24 37.0 $15. 3 $12.3 $0.4

3 LNB with OFA and Selective

Catalytic Reduction (SCR)

System, Dry FGD, Fabric

Filter 1.54 43.0 $21. 3 $13.8 $0.5

4 LNB with OFA and SCR,

Wet FGD, New stack 1.42 41.0 $20. 4 $14.3 $0.5

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR NAUGHTON UNIT 1



# TABLE 5-2



# Fitzpatrick Wilderness Area Class I Area Control Data

Naughton 1

Scenario Controls 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$

per dV

Reduced) Cost per

Reduction in

No. of Days

Above 0.5 dV

(Million$ per

Day Reduced)

Base Current Operation

with Electrostatic

Precipitator (ESP) 0.00 0.0 $0.0 $0.0 $0.0

1 Low-NO

x

# Burner

(LNB) with Overfire Air (OFA), Dry

Flue Gas

Conditioning

(FGD), ESP 0.55 16.0 $12. 0 $21.8 $0.8

2 LNB with OFA,

Dry FGD, New

Fabric Filter 0.66 18.0 $15. 3 $23.2 $0.8

3 LNB with OFA

and Selective

Catalytic

Reduction (SCR)

System, Dry FGD,

Fabric Filter 0.78 20.3 $21. 3 $27.3 $1.0

4 LNB with OFA &

SCR, Wet FGD,

New stack 0.76 19.7 $20. 4 $26.7 $1.0

TABLE 5-3



# Bridger Wilderness Area Class I Agent Incremental Data

Naughton 1

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$ per Day) Incremental

Cost

Effectiveness

(Million$ per

dV)

Baseline and Scenario 1 30.00 1.09 $0.40 $11.1

Scenario 1 and Scenario 2 7.0 0.16 $0.5 $20.7

Scenario 1 and Scenario 3 13.0 0.45 $0.7 $20.4

Scenario 1 and Scenario 4 11.0 0.34 $0.8 $24.9

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR NAUGHTON UNIT 1



# TABLE 5-4



# Fitzpatrick Wilderness Area Class I Area Incremental Data

Naughton 1

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$ per Day) Incremental

Cost

Effectiveness

(Million$ per

dV)

Baseline and Scenario 1 16.00 0.55 $0.75 $21.8

Scenario 1 and Scenario 2 2.0 0.11 $1.6 $30.0

Scenario 1 and Scenario 3 4.3 0.23 $2.1 $40.4

Scenario 1 and Scenario 4 3.7 0.21 $2.3 $39.4

FIGURE 5-1



# Least-cost Envelope Bridger Wilderne ss Area Class I Area Days Reduction

Naughton 1

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4



# $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0

0 5 10 15 20 25 30 35 40 45 50



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



# JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR NAUGHTON UNIT 1



# FIGURE 5-2



# Least-cost Envelope Bridger W ilderness Area Class I Area 98 th



# Percentile dV Reduction

Naughton 1

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



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

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80



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



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick Wilder ness Area Class I Area Days Reduction

Naughton 1

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4



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

0 5 10 15 20 25



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



# JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR NAUGHTON UNIT 1



# FIGURE 5-4



# Least-cost Envelope Fitzpatrick W ilderness Area Class I Area 98 th



# Percentile dV Reduction

Naughton 1

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90



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



# 5.1.2 Analysis of Results

Results of the least-cost analysis, shown in Ta bles 5-1 to 5-4 and Figur es 5-1 to 5-4 (on the

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

visibility improvements.

The other scenarios were eliminated because of the following reasons:

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

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

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

improvement and a cost per dV reduction.

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

projected improvement is less than 0.5 dV, and the cost increment is excessive. It is also

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

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

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

# percentile

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

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

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

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR NAUGHTON UNIT 1

JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 5-7 

# at the Bridger WA. However, the incremental co st effectiveness for Scenario 2 compared to

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

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

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

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

confirms that Scenario 1 re presents the proper BART cont rol technology for Naughton 1;

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



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

CH2M HILL recommends LNB with OFA as BART for Naughton 1, based on the projected

significant reduction in NO

x 

# emissions, reasonable control co sts, and the advantages of no

additional power requirements or non-ai r quality environmental impacts. NO

x 

# reductions are

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

been installed on Unit 2. This selection of new LNBs with OFA at Naughton 1 is projected to

attain an emission rate below 0.26 lb per MMBtu.



# 5.2.2 SO 2 

# Emission Control

CH2M HILL recommends a dry lime FGD sy stem as BART for Naughton 1, assuming use

of coal containing no more than 1.02 percen t sulfur by weight, based on the significant

reduction in SO 2 

# emissions, reasonable control cost s, and the advantages of minimal

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



# 5.2.3 PM 10



# Emission Control

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

existing ESP as BART for Naughton 1, base d on the significant reduction in PM 10 

# emissions,

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

no non-air quality environmental impacts.



