# Final Report



# BART Analysis for

Naughton Unit 2

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Naughton Unit 2

Submitted to



# PacifiCorp

December 2007

# Executive Summary

Background

In response to the Regional Haze Rule 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 2 (hereafter referred to as Naughton 2). A BART analysis has

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

x 

# ), sulfur dioxide

(SO 2 

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

# ). The

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

(MW). Presumptive BART limits do not direct ly apply to Naughton 2, based on the United

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

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

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

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

assumed for this analysis.

In completing the BART analysis, technology 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

− 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_NAUGHTON2__OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR NAUGHTON UNIT 2



# BART Engineering Analysis

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

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

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

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

availability of opti ons 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 Effectiveness of Remaining Control Technologies

• 

# Step 4 – Evaluate Impacts and Document Results

− The costs of compliance with control options

− The remaining useful life of the facility

− The energy and non-air quality 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; cost s have not been escalated to the assumed 2014

BART implementation date.



# Coal Characteristics

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

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

characteristics to bituminous coal in many of the parameters influencing NO

x 

# formation.

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR NAUGHTON UNIT 2



# analysis has compared the higher nitroge n content and the different combustion

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

of these qualities on NO

x 

# formation and achievable emission rates.



# Recommendations

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

existing ESP with an SO 3 

# FGC system. This combination of c ontrol devices is identified as

Scenario 1 throughout this report.



# NO

x 

# Emission Control

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

P&M coals are aligned more cl osely with bituminous coals.

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

significant reduction in NO

x 

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

additional power requirements or non-air quality environmental impacts. Reductions of NO

x 

# are expected to be similar to those realized at the Jim Bridger plan t where LNBs with OFA

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

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



# SO 2 

# Emission Control

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

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

based on the significant reduction in SO 2 

# emissions, reasonable control costs, and the

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

environmental impacts. This techno logy is projected to attain an SO 2 

# limit of 0.41 pound per

MMBtu.



# PM 10



# Emission Control

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

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

PM 10 

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

requirements and no non-air quality environmental impacts.



# BART Modeling Analysis

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

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

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

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

• Bridger WA

• Fitzpatrick WA

Because Naughton 2 simultaneously will control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR NAUGHTON UNIT 2



# 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 modi fications, a dry FGD system, and an FGC system

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

preliminary BART recommendation of CH2M HILL.

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

new fabric filter.

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

installation of a new fabric filter.

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

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

stack.

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

were compared using a least-cost envelope, as outlined in the New Source Review Workshop

Manual

. 1



# Least-cost Envelope Analysis

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

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

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

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

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

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

the BART analysis.

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

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

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

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

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

# percentile

delta-deciview ( Δ dV) reduction.

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

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

following reasons:

• Scenario 2 (LNB with OFA, 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_NAUGHTON2__OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC ES-5 

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

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

reduction.

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

# injection) provides some potential visibil ity advantage over Scen ario 1, the projected

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

Therefore, Scenario 1 represents BART for Naughton 2.



# Just-Noticeable Differences in Atmospheric Haze

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

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

distinguished by the average 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 would o ccur, although PacifiCorp would be spending

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

entire fleet of coal-fired power plants.

# Contents

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

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

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

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

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

3.2.1 BART 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.................................................................................... 5-6

5.2.1 NO

x 

# Emission Control ................................................................. 5-6

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC iv 

# Tables

2-1 Present Unit Operation

2-2 Coal Sources and Characteristics

3-1 Coal Characteristics Comparison

3-2 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 WA Class I Agent Control Data

5-2 Fitzpatrick WA Class I Area Control Data

5-3 Bridger WA Class I Agent Incremental Data

5-4 Fitzpatrick WA Class I Area Incremental Data

Figures

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

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

BART NO

x 

# Limits

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

NO

x 

# Limits

3-4 First Year Control Cost for NO

x 

# Air Pollution Control Options

3-5 First Year Control Cost for SO 2 

# Air Pollution Control Options

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

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

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

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

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

# Percentile dV Reduction

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

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

# Percentile dV Reduction

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

°C Degrees Celsius

°F Degrees Fahrenheit

ƒ(RH) Relative Humidity Factor

BACT Best 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

CO Carbon Monoxide

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

kW Kilowatt

kWh Kilowatt-hour

LAER Lowest Achievable Emission Rate

lb Pound

LNB Low-NO

x 

# Burner

MMBtu Million British Thermal Units

MM5 Mesoscale Meteorologi cal Model, Version 5

MW Megawatt

N 2 

# Molecular Nitrogen

NO Nitric Oxide

NO 2 

# Nitrogen Dioxide

NO

x 

# Nitrogen Oxide

(NH 4 

# )HSO 4 

# Ammonium Bisulfate

(NH 4 

# ) 2 

# SO 4 

# Ammonium Sulfate

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC vi 

# NP National Park

OFA Over-fire Air

P&M P&M Kemmerer Mine

PM Particulate Matter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Sargent & Lundy

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

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

TRC TRC Companies, Inc.

USGS United States Geological Survey

WA Wilderness Area

WDEQ Wyoming Department of Environmental Quality

WDEQ-AQD Wyoming Department of Envir onmental Quality – Air Quality Division

# 1.0 Introduction

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

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

occurrence of regional haze in national parks (NPs) and other Class I protected air quality

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

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

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

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

The Wyoming Department of Environmental 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 Unit 2 (hereafter referred to as Naughton 2) by February 9, 2007. The

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

well as a proposal and justification for BART at the source. This revised report—submitted

in October 2007—incorporates ed itorial revisions and new mode l runs since the February

2007 version.