# 5.3 Just-Noticeable Differences in Atmospheric Haze

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

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

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

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

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

be expected under any of the s cenarios. Thus, the results in dicate 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

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

natural obscuration were to reduce the visibil ity impacts modeled for the Naughton 1 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 Guide lines 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

.

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and Nonattainment Area Permitting . Draft. October 1990.

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

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

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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

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JMS EY102007001SLC\BART_NAUGHTON1_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios7Index 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 $ 12,042,621 N/A N/AN/A N/A $ 12,042,621 N/A N/AN/A N/A $ 15,299,091 N/A N/AN/A N/A $ 15,299,091 N/A N/AN/A N/A $ 21,262,911 N/A N/AN/A N/A $ 21,262,911 N/A N/AN/A N/A $ 20,399,907 N/A N/AN/A N/A $ 20,399,907 N/A N/AScenario 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 1Scenario 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\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYNaughton Unit 1Boiler Design: Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESP& Higher SCoalDry FGDw/Fabric FilterWet FGDw/ESPFlue GasConditioningFabric FilterCase1 2 3 4 5 6 7 8 9 10NOx Emission Control SystemNone LNB w/OFA ROFALNB w/OFA &SNCRLNB w/OFA &SCR None None None None NoneSO2 Emission Control SystemNone None None None NoneDry FGD w/ESP &Higher S Coal Dry FGD w/Fabric Filter Wet FGD w/ESP None NonePM Emission Control SystemESP ESP ESP ESP ESP ESP ESP ESP Flue Gas Conditioning Fabric FilterTOTAL INSTALLED CAPITAL COST ($)0 7,300,000 9,068,746 17,526,855 58,227,447 64,297,623 108,995,970 91,696,610 1,298,352 29,798,898FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 506,128 506,128 809,804 0 0Maintenance Material ($) 0 32,000 48,000 83,000 132,000 587,643 632,660 963,589 0 45,016Maintenance Labor ($) 0 48,000 72,000 124,500 198,000 391,762 459,286 642,393 10,000 67,524Administrative Labor ($) 0 0 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 80,000 120,000 207,500 330,000 1,485,533 1,598,074 2,415,786 10,000 112,540Makeup Water Cost 0 0 0 0 0 69,063 69,063 92,084 0 0Reagent Cost 0 0 0 399,761 281,492 1,870,139 880,203 735,700 47,609 0SCR Catalyst / FF Bag Cost 0 0 0 0 201,000 0 89,960 0 0 89,960Waste Disposal Cost 0 0 0 0 0 878,461 471,814 548,278 0 0Electric Power Cost 0 0 558,514 63,072 386,710 647,671 1,046,995 946,080 19,710 399,325TOTAL VARIABLE O&M COST0 0 558,514 462,833 869,203 3,465,334 2,558,035 2,322,141 67,319 489,285TOTAL FIRST YEAR O&M COST 0 80,000 678,514 670,333 1,199,203 4,950,867 4,156,109 4,737,927 77,319 601,825FIRST YEAR DEBT SERVICE ($)0 694,433 862,690 1,667,292 5,539,050 6,116,493 10,368,549 8,722,899 123,509 2,834,704TOTAL FIRST YEAR COST ($)0 774,433 1,541,204 2,337,624 6,738,253 11,067,360 14,524,658 13,460,826 200,828 3,436,529Power Consumption (MW) 0.0 0.0 1.4 0.2 1.0 1.6 2.7 2.4 0.1 1.0Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 11.2 1.3 7.7 13.0 20.9 18.9 0.4 8.0CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0% 58.6% 55.2% 67.2% 87.9% 0.0% 0.0% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 2,480 2,334 2,844 3,719 0 0 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 312 660 822 1,812 0 0 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 312 660 4,287 3,751 0 0 0 0 02-1 3-1 4-2 5-3SO2 Removal Rate (%)0.0% 0.0% 0.0% 0.0% 0.0% 80.1% 87.3% 91.5% 0.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 12,061 7,530 7,895 0 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 918 1,929 1,705 0 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 918 1,929 1,705 0 06-1 7-1 8-1PM Removal Rate (%) 98.63% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 28.57% 73.21%PM Removed (Tons/Yr) 0 0 0 0 0 0 0 0 117 299First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 0 0 1,721 11,493Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 0 0 1,721 17,7479-1 10-9PRESENT WORTH COST ($)0 8,277,429 17,358,735 25,716,881 72,879,129 124,786,587 159,774,694 149,583,911 2,243,024 37,151,908PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls1 of 1INPUT CALCULATIONSNaughton Unit 1Boiler Design:Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESP &Higher S CoalDry FGD w/FabricFilterWet FGDw/ESPFlue GasConditioningFabric FilterCase1 2 3 4 5 6 7 8 9 10NOx Emission Control SystemNone LNB w/OFA ROFALNB w/OFA &SNCR LNB w/OFA & SCRNone None None None NoneSO2 Emission Control SystemNoneNone None None NoneDry FGD w/ESP & Higher SCoal Dry FGD w/Fabric Filter Wet FGD w/ESPNone NonePM Emission Control SystemESPESP ESP ESP ESP ESP ESP ESPFlue Gas Conditioning Fabric FilterUnit Design and Coal CharacteristicsType of UnitPC PC PC PC PC PC PC PC PC PCNet Power Output (kW)160,000 160,000160,000 160,000 160,000 160,000 160,000 160,000 160,000 160,000Net Plant Heat Rate (Btu/kW-Hr)11,56311,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563 11,563Boiler FuelKemmerer MineKemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer Mine Kemmerer MineCoal Heating Value (Btu/Lb)9,800 9,8009,800 9,800 9,8009,8759,800 9,800 9,800 9,800Coal Sulfur Content (wt.%)0.58%0.58%0.58%0.58%0.58%1.02%0.58%0.580%0.58%0.58%Coal Ash Content (wt.%)5.00%5.00%5.00%5.00%5.00%5.25%5.00%5.00%5.00%5.00%Boiler Heat Input, each (MMBtu/Hr)1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850 1,850Coal Flow Rate (Lb/Hr)188,784 188,784 188,784 188,784 188,784 187,350 188,784 188,784 188,784 188,784(Ton/Yr)744,185 744,185 744,185 744,185 744,185 738,533 744,185 744,185 744,185 744,185(MMBtu/Yr)14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031 14,586,031EmissionsUncontrolled SO2 (Lb/Hr)2,188 2,188 2,188 2,188 2,188 3,818 2,188 2,188 2,188 2,188(Lb/MMBtu)1.18 1.18 1.18 1.18 1.18 2.06 1.18 1.18 1.18 1.18(Lb Moles/Hr)34.15 34.15 34.15 34.15 34.15 59.60 34.15 34.15 34.15 34.15(Tons/Yr)8,624 8,624 8,624 8,624 8,624 15,051 8,624 8,624 8,624 8,624SO2 Removal Rate (%)0.0%0.0%0.0%0.0%0.0%80.1%87.3%91.5%0.0%0.0%(Lb/Hr)0 0 0 0 0 3,060 1,910 2,003 0 0(Ton/Yr)0 0 0 0 0 12,061 7,530 7,895 0 0SO2 Emission Rate (Lb/Hr)2,188 2,188 2,188 2,188 2,188 759 278 185 2,188 2,188(Lb/MMBtu)1.181.18 1.18 1.18 1.180.41 0.15 0.101.18 1.18(Ton/Yr)8,624 8,624 8,624 8,624 8,624 2,990 1,094 729 8,624 8,624Uncontrolled NOx (Lb/Hr)1,073 1,073 1,073 1,073 1,073 1,073 1,073 1,073 1,073 1,073(Lb/MMBtu)0.580.58 0.58 0.58 0.58 0.58 0.58 0.58 0.58 0.58(Lb Moles/Hr)35.76 35.76 35.76 35.76 35.76 35.76 35.76 35.76 35.76 35.76(Tons/Yr)4,230 4,230 4,230 4,230 4,230 4,230 4,230 4,230 4,230 4,230NOx Removal Rate (%)0.0%58.6%55.2%67.2%87.9%0.0%0.0%0%0.0%0%(Lb/Hr)0 629 592 722 944 0 0 0 0 0(Lb Moles/Hr)0.00 20.96 19.73 24.04 31.44 0.00 0.00 0.00 0.00 0.00(Ton/Yr)0 2,480 2,334 2,844 3,719 0 0 0 0 0NOx Emission Rate (Lb/Hr)1,073 444 481 352 130 1,073 1,073 1,073 1,073 1,073(Lb/MMBtu)0.580.24 0.26 0.19 0.070.58 0.58 0.58 0.58 0.58(Ton/Yr)4,230 1,750 1,896 1,386 511 4,230 4,230 4,230 4,230 4,230Uncontrolled Fly Ash (Lb/Hr)7,551 104 104 104 104 104 104 104 104 104(Lb/MMBtu)4.082 0.056 0.056 0.056 0.056 0.056 0.056 0.056 0.056 0.056(Lb Moles/Hr)251.6 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5(Tons/Yr)29,767 408 408 408 408 408 408 408 408 408Fly Ash Removal Rate (%)98.63%0.00%0.00%0.00%0.00%0.00%0.00%0.00%28.57%73.21%(Lb/Hr)7,448 0 0 0 0 0 0 0 30 76(Ton/Yr)29,359 0 0 0 0 0 0 0 117 299Fly Ash Emission Rate (Lb/Hr)104 104 104 104 104 104 104 104 74 28(Lb/MMBtu)0.0560.056 0.056 0.056 0.056 0.056 0.056 0.0560.040 0.015(Ton/Yr)408 408 408 408 408 408 408 408 292 109ParameterCommentsCurrentOperationSO2 ControlNOx ControlPM ControlEY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls1 of 2LNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRDry FGD w/ESP &Higher S CoalDry FGD w/FabricFilterWet FGDw/ESPFlue GasConditioningFabric FilterCase1 2 3 4 5 6 7 8 9 10ParameterCommentsCurrentOperationSO2 ControlNOx ControlPM ControlGeneral Plant DataAnnual Operation (Hours/Year)7,884 