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

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

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

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

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

5 years after EPA approval of the SIP.

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

• Cost of the controls

• Energy and non-air quality environmental impacts of compliance

• Any existing pollution control tech nology in use at the source

• Remaining useful life of the source

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

such technology

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

PacifiCorp. The analysis was pe rformed for nitrogen oxides (NO

x 

# ), SO 2 

# (sulfur dioxide), and

particulate matter less than 10 microm eters in aerodynamic diameter (PM 10 

# ) because these

are the primary criteria pollutant s that affect visibility.

Section 2 of this report provi des a description of the pres ent unit operation, including a

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

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

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

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

Wyoming BART Protocol.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 1-1

# 2.0 Present Unit Operation

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

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

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

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

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

coal to control SO

x 

# emissions below 1.2 pounds per milli on British thermal units (MMBtu)

and good combustion practices for NO

x 

# control. A Honeywell dist ributed control system was

installed in 1998.

Naughton 2 began operation in 1968. Its current economic depreciation life is through 2032;

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

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

for Naughton 2 of 20 years from the installation date of any new or modified BART-related

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

needed to allow the unit at Naughton 2 to operate until 2034. Table 2- 1 lists additional unit

information and study assumptions for this analysis.

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

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

of the parameters influencing NO

x 

# formation. P&M coal has hi gher nitrogen content than

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

use in the United States.

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

characteristics of PRB coals, compared to thos e coals used Naughton 2 and the effect of these

qualities on NO

x 

# formation. Coal sources and characteris tics are summarized in Table 2-2.

The primary source of coal will be from P&M, and data on coal from this source were used

in the modeling analysis.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 2-2 

# TABLE 2-1



# Present Unit Operation

Naughton 2

General Plant Data

Site Elevation (feet above mean sea level) 6936

Stack Height (feet) 224

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

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

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

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

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

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

Annual Unit Capacity Fact or (percentage [%]) 90

Net Unit Output (megawatts) 210

Net Unit Heat Rate (British thermal unit [Btu] per kilowatthour)(100% load) 10,550 (as measured by fuel

throughput)

Boiler Heat Input (million Btu [MMBtu] per hour)(100% load) 2,400 (as measured by continuous

emissions monitoring)

Type of Boiler Tangentially fired

Boiler Fuel Coal

Coal Sources P&M Kemmerer Mine

Coal Heating Value (Btu per pound) (a) 

# 9,800

Coal Sulfur Content (% by weight) (a) 

# 0.58

Coal Ash Content (% by weight) (a) 

# 5.00

Coal Moisture Content (% by weight) (a) 

# 21.00

Coal Nitrogen Content (% by weight) (a) 

# 1.3

Current Nitrogen Oxide (NO

x 

# ) Controls Good Combustion Practices

Pre-project NO

x 

# Emission Rate (pounds per MMBtu) (b) 

# 0.54

Current Sulfur Dioxide (SO 2 

# ) Controls None

Pre-project SO 2 

# Emission Rate (pounds per MMBtu) 1.20

Current PM 10 (c) 

# Controls Electrostatic Precipitator

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

# 0.064

NOTES:

(a) 

# Coal characteristics vary between coal sources

(b) 

# Emission rates stated on annual average basis

(c) 

# PM 10 

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

(d) 

# Emission rate stated from test resultsBART ANALYSIS FOR NAUGHTON UNIT 2TABLE 2-2Coal Sources and CharacteristicsNaughton 2Ultimate Analysis (% dry basis)MinesMoisture(%)Ash(%)VolatileMatter(%)FixedCarbon(%)Britishthermalunit perpoundSulfur(%)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_NAUGHTON2__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 EPA for Class I areas . The state has estimated that formal submittal

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

implementation of BART emission controls on 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 control equipment in use at the source, which affects the

availability of opti ons and their impacts

• The costs of compliance with the control options

• The remaining useful life of the facility

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

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

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Availabl e Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

− Identification of available, technica lly feasible, retrofit control options

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

the applicability of op tions and their impacts

• Step 3 – Evaluate Effectiveness of Remaining Control Technologies

• Step 4 – Evaluate Impacts and Document Results

− Costs of compliance with the control options

− Remaining useful life of the facility

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR NAUGHTON UNIT 2



# − Energy and non-air quality environmental impacts of compliance

• Step 5 – Evaluate Visibility Impacts

− Degree of visibility improvement that reason ably could 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 compliance associated w ith the control options,

and the energy and non-air quality environmenta l impacts 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 also were developed.

Separate cost analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs

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

implementation date).



# 3.2.1 BART NO

x 

# Analysis

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

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

characteristics.