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 0.90 0.90Economic FactorsInterest Rate (%)7.10%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%7.10%Plant Economic Life (Years)2020 20 20 20 20 20 20 20 20Installed Capital CostsNOx Emission Control System ($2006)07,300,000 9,068,746 17,526,85558,227,447 0 0 0 0 0SO2 Emission Control System ($2006)00 0 0 0 64,297,623 108,995,970 91,696,610 0 0PM Emission Control System ($2006)00 0 0 0 0 0 0 1,298,352 29,798,898Total Emission Control Systems ($2006)0 7,300,000 9,068,746 17,526,85558,227,447 64,297,623 108,995,970 91,696,610 1,298,352 29,798,898NOx Emission Control System ($/kW)0 46 57 110 364 0 0 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 402 681 573 0 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 0 8 186Total Emission Control Systems ($/kW)0 46 57 110 364 402 681 573 8 186Total Fixed Operating & Maintenance CostsOperating Labor ($)0 0 0 0 0 506,128 506,128 809,804 0 0Maintenance Material ($)0 32,000 48,000 83,000 132,000 587,643 632,660 963,589 0 45,016Maintenance Labor ($)0 48,000 72,000 124,500 198,000 391,762 459,286 642,393 10,000 67,524Administrative Labor ($)00000 0 0 0 0 0Total Fixed O&M Cost ($)0 80,000 120,000 207,500 330,000 1,485,533 1,598,0742,415,786 10,000 112,540Annual Fixed O&M Cost Escalation Rate (%)2.00%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 0 120 120 160 0 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 69,063 69,063 92,084 0 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Lime Lime Lime Elemental SulfurNoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 91.25 91.25 91.25 370 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.046 0.046 0.046 0.185 0.000Molar Stoichiometry0.00 0.00 0.00 0.45 1.00 1.40 1.15 1.05 0.00 0.00Reagent Purity (Wt.%)100%100%100%100%100%90%90%90%100%90%Reagent Usage (Lb/Hr)0 0 0 274 179 5,199 2,447 2,045330First Year Reagent Cost ($)0 0 0 399,761 281,492 1,870,139 880,203 735,700 47,609 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags Bags Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags000067 0 865 0 0 865SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000104104 104 3,000 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 201,000 0 89,960 0 0 89,960Annual SCR Catalyst / Bag Cost Esc. Rate (%)2.00%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 9,158 4,919 5,716 0 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 878,461 471,814 548,278 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%2.00%Auxiliary Power CostAuxiliary Power Requirement (% of Plant Output)0.00%0.00%0.89%0.10%0.61%1.03%1.66%1.50%0.03%0.63%(MW)0.00 0.00 1.42 0.16 0.98 1.64 2.66 2.40 0.05 1.01Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 558,514 63,072 386,710 647,671 1,046,995 946,080 19,710 399,325Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.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\[File]1 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 31.18 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 11.18 0.58 0.056 0.24 0.260.190.07 0.410.150.100.040 0.0158 Naughton Unit 21.18 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\[File]2 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\[File]3 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\[File]4 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 $ 67,159,581 $ 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 $ 87,030,191 $ 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\[File]5 of 5CAPITAL COSTNaughton Unit 1CaseNOx 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 $2,502,123Vendor $2,675,792Vendor $2,502,123Vendor $2,502,123Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$2,135,15685.3%$2,283,35485.3%$2,135,15685.3%$2,135,15685.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$1,293,40151.7%$1,383,17451.7%$1,293,40151.7%$1,293,40151.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$802,7380.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$331,49013.2%$354,49813.2%$331,49013.2%$331,49013.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$410,98616.4%$439,51216.4%$410,98616.4%$410,98616.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$305,72112.2%$326,94112.2%$305,72112.2%$305,72112.