Formation of NO

x 

# During coal combustion, NO

x 

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

x 

# formation is the oxidation of fuel-bound nitrog en. During combustion, pa rt 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 (NO and nitrogen dioxide) and partia lly reduced to molecular nitrogen (N 2 

# ). A smaller

part of NO

x 

# formation is due to high temperature fi xation of atmospheric nitrogen in the

combustion air (thermal NO

x 

# ). A small amount of NO

x 

# is called prompt NO

x 

# , which results

from an interaction of hydrocar bon 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 and provi de stable combustion. However, not all of the oxygen in the

air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form NO

x 

# .

Coal characteristics directly and significantly affect NO

x 

# emissions from coal combustion.

Coal ranking is a means of classifying coal ac cording to its degree of metamorphism in the

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

coal, such as the sub-bituminous co al from the PRB, produces lower NO

x 

# emissions than

higher rank bituminous coal, due to its higher reactivity and lower nitrogen content. The

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

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

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

with low-NO

x 

# burners (LNBs), sub-bituminous coal cr eates a longer time for the kinetics to

promote more stable N 2 

# , and hence results in lower NO

x 

# emissions.

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

and low NO

x 

# production characteristics previously described. Base d on data from the Energy

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR NAUGHTON UNIT 2



# of sub-bituminous coal in the United States a nd 73 percent of all the western coal production

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

sub-bituminous coal imply PRB origin a nd characteristics. Emissions standards

differentiating between bituminous and sub-bitu minous coals are presumed to use PRB coal

as the basis for the sub-bituminous standards, due to its dominant market presence and

unique characteristics.

A number of western coals are classified as sub-bituminous; however, these coals border on

being ranked as bituminous and do not displa y many of the qualities of PRB coals including

most of the low NO

x 

# -forming characteristics. Coals from P&M fall into this category.

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

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

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

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

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

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

area of the particle. Thus, with the applicati on of heat, agglomerating coals would tend to

develop a non-porous surface, while the surface of non-agglomerating coals would become

even more porous with combustion.

As shown in Figure 3-1, the increased porosity provides more particle surface area resulting

in more favorable combustion conditions. This non-agglomerating proper ty assists in making

sub-bituminous coals more amenable to controlling NO

x 

# by allowing less air to be introduced

during the initial ignition por tion of the combustion process. The coals from the P&M Mine

just barely fall into the category of non-aggl omerating coals. While each of these coals is

considered non-agglomerating, they either do not exhibit properties of non-agglomerating

coals or exhibit the properties to only a minor degree. The conditions during combustion of

typical non-agglomerating coals th at make it easier to control NO

x 

# emissions do not exist for

the coal used at Naughton 2.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR NAUGHTON UNIT 2



# FIGURE 3-1



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

Naughton 2



# Table 3-1 shows key NO

x 

# -forming characteristics of a typi cal PRB coal compared to lowsulfur and high-sulfur P&M coals, and to coal s from Twentymile, which is a representative

western bituminous coal.

TABLE 3-1



# Coal Characteristics Comparison

Naughton 2

Parameter Powder

River

Basin P&M

Low

Sulfur P&M High

Sulfur Twentymile

Nitrogen (% dry) 1.10 1.33 1.22 1.85

Oxygen (% dry) 16.2 15.35 14.5 7.19

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



# As shown in Table 3-1, although P&M coal is cla ssified as sub-bituminous, the coal exhibits

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

content is an indication that more nitrogen is available to the com bustion process and higher

NO

x 

# emissions are likely. Oxygen content can be co rrelated to the reactivity of the coal; more

reactive coals generally contain higher levels of oxygen. Mo re reactive coal s tend to produce

lower NO

x 

# emissions. More reactive coals are al so more conducive to reduction of NO

x

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR NAUGHTON UNIT 2



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

(OFA).

These characteristics indicate that higher NO

x 

# formation is more likely with P&M coal than

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

PRB coal and Twentymile coal. Twentymile coal is a clearly bituminous coal that produces

higher NO

x 

# as has been demonstrated at pow er plants burning this fuel.

Figures 3-2 and 3-3 illustrate the relations hip of nitrogen and oxygen content to BARTpresumptive NO

x 

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

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

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

Twentymile shows the achievemen t 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 fr om P&M that has been used at Naughton 2 and

indicates the average NO

x 

# emission rate of 0.57 pound 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 that for the Naughton 2 with the TFS2000 low NO

x 

# emission system installed and bur ning 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 pound per MMBtu. Neither limit

applies to Naughton 2.

All these factors are consiste nt with the observed sustaina ble emission rate of 0.24 pound per

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

Bridger Unit 2.

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

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

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

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

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

quality and combustion conditions (for example, formation of NO

x 

# ). Significant variability

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

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

x 

# formation have been

previously discussed. Some additional considerat ions illustrate the complexity of achieving

and maintaining low NO

x 

# emissions with pulverized coal on a consistent shorter term basis,

such as a 30-day rolling-average basis.

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

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

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

requirement, such as NO

x 

# emission limits, is changed subsequently, conflicts with and

between other performance issues can result.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR NAUGHTON UNIT 2



# FIGURE 3-2



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

x 

# Limits

Naughton 2

PRB Subbituminous Present

LNB w/OFA Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 0.6

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

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



# Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu



# FIGURE 3-3



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

x 

# Limits

Naughton 2

PRB Subbituminous Twentymile Bituminous Present

LNB w/OFA

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5 0.55 0.6

6.00 8.00 10.00 12.00 14.00 16.00 18.00

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



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



# JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR NAUGHTON UNIT 2



# Naughton 2 is located at an altitude of 6,936 feet above sea level. At this elevation,

atmospheric pressure is lower (11.3 pounds per square inch) than pr essure at sea level

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

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

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

distribution to reduce NO

x 

# emissions using LNBs with 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 gri ndability index (Hardgrove ) of the coal. Finer

coal particles promote the releas e of volatile particles and assi st char burnout due to more

surface area that is exposed to air. Reduction of NO

x 

# with high volatile coals is improved

with greater fineness and with proper air stagi ng. Coal fineness can de teriorate over time

periods between pulverizer maintenance and se rvice because of the wear to pulverizer

grinding surfaces.