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal $6,978,877 $8,266,008 $6,978,877 $6,978,877 $0 $0 $0 $0 $0Contingency12.8%$321,12430.0%$802,73812.8%$321,12412.8%$321,12412.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $7,300,000 $9,068,746 $7,300,000 $7,300,000 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $7,257,000 S&L Report $37,292,000 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0Contingency20.0%$020.0%$020.0%$1,451,40010.0%$3,729,20020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$405,8845.6%$2,085,7425.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$3,150,0558.4%$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%$79,9721.1%$410,9581.1%$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%$203,7040.0%$02.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$828,89511.4%$4,259,49211.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $10,226,855 $50,927,447 $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 $39,617,991 S&L Report $67,159,581 S&L Report $56,500,308 S&L Report $800,000 S&L Report $18,361,060Contingency20.0%$020.0%$020.0%$020.0%$020.0%$7,923,59820.0%$13,431,91620.0%$11,300,06220.0%$160,00020.0%$3,672,212Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$2,215,8345.6%$3,756,2355.6%$3,160,0625.6%$44,7445.6%$1,026,934EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$3,346,5328.4%$5,672,9708.4%$4,772,5818.4%$67,5768.4%$1,550,959Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$1,114,8502.8%$1,889,8712.8%$1,589,9192.8%$22,5122.8%$516,680Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$436,5901.1%$740,0991.1%$622,6331.1%$8,8161.1%$202,339Escalation10.1%$010.1%$010.1%$010.1%$010.1%$4,004,98310.1%$6,789,16210.1%$5,711,61610.1%$80,87210.1%$1,856,120Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$1,112,0772.8%$1,885,1692.8%$1,585,9642.8%$22,4562.8%$515,395Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$4,525,16711.4%$7,670,96711.4%$6,453,46511.4%$91,37611.4%$2,097,200Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $64,297,623 $108,995,970 $91,696,610 $1,298,352 $29,798,898Fabric Filter8NoneFabric Filter10NoneNoneNoneNoneFlue Gas ConditioningDry FGD w/Fabric FilterDry FGD w/ESP & HigherLNB w/OFA & SNCRSO2 ControlWet FGD w/ESPWet FGD w/ESPESPLNB w/OFANoneESP ESPROFANoneNoneDry FGD w/Fabric FilterParameterLNB w/OFA ROFA LNB w/OFA & SCRESPNoneDry FGD w/ESP & Higher S CoalESPLNB w/OFA & SNCRNoneESP ESPLNB w/OFA & SCRNonePM ControlFlue Gas ConditioningNOx Control45 76293EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls1 of 1Naughton Unit 1LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 80,000------694,433774,4333122 2015 81,600------694,433776,0333133 2016 83,232------694,433777,6653144 2017 84,897------694,433779,3303145 2018 86,595------694,433781,0283156 2019 88,326------694,433782,7603167 2020 90,093------694,433784,5263168 2021 91,895------694,433786,3283179 2022 93,733------694,433788,16631810 2023 95,607------694,433790,04131911 2024 97,520------694,433791,95331912 2025 99,470------694,433793,90332013 2026 101,459------694,433795,89332114 2027 103,489------694,433797,92232215 2028 105,558------694,433799,99132316 2029 107,669------694,433802,10332317 2030 109,823------694,433804,25632418 2031 112,019------694,433806,45232519 2032 114,260------694,433808,69332620 2033 116,545------694,433810,978327Present Worth977,428------7,300,0008,277,429167(% of PW)11.8% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 88.2% 100.0%Naughton Unit 1ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 120,000----558,514558,514862,6901,541,2046602 2015 122,400----569,685569,685862,6901,554,7756663 2016 124,848----581,078581,078862,6901,568,6166724 2017 127,345----592,700592,700862,6901,582,7356785 2018 129,892----604,554604,554862,6901,597,1366846 2019 132,490----616,645616,645862,6901,611,8256917 2020 135,139----628,978628,978862,6901,626,8076978 2021 137,842----641,557641,557862,6901,642,0907049 2022 140,599----654,389654,389862,6901,657,67871010 2023 143,411----667,476667,476862,6901,673,57871711 2024 146,279----680,826680,826862,6901,689,79572412 2025 149,205----694,442694,442862,6901,706,33773113 2026 152,189----708,331708,331862,6901,723,21073814 2027 155,233----722,498722,498862,6901,740,42174615 2028 158,337----736,948736,948862,6901,757,97575316 2029 161,504----751,687751,687862,6901,775,88176117 2030 164,734----766,721766,721862,6901,794,14576918 2031 168,029----782,055782,055862,6901,812,77477719 2032 171,390----797,696797,696862,6901,831,77678520 2033 174,817----813,650813,650862,6901,851,157793Present Worth1,466,142----6,823,8476,823,8479,068,74617,358,735372(% of PW)8.4% 0.0% 0.0% 0.0% 0.0% 39.3% 39.3% 52.2% 100.0%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls1 of 5Naughton Unit 1LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 207,500-399,761--63,072462,8331,667,2922,337,6248222 2015 211,650-407,756--64,333472,0891,667,2922,351,0318273 2016 215,883-415,911--65,620481,5311,667,2922,364,7068314 2017 220,201-424,229--66,933491,1621,667,2922,378,6548365 2018 224,605-432,714--68,271500,9851,667,2922,392,8818416 2019 229,097-441,368--69,637511,0051,667,2922,407,3938467 2020 233,679-450,195--71,029521,2251,667,2922,422,1958528 2021 238,352-459,199--72,450531,6491,667,2922,437,2938579 2022 243,119-468,383--73,899542,2821,667,2922,452,69386210 2023 247,982-477,751--75,377553,1281,667,2922,468,40186811 2024 252,941-487,306--76,884564,1901,667,2922,484,42387312 2025 258,000-497,052--78,422575,4741,667,2922,500,76687913 2026 263,160-506,993--79,991586,9841,667,2922,517,43588514 2027 268,423-517,133--81,590598,7231,667,2922,534,43889115 2028 273,792-527,476--83,222610,6981,667,2922,551,78189716 2029 279,268-538,025--84,887622,9121,667,2922,569,47190317 2030 284,853-548,786--86,584635,3701,667,2922,587,51591018 2031 290,550-559,761--88,316648,0771,667,2922,605,91991619 2032 296,361-570,957--90,082661,0391,667,2922,624,69292320 2033 302,288-582,376--91,884674,2601,667,2922,643,840930Present Worth2,535,205-4,884,217--770,6045,654,82117,526,85525,716,881452(% of PW)9.9% 0.0% 19.0% 0.0% 0.0% 3.0% 22.0% 68.2% 100.0%Naughton Unit 1LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 330,000-281,492201,000-386,710869,2035,539,0506,738,2531,8122 2015 336,600-287,122205,020-394,444886,5875,539,0506,762,2371,8183 2016 343,332-292,865209,120-402,333904,3185,539,0506,786,7011,8254 2017 350,199-298,722213,303-410,380922,4055,539,0506,811,6541,8315 2018 357,203-304,696217,569-418,588940,8535,539,0506,837,1061,8386 2019 364,347-310,790221,920-426,959959,6705,539,0506,863,0671,8457 2020 371,634-317,006226,359-435,498978,8635,539,0506,889,5471,8528 2021 379,066-323,346230,886-444,208998,4415,539,0506,916,5571,8609 2022 386,648-329,813235,504-453,0931,018,4095,539,0506,944,1071,86710 2023 394,381-336,409240,214-462,1541,038,7785,539,0506,972,2081,87511 2024 402,268-343,138245,018-471,3981,059,5535,539,0507,000,8721,88212 2025 410,314-350,000249,918-480,8261,080,7445,539,0507,030,1081,89013 2026 418,520-357,000254,917-490,4421,102,3595,539,0507,059,9291,89814 2027 426,890-364,140260,015-500,2511,124,4065,539,0507,090,3471,90615 2028 435,428-371,423265,215-510,2561,146,8945,539,0507,121,3731,91516 2029 444,137-378,852270,520-520,4611,169,8325,539,0507,153,0191,92317 2030 453,019-386,429275,930-530,8701,193,2295,539,0507,185,2991,93218 2031 462,080-394,157281,449-541,4881,217,0935,539,0507,218,2231,94119 2032 471,321-402,040287,077-552,3171,241,4355,539,0507,251,8071,95020 2033 480,748-410,081292,819-563,3641,266,2645,539,0507,286,0621,959Present Worth4,031,892-3,439,2332,455,789-4,724,76810,619,79058,227,44772,879,129980(% of PW)5.5% 0.0% 4.7% 3.4% 0.0% 6.5% 14.6% 79.9% 100.0%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls2 of 5Naughton Unit 1Dry FGD w/ESP & Higher S CoalYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 1,485,53369,0631,870,139-878,461647,6713,465,3346,116,49311,067,3609182 2015 1,515,24470,4441,907,542-896,030660,6243,534,6406,116,49311,166,3779263 2016 1,545,54971,8531,945,693-913,950673,8363,605,3336,116,49311,267,3759344 2017 1,576,46073,2901,984,607-932,229687,3133,677,4406,116,49311,370,3929435 2018 1,607,98974,7562,024,299-950,874701,0593,750,9896,116,49311,475,4709516 2019 1,640,14976,2512,064,785-969,891715,0813,826,0086,116,49311,582,6509607 2020 1,672,95277,7762,106,081-989,289729,3823,902,5286,116,49311,691,9739698 2021 1,706,41179,3322,148,202-1,009,075743,9703,980,5796,116,49311,803,4839799 2022 1,740,53980,9182,191,166-1,029,257758,8494,060,1916,116,49311,917,22298810 2023 