When all of the factors are taken into acc ount (agglomeration versus non-agglomeration,

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

demonstrates that for the coal used at Na ughton 2, the LNB technology (referred to in the

presumptive BART analysis by EPA) will achieve NO

x 

# reductions similar to the rates

identified for tangentially fired boilers that burn bituminous coals. The current NO

x 

# emission

rate at Naughton 2 is 0.54 pound per MMBtu.

The BART analysis for NO

x 

# emissions from Naughton 2 is fu rther described in the following

section.

Step 1: Identify All Availabl e Retrofit Control Technologies

The first step of the BART process is to evaluate NO

x 

# control technologies with practical

potential for application to Naughton 2, includ ing those control technologies identified as

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

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

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

x 

# emissions from Naughton 2 currently are co ntrolled through the use of good combustion

practices and OFA.

The following potential NO

x 

# control technology options were considered:

• New/modified LNBs with advanced OFA

• Mobotec rotating opposed-fire air (ROFA)

• Conventional selectiv e non-catalytic reduction (SNCR) system

• Selective catalytic reduction (SCR) system

Step 2: Eliminate Technically Infeasible Options

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

boiler configuration. Naughton 2 has an uncontrolled NO

x 

# emission rate of

0.54 pound per MMBtu.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR NAUGHTON UNIT 2



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

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

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

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

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

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

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

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

where the temperature 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

applications. SNCR typically is applied on smalle r units. Adequate reagen t distribution in the

furnaces of large units can be problematic.

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

analysis, along with projected NO

x 

# emission rates.

TABLE 3-2



# NO

x 

# Control Technology Projected Emission Rates

Naughton 2

Technology Projected Emission Rate

(Pound per million British

thermal units)

Low-NO

x

# Burner (LNB) with Over-fire Air (OFA) 0.24

Rotating Opposed Fire Air (ROFA) 0.26

LNB with OFA and Selective Non-catalytic Reduction 0.19

LNB with OFA and Selective Catalytic Reduction 0.07



# Step 3: Evaluate Effectiveness of Remaining Control Technologies

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

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

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

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

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

preliminary proposals must be qualified, contract ual guarantees can be established only after

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

technologies and the control effectivene ss 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.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR NAUGHTON UNIT 2



# Low-NO

x 

# burners and OFA are considered to be a capital cost, combustion technology

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

data from boiler vendors indi cating that a new re trofit of LNBs and OFA at Naughton 2

would result in an expected NO

x 

# emission rate of 0.24 pound per MMBtu. PacifiCorp has

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

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

between overhauls, which would rate repr esent a significant reduction from the NO

x 

# emission rate of 0.54 pound per MMBtu.

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

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

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

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

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

combustion air is also mixed more effectively.”

A typical ROFA installation woul d have a booster fan(s) to suppl y the high-velocity air to the

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

Mobotec expects to achieve a NO

x 

# emission rate of 0.24 pound per MMBtu using ROFA

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

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

Under the Mobotec proposal, which was primaril y based on ROFA equipment, the operation

of existing burners was analyzed. While a typica l installation does not require modification to

the existing burner system, results of co mputational fluid dynamics modeling would

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

bent-tube assemblies for OFA port installation.

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

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

construction supervisor duri ng installation and startup.

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

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

sub-bituminous coals, ROFA was not consider ed in the post-contro l modeling scenarios.

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

NO

x 

# on smaller units. With SNCR, an amine-ba sed reagent such as ammonia or, more

commonly, urea is injected in to the furnace within a temperature range of 1,600°F to

2,100°F, where the temperature reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to

60 percent have been achieved, although 20 to 40 percent is more realistic for most

applications.

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NO

x 

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

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

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

downstream. The ammonia might render fly ash uns aleable, might react with sulfur to foul

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR NAUGHTON UNIT 2



# have a significant impact on economics, with higher levels of NO

x 

# reduction generally

resulting in lower reagent utiliz ation and higher operating cost.

Reductions from higher baseline concentrations (inlet NO

x 

# ) are lower in cost per ton but

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

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

a NO

x 

# emission rate of 0.24 pound per MMBtu, woul d be installed in conjunction with

SNCR

. At Naughton 2, a further reduction of 20 percent in NO

x 

# emission rates results in a

projected emission rate of 0.19 pound per MMBtu for SNCR.

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

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

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

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

a catalyst to promote the reacti on. Ammonia is injected into th e flue-gas stream, where it

reduces NO

x 

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

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

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

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

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

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

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

located in the existing gas duc t, which could be expanded in the area of the catalyst to

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

as the basis for analysis at Naughton 2.

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

SNCR, reducing NO

x 

# emission levels as much as possible through combustion modifications

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

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

modifications, including LNBs a nd OFA that would provide a NO

x 

# emission rate of

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

basis results in a projected NO

x 

# emission rate of 0.07 pound per MMBtu. Additional catalyst

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

at Naughton 2.

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

NO

x 

# emissions needed to consistently achieve co mpliance with an established goal, a review

of typical NO

x 

# emissions from coal-fired generating un its was completed. During this review,

NO

x 

# emissions were noted to vary signifi cantly around an average emissions level.

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

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

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

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

value:

• Establish expected NO

x 

# emissions value from vendor.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR NAUGHTON UNIT 2



# • Evaluate vendor’s experience and histori cal basis for achieving expected values.

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

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

less variant the NO

x 

# emissions are.

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

NO

x 

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

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

made.

Step 4: Evaluate Impacts and Document Results

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

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

considered during this evaluation.

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

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

have energy impacts.

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

ROFA fan.

SCR retrofit affects the existing flue-gas fan systems due to the additional pressure drop

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

requirements for SCR instal lation at Naughton 2 are estim ated at approximately

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

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

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

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

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

could result in higher unbur ned carbon in the ash.

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

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

improvements to visibility. Other environmen tal impacts involve the storage of ammonia,

especially if anhydrous ammonia is used, and th e transportation of the ammonia to the power

plant site.

Economic Impacts. PacifiCorp furnished CH2M HILL the costs and schedules for the LNBs

and OFA, SNCR, and SCR, all of which were developed using the S&L internal proprietary

database and supplemented (as needed) by ve ndor-obtained price quotes. The relative

accuracy of these cost estimates is stated by S&L to be plus or minus 20 percent. Cost for the

ROFA system was obtained from Mobotec, to wh ich construction and other costs were added

to make a comparable estimate.

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

of NO

x 

# removed is summarized in Table 3-3. Th e first year control costs are shown in

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-12



# TABLE 3-3



# NO

x 

# Control Cost Comparison

Naughton 2

Factor Low-NO

x 

# Burner

(LNB) with

Over-fire Air

(OFA) Rotating

Opposed

Fire Air

(ROFA) LNB with

OFA and

Selective

Non-catalytic

Reduction LNB with

OFA and

Selective

Catalytic

Reduction

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

Total First Year Fixed and Variable

Operations and Maintenance (O&M)

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

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

Power Consumption (megawatts)

-- 2.6 0.2 1.3

Annual Power Usage (1,000 megawatt

hours per year) -- 20.6 1.7 10.6

Nitrogen Oxide (NO

x 

# ) Design Control

Efficiency 55.6% 51.9% 64.8% 87.0%

Tons NO

x

# Removed per Year 2,838 2,649 3,311 4,446

First Year Average Control Cost ($ per ton

of NO

x

# Removed) 280 814 833 1,920

Incremental Control Cost ($ per ton of

NO

x

# Removed) 280 814 4,152 3,550



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

BART for Naughton 2. This recommendation is based on the signifi cant reduction in NO

x 

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

additional power requirements or environmenta l impacts. As previously discussed, the

recommended technology and the achieved emi ssion rate are deemed appropriate as BART

for NO

x 

# emissions from the coals combusted at Naughton 2.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR NAUGHTON UNIT 2FIGURE 3-4First Year Control Cost for NOxAir Pollution Control OptionsNaughton 205001,0001,5002,0002,5003,0003,5004,0004,500LNB 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_NAUGHTON2__OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR NAUGHTON UNIT 2



# 3.2.2 BART SO 2 

# Analysis

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

on sulfur content in the coal. The BART analysis for SO 2 

# emissions at Naughton 2 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 2. This included control

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

The following potential SO 2 

# control technology options were considered:

• 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 2 currently has an uncontrolled SO 2 

# emission rate of approximately 1.20 pound 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 2, this dry particulate matter would be

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

typically produces a dry waste 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. The resulting controlled SO 2 

# emission rate from Naughton 2 would be

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

weight.

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

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

0.15 pound of SO 2 

# per MMBtu.

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

filter located downstream of the lime spray dryer, then an 87.5 percent SO 2 

# removal is

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

0.15 pound of SO 2 

# per MMBtu.

However, if higher-sulfur coal (with 1.02 percent sulfur) is used, the controlled SO 2 

# emission

rate is projected to be 0.21 pound of SO 2 

# 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)

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR NAUGHTON UNIT 2



# reagent reacts with the SO 2 

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

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

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

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

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

developers. These variations include using a jet bubbling reactor as a combination SO 2 

# absorber and calcium sulfite oxidation vessel, 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 2, this removal efficiency is projected to meet a limit of 0.15 pound of SO 2 

# per

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

Step 3: Evaluate Effectiveness of Remaining Control Technologies

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

evaluated for Naughton 2.

TABLE 3-4



# SO 2 

# Control Technology Emission Rates

Naughton 2

Control Technology Projected SO 2 

# Emission Rate

(pound per million Brit ish thermal units)

Dry Flue Gas Desulfurization (F GD) with Existing Electrostatic

Precipitator (ESP) 0.41

Dry FGD with Fabric Filter 0.15

Wet FGD with Existing ESP and New Stack 0.10



# Step 4: Evaluate Impacts and Document Results

This step involves the 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 2 using the existing ESP would re quire approximately 2.2 MW of power,

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

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

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

Naughton 2.

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

when compared to wet FGD technology:

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR NAUGHTON UNIT 2



# • Sulfuric Acid Mist. Sulfur trioxide (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 might

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

SO 3 

# , when medium- to high-sulfur coal is bur ned in a unit. Otherwise, the emission of

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

vapor plume dissipates.

• Plume Buoyancy

. Flue gas following a dry FGD 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

. No liquid waste results from use of a dry FGD system.

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

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

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

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

contain toxic metals and might require special considerations for disposal.

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

solid waste handling and disposal challenge. This sludge 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 of.

• Makeup Water Requirements

. Dry FGD has the advantages over a wet scrubber of

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

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

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

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

# removed for each technology

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

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

Preliminary BART Selection. CH2M HILL recommends the 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 Na ughton 2. This recommendation is based on

significant reduction in SO 2 

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

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

FGD system and existing ESP.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-17



# TABLE 3-5



# SO 2 

# Control Cost Comparison (Incremental to Existing FGD System)

Naughton 2

Factor Dry Flue Gas

Desulfurization

(FGD) with

Electrostatic

Precipitator

(ESP) Dry FGD with

Fabric Filter Wet FGD

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

Total First Year Fixed & Variable Operations &

Maintenance Costs $6.5 million $5.5 million $5.9 million

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

Power Consumption (megawatts) 2.2 3.6 3.3

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

Sulfur Dioxide (SO 2 

# ) Design Control Efficiency 80.1% 87.3% 91.5%

Tons SO 2 

# Removed per Year 15,645 9,768 10,241

First Year Average Control Cost

($ per ton of SO 2 

# Removed) 955 1,934 1,752

Incremental Control Cost

($ per ton of SO 2 

# Removed) 955 1,934 1,752BART ANALYSIS FOR NAUGHTON UNIT 2FIGURE 3-5First Year Control Cost for SO2Air Pollution Control OptionsNaughton 205001,0001,5002,0002,500Dry 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_NAUGHTON2__OCT2007_FINAL.DOC3-18

# BART ANALYSIS FOR NAUGHTON UNIT 2



# 3.2.3 BART PM 10



# Analysis

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

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

then attracting these charged particles to grounded collection plates. A layer of collected

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

plates. The collected ash particles drop into hoppers below the precip itator and are removed

periodically by the fly ash-handling system . Historically, the ESP at Naughton 2 has

controlled PM 10 

# emissions to level of 0.064 pound per MMBtu.

The BART analysis for PM 10 

# emissions from Naughton 2 is desc ribed in the following steps.

For the modeling analysis in Section 4, PM 10 

# was used as an indicator for PM, and PM 10



# includes PM 2.5 

# as a subset.

Step 1: Identify Available Retrofit Control Technologies

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

• Flue gas conditioning (FGC)

• Polishing fabric filter

• Replacement of fabric filter

Step 2: Eliminate Technically Infeasible Options

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

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

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

typically is accomplished by injection of SO 3 

# , will lower the resistivity of the particles so that

they will accept more charge, allowing the ESP to collect the ash more effectively. Adding

FGC can account for large improvements in collection efficiency for small ESPs.

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

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

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

COHPAC collects the ash that the ESP does not collect, thus acting as a polishing device.

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

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

The smaller size is due to the fact that the COHP AC has a higher air-to-clo th ratio (7 to 9:1),

compared to the ratio of a full-sized pul se jet fabric filt er (3.5 to 4:1).

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

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

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

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

lower costs) installation of a full fabric f ilter was not consider ed in the analysis.

Step 3: Evaluate Effectiveness of Remaining Control Technologies

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-19

# BART ANALYSIS FOR NAUGHTON UNIT 2



# approximately 0.040 pound per MMBtu. Adding a COHP AC fabric filter downstream of the

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

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

per MMBtu.

A summary of the PM 10 

# control technology emission rate s is shown in Table 3-6.

TABLE 3-6



# PM 10



# Control Technology Emission Rates

Naughton 2

Control Technology Projected PM 10 

# Emission Rate

(pound per million British

thermal units)

Flue Gas Conditioning 0.040

Polishing Fabric Filter 0.015

Replacement Fabric Filter 0.015



# Step 4: Evaluate Impacts and Document Results

This step involves the 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 asso ciated ductwork. Therefore, a COHPAC retrofit would require

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

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

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

annual plant capacity factor.

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

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

COHPAC polishing fabric filter or FGC system.

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

conditionings are recorded in Table 3-7, and the fi rst year of control co sts for FGC and fabric

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-20

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 3-21 

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

existing ESP as BART for Naughton 2. This re commendation is based on the significant

reduction in PM 10 

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

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

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.

TABLE 3-7



# PM 10



# Control Cost Comparison

Naughton 2

Factor Flue Gas

Conditioning Polishing Fabric Filter

Total Installed Capital Costs $1.3 million $34.9 million

Total First Year Fixed and Variable Operation and

Maintenance Costs $0.1 million $0.8 million

Total First Year Annualized Cost $0.2 million $4.1 million

Power Consumption (megawatts) 0.1 1.4

Annual Power Usage (1,000 megawatt hours per

year) 0.4 10.9

PM Design Control Efficiency 37.5% 76.6%

Tons Particulate Matter (PM) Removed per Year 227 464

First Year Average Control Cost

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

Incremental Control Cost

($ per ton of PM Removed) 949 16,432BART ANALYSIS FOR NAUGHTON UNIT 2FIGURE 3-6First Year Control Cost for PM Air Pollution Control OptionsNaughton 202,0004,0006,0008,00010,00012,00014,00016,00018,000Flue Gas ConditioningFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC3-22

# 4.0 BART Modeling Analysis

4.1 Model Selection

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

visibility impacts of emissions from Naughton 2 at Class I areas. The Cl ass I areas potentially

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

These wilderness areas (WA) include:

• Bridger WA

• Fitzpatrick WA

The CALPUFF modeling system includes the CALMET meteorological model with

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

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

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

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

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

CH2M HILL used the CALMET model to 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 Naughton 2 and to in clude a 50-kilometer buffer around the Class I

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

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

otherwise by the Wyoming Department of E nvironmental Quality – Air Quality Division

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

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

protocol.

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

large extent of the domain. The latitude of the projection 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_NAUGHTON2__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 2



# The default technical options listed in current exampl e CALMET.inp file of TRC

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

included 10 layers, with vertical fa ce 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, which

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

analysis.

TABLE 4-1



# User-specified CALMET Options

Naughton 2

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500



# 4.2.2 CALMET Input Data

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

WDEQ-AQD provided 12-kilometer-resoluti on Mesoscale Meteorological Model,

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

each year.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-4 

# These three data sets were chosen because 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.

CALMET adjusted the initial gue ss wind field for local terra in 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 from the Auto mated Surface Observing System network of

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

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

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

SMERGE preprocessor and CALMET.

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

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

Level 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 data were filled with values that were assumed

appropriate for the missing area.

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

fixed-length, TD-3240 format were ordered 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 2



# 4.2.3 Validation of CALMET Wind Field

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

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

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

conditions, as depicted in surface and upper-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 (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 prec ontrol (baseline) scenario fo r comparison to the predicted

impacts for post-control scenarios for Naughton 2.



# 4.3.1 Background Ozone and Ammonia

CALPUFF used hourly values of background ozone concentrations for the calculation of 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. Backgr ound ammonia was set to 2 parts per billion

(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 2. 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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-7 

# Regulations and Guidelines for Best Availabl e Retrofit Technology De terminations; Final

Rule (40 CFR Part 51).

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

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

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

emissions or short-term emission limits were used if continuous-em ission 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 precontrol scenario.



# 4.3.4 Post-control Scenarios

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

the combination of the individual NO

x 

# , SO 2 

# , and PM control technol ogies being evaluated.

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

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

levels for each pollutant.

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

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

represents the preliminary BART recommendation of CH2M HILL.

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

filter.

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

fabric filter.

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

enhanced ESP performance, and a new stack.

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

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

protocol, elemental carbon stack emissions and organic aerosol emissi ons were not modeled.TABLE 4-2BART Model Input DataNaughton 2BaselinePost-control Scenario 1 Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Model Input DataCurrent Operations with ESP LNB with OFA, Dry FGD, ESPLNB with OFA, Dry FGD, NewFabric FilterLNB with OFA and SCR, DryFGD, Fabric FilterLNB with OFA and SCR, WetFGD, ESP (New Stack)Sulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])2,868 984 359 359 239Nitrogen Oxide (NOx) Stack Emissions (lb/hr)1,291576574167167PM10Stack Emissions (lb/hr)154 96.0 36.0 36.0 96.0Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)65.841.320.420.441.1Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)87.254.715.415.454.5Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 44.2 2.16 2.16 3.12 37.9H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 43.3 2.12 2.12 3.06 37.2Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)0.552.76(NH4)2SO4as SO4Stack Emissions (lb/hr)0.402.01(NH4)HSO4Stack Emissions (lb/hr)1.04.80(NH4)HSO4as SO4Stack Emissions (lb/hr)0.804.01Total Sulfate (SO4) (lb/hr)43.1 2.12 2.11 4.24 43.0Stack ConditionsStack Height (meters)68 68 68 68 152Stack Exit Diameter (meters)4.88 4.88 4.88 4.88 5.49Stack Exit Temperature (Kelvin) 411 350 343 343 323Stack Exit Velocity (meters persecond) 27.8 20.21 24.3 24.3 18.5Notes:(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. PM10and PM2.5refer to particulate matter less than 10 and 2.5 micrometers, respectively, in aerodynamicdiameter.(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 2



# 4.3.5 Modeling Process

The CALPUFF modeling for the control techno logy options for Naughton 2 followed this

sequence:

• Model precontrol (baseline) emissions

• Model preferred post-control scenario (if applicable)

• Determine degree of visibility improvement

• Model other control scenarios

• Determine degree of visibility improvement

• Factor visibility results into the BART five-step evaluation



# 4.3.6 Receptor Grids

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

along the boundary and in the interior of each 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 and long itude 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. Calc ulations of light extinction were made for

each pollutant modeled. The sum of all extinc tion values were used to calculate the

delta-dV ( Δ dV) change in deciview relative to natural background. Default extinction

coefficients for each pollutant, as shown below, were used.

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 

# ) 0.6

• PM fine (PM 2.5 

# ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0

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

humidity factors [ƒ(RH)] were used in the li ght-extinction calculations to account for the

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

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

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

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

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

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

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

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-9

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 4-10 

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

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

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

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

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

Improvement Modeling Analysis in North Dakota (North Dakota Depa rtment of Health;

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

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

lists the annual average species conc entrations from the BART protocol.

TABLE 4-3



# Average Natural Levels of Aerosol Components

Naughton 2

Aerosol Component Average Natural Concentration

Bridger and Fitzpatrick WA Class I Areas

(micrograms per cubic meter)

Ammonium Sulfate 0.045

Ammonium Nitrate 0.038

Organic Carbon 0.178

Elemental Carbon 0.008

Soil 0.189

Coarse Mass 1.136

NOTE:

Source: WDEQ-AQD, 2006



# 4.5 Presentation of Modeling Results

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

for Naughton 2.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

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

post-control scenarios included emission rates for SO 2 

# , NO

x 

# , and PM 10 

# that would be

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

Baseline and post-control 98 th 

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

WA and Fitzpatrick WA. The 98 th 

# percentile results for each Class I area are presented in

Table 4-4.BART ANALYSIS FOR NAUGHTON UNIT2TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasNaughton 2ModelingResultsScenarioTotal FirstYearAnnualizedCostClass I AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)No. of Days Above0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2001Bridger WA5.4202.12761----Baseline: current operation withelectrostatic precipitator(ESP)Fitzpatrick WA3.2771.15826----$15,951,704Bridger WA2.6350.83828$12,375,255$483,385Scenario 1: Low-NOxburner (LNB) with over-fire air (OFA),dry flue gas desulfurization (FGD), ESP$15,951,704Fitzpatrick WA1.5150.4626$22,919,115$797,585$19,686,224Bridger WA2.0780.64214$38,151,597$1,640,519$19,053,673$266,751Scenario 2: LNB with OFA,dry FGD, fabric filter$19,686,224Fitzpatrick WA1.1130.3123$23,269,768$855,923$24,896,800$1,244,840$27,429,327Bridger WA0.9490.2842$14,882,977$464,904$21,628,779$645,259Scenario 3: LNB with OFA and selective catalytic reduction(SCR), dry FGD, fabric filter$27,429,327Fitzpatrick WA0.5190.1581$27,429,327$1,097,173$50,279,890$3,871,552$26,693,951Bridger WA1.6270.4827$16,227,326$494,332NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$26,693,951Fitzpatrick WA0.7170.2082$28,098,896$1,112,248NANA2002Bridger WA4.3491.86056----Baseline: current operation with ESPFitzpatrick WA3.9001.09924----$15,951,704Bridger WA1.7280.92618$17,078,912$419,782Scenario 1: LNB with OFA, dry FGD, ESP$15,951,704Fitzpatrick WA1.6670.4135$23,253,213$839,563$19,686,224Bridger WA1.3890.74511$17,655,806$437,472$20,632,707$533,503Scenario 2: LNB with OFA,dry FGD, fabric filter$19,686,224Fitzpatrick WA1.1530.2864$24,214,298$984,311$29,405,669$3,734,520$27,429,327Bridger WA0.6180.3213$17,822,825$517,534$18,262,035$967,888Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$27,429,327Fitzpatrick WA0.5420.1411$28,631,865$1,192,579$53,400,710$2,581,034$26,693,951Bridger WA1.0760.3544$17,725,067$513,345NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$26,693,951Fitzpatrick WA0.8870.1381$27,777,264$1,160,607NANAJMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC4-11BART ANALYSIS FOR NAUGHTON UNIT 2JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC4-12TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasNaughton 2ModelingResultsScenarioTotal FirstYearAnnualizedCost Class I AreaHighest DeltaDeciview (ΔdV)98thPercentileDelta-Deciview(ΔdV)No. of Days Above0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove 0.5 dVIncrementalCost per dVReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2003Bridger WA4.6782.08755----Baseline: current operation with ESPFitzpatrick WA2.4661.11022----$15,951,704Bridger WA2.1360.88219$13,237,929$443,103Scenario 1: LNB with OFA, dry FGD, ESP$15,951,704Fitzpatrick WA1.2960.4486$24,096,230$996,982$19,686,224Bridger WA1.7350.61412$13,364,714$457,819$13,934,776$533,503Scenario 2: LNB with OFA,dry FGD, fabric filter$19,686,224Fitzpatrick WA0.8550.3134$24,700,407$1,093,679$27,663,111$1,867,260$27,429,327Bridger WA0.7910.2913$15,272,454$527,487$23,972,455$860,345Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$27,429,327Fitzpatrick WA0.4650.1480$28,512,814$1,246,788$46,927,897$1,935,776$26,693,951Bridger WA1.1020.5268$17,100,545$567,956NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$26,693,951Fitzpatrick WA0.3630.1620$28,158,176$1,213,361NANA3-Year AveragesBridger WA2.02557.3Baseline: current operation with ESPFitzpatrick WA1.12224.0$15,951,704Bridger WA0.88221.7$13,960,068$447,244Scenario 1: LNB with OFA, dry FGD, ESP$15,951,704Fitzpatrick WA0.4415.7$23,412,481$870,093$19,686,224Bridger WA0.66712.3$14,500,042$437,472$17,369,860$400,127Scenario 2: LNB with OFA,dry FGD, fabric filter$19,686,224Fitzpatrick WA0.3043.7$24,046,691$968,175$27,193,107$1,867,260$27,429,327Bridger WA0.2992.7$15,891,846$501,756$21,021,999$801,011Scenario 3: LNB with OFA and SCR, dry FGD, fabric filter$27,429,327Fitzpatrick WA0.1490.7$28,180,815$1,175,543$50,063,166$2,581,034$26,693,951Bridger WA0.4546.3$16,995,300$523,411NANAScenario 4: LNB with OFA and SCR, wet FGD, ESP, newstack$26,693,951Fitzpatrick WA0.1691.0$28,010,442$1,160,607NANANOTES:Scenario 4 produces worse results than Scenario 3.Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $15,951,704/ (2.306 - 0.908) = $11,410,375Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $15,951,704 / (76 - 32) = $362,539

# 5.0 Preliminary Assessment and

Recommendations

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

modeling analysis completed for Naughton 2, th e preliminary recommended BART controls

for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# New LNBs and OFA system for NO

x 

# control

• 

# Lime spray dryer FGD for SO 2 

# control and a coal sulfur limit less than 1.02 weight

percent

• 

# Add FGC ahead of the existing ESP for PM control

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

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

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

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

hereafter as the NSR Manual