1,775,35082,5372,234,990-1,049,842774,0264,141,3946,116,49312,033,23799811 2024 1,810,85784,1872,279,690-1,070,838789,5074,224,2226,116,49312,151,5721,00812 2025 1,847,07485,8712,325,283-1,092,255805,2974,308,7076,116,49312,272,2741,01813 2026 1,884,01587,5892,371,789-1,114,100821,4034,394,8816,116,49312,395,3891,02814 2027 1,921,69689,3402,419,225-1,136,382837,8314,482,7796,116,49312,520,9671,03815 2028 1,960,13091,1272,467,609-1,159,110854,5884,572,4346,116,49312,649,0571,04916 2029 1,999,33292,9502,516,961-1,182,292871,6794,663,8836,116,49312,779,7081,06017 2030 2,039,31994,8092,567,301-1,205,938889,1134,757,1606,116,49312,912,9721,07118 2031 2,080,10596,7052,618,647-1,230,057906,8954,852,3046,116,49313,048,9021,08219 2032 2,121,70798,6392,671,020-1,254,658925,0334,949,3506,116,49313,187,5501,09320 2033 2,164,141100,6122,724,440-1,279,751943,5345,048,3376,116,49313,328,9711,105Present Worth18,150,027843,80222,849,089-10,732,9027,913,14442,338,93864,297,623124,786,587517(% of PW)14.5% 0.7% 18.3% 0.0% 8.6% 6.3% 33.9% 51.5% 100.0%Naughton Unit 1Dry FGD w/Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 1,598,07469,063880,20389,960471,8141,046,9952,558,03510,368,54914,524,6581,9292 2015 1,630,03570,444897,80791,759481,2501,067,9352,609,19610,368,54914,607,7801,9403 2016 1,662,63671,853915,76393,594490,8751,089,2942,661,38010,368,54914,692,5651,9514 2017 1,695,88873,290934,07895,466500,6931,111,0802,714,60710,368,54914,779,0451,9635 2018 1,729,80674,756952,76097,376510,7071,133,3012,768,89910,368,54914,867,2551,9746 2019 1,764,40276,251971,81599,323520,9211,155,9672,824,27710,368,54914,957,2291,9867 2020 1,799,69077,776991,251101,310531,3391,179,0872,880,76310,368,54915,049,0031,9998 2021 1,835,68479,3321,011,076103,336541,9661,202,6682,938,37810,368,54915,142,6122,0119 2022 1,872,39880,9181,031,298105,402552,8051,226,7222,997,14610,368,54915,238,0932,02410 2023 1,909,84682,5371,051,924107,511563,8611,251,2563,057,08910,368,54915,335,4842,03711 2024 1,948,04384,1871,072,962109,661575,1391,276,2813,118,23010,368,54915,434,8222,05012 2025 1,987,00485,8711,094,421111,854586,6411,301,8073,180,59510,368,54915,536,1482,06313 2026 2,026,74487,5891,116,310114,091598,3741,327,8433,244,20710,368,54915,639,5002,07714 2027 2,067,27989,3401,138,636116,373610,3421,354,4003,309,09110,368,54915,744,9192,09115 2028 2,108,62491,1271,161,409118,700622,5491,381,4883,375,27310,368,54915,852,4462,10516 2029 2,150,79792,9501,184,637121,074635,0001,409,1183,442,77810,368,54915,962,1242,12017 2030 2,193,81394,8091,208,330123,496647,7001,437,3003,511,63410,368,54916,073,9962,13518 2031 2,237,68996,7051,232,496125,966660,6541,466,0463,581,86610,368,54916,188,1052,15019 2032 2,282,44398,6391,257,146128,485673,8671,495,3673,653,50410,368,54916,304,4962,16520 2033 2,328,091100,6121,282,289131,055687,3441,525,2743,726,57410,368,54916,423,2152,181Present Worth19,525,029843,80210,754,1861,099,1185,764,55512,792,03431,253,695108,995,970159,774,6941,061(% of PW)12.2% 0.5% 6.7% 0.7% 3.6% 8.0% 19.6% 68.2% 100.0%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls3 of 5Naughton Unit 1Wet FGD w/ESPYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 2,415,78692,084735,700-548,278946,0802,322,1418,722,89913,460,8261,7052 2015 2,464,10293,926750,414-559,243965,0022,368,5848,722,89913,555,5851,7173 2016 2,513,38495,804765,422-570,428984,3022,415,9568,722,89913,652,2381,7294 2017 2,563,65197,720780,730-581,8361,003,9882,464,2758,722,89913,750,8251,7425 2018 2,614,92499,675796,345-593,4731,024,0672,513,5608,722,89913,851,3841,7556 2019 2,667,223101,668812,272-605,3431,044,5492,563,8328,722,89913,953,9531,7687 2020 2,720,567103,702828,517-617,4501,065,4402,615,1088,722,89914,058,5751,7818 2021 2,774,979105,776845,088-629,7991,086,7492,667,4108,722,89914,165,2881,7949 2022 2,830,478107,891861,989-642,3941,108,4842,720,7598,722,89914,274,1361,80810 2023 2,887,088110,049879,229-655,2421,130,6532,775,1748,722,89914,385,1611,82211 2024 2,944,830112,250896,814-668,3471,153,2662,830,6778,722,89914,498,4061,83612 2025 3,003,726114,495914,750-681,7141,176,3322,887,2918,722,89914,613,9161,85113 2026 3,063,801116,785933,045-695,3481,199,8582,945,0378,722,89914,731,7361,86614 2027 3,125,077119,121951,706-709,2551,223,8553,003,9378,722,89914,851,9131,88115 2028 3,187,578121,503970,740-723,4411,248,3323,064,0168,722,89914,974,4931,89716 2029 3,251,330123,933990,155-737,9091,273,2993,125,2968,722,89915,099,5251,91317 2030 3,316,356126,4121,009,958-752,6681,298,7653,187,8028,722,89915,227,0581,92918 2031 3,382,684128,9401,030,157-767,7211,324,7403,251,5588,722,89915,357,1411,94519 2032 3,450,337131,5191,050,760-783,0751,351,2353,316,5908,722,89915,489,8261,96220 2033 3,519,344134,1491,071,776-798,7371,378,2603,382,9218,722,89915,625,1641,979Present Worth29,515,7191,125,0708,988,671-6,698,77411,559,06728,371,58291,696,610149,583,911947(% of PW)19.7% 0.8% 6.0% 0.0% 4.5% 7.7% 19.0% 61.3% 100.0%Naughton Unit 1Flue Gas ConditioningYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 10,000-47,609--19,71067,319123,509200,8281,7212 2015 10,200-48,561--20,10468,665123,509202,3751,7343 2016 10,404-49,532--20,50670,039123,509203,9521,7484 2017 10,612-50,523--20,91671,439123,509205,5611,7625 2018 10,824-51,533--21,33572,868123,509207,2021,7766 2019 11,041-52,564--21,76174,326123,509208,8761,7907 2020 11,262-53,615--22,19775,812123,509210,5831,8058 2021 11,487-54,688--22,64177,328123,509212,3251,8209 2022 11,717-55,781--23,09378,875123,509214,1011,83510 2023 11,951-56,897--23,55580,452123,509215,9131,85011 2024 12,190-58,035--24,02682,061123,509217,7611,86612 2025 12,434-59,196--24,50783,703123,509219,6461,88213 2026 12,682-60,380--24,99785,377123,509221,5691,89914 2027 12,936-61,587--25,49787,084123,509223,5301,91615 2028 13,195-62,819--26,00788,826123,509225,5301,93316 2029 13,459-64,075--26,52790,602123,509227,5711,95017 2030 13,728-65,357--27,05892,414123,509229,6521,96818 2031 14,002-66,664--27,59994,263123,509231,7751,98619 2032 14,282-67,997--28,15196,148123,509233,9402,00520 2033 14,568-69,357--28,71498,071123,509236,1492,024Present Worth122,179-581,679--240,814822,4931,298,3522,243,024961(% of PW)5.4% 0.0% 25.9% 0.0% 0.0% 10.7% 36.7% 57.9% 100.0%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls4 of 5Naughton Unit 1Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 112,540--89,960-399,325489,2852,834,7043,436,52911,4932 2015 114,791--91,759-407,311499,0702,834,7043,448,56611,5333 2016 117,087--93,594-415,457509,0522,834,7043,460,84311,5744 2017 119,429--95,466-423,766519,2332,834,7043,473,36611,6165 2018 121,817--97,376-432,242529,6172,834,7043,486,13911,6596 2019 124,254--99,323-440,887540,2102,834,7043,499,16811,7027 2020 126,739--101,310-449,704551,0142,834,7043,512,45711,7478 2021 129,274--103,336-458,698562,0342,834,7043,526,01211,7929 2022 131,859--105,402-467,872573,2752,834,7043,539,83811,83810 2023 134,496--107,511-477,230584,7402,834,7043,553,94111,88611 2024 137,186--109,661-486,774596,4352,834,7043,568,32611,93412 2025 139,930--111,854-496,510608,3642,834,7043,582,99811,98313 2026 142,728--114,091-506,440620,5312,834,7043,597,96412,03314 2027 145,583--116,373-516,569632,9422,834,7043,613,22912,08415 2028 148,495--118,700-526,900645,6012,834,7043,628,80012,13616 2029 151,465--121,074-537,438658,5132,834,7043,644,68212,18917 2030 154,494--123,496-548,187671,6832,834,7043,660,88112,24318 2031 157,584--125,966-559,151685,1172,834,7043,677,40512,29819 2032 160,735--128,485-570,334698,8192,834,7043,694,25912,35520 2033 163,950--131,055-581,741712,7952,834,7043,711,45012,412Present Worth1,375,002--1,099,118-4,878,8895,978,00729,798,89837,151,9086,212(% of PW)3.7% 0.0% 0.0% 3.0% 0.0% 13.1% 16.1% 80.2% 100.0%EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls5 of 5EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 1 of 1First Year Cost for Air Pollution Control Options02,000,0004,000,0006,000,0008,000,00010,000,00012,000,00014,000,00016,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRDry FGDw/ESP &Higher S CoalDry FGDw/FabricFilterWet FGDw/ESPFlue GasConditioningFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\PCorp Naughton 1 BART Economic Analysis_02-08-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options020,000,00040,000,00060,000,00080,000,000100,000,000120,000,000140,000,000160,000,000180,000,000LNB w/OFA ROFA LNB w/OFA& SNCRLNB w/OFA& SCRDry FGDw/ESP &Higher SCoalDry FGDw/FabricFilterWet FGDw/ESPFlue GasConditioningFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B 

# 2006 Wyoming BART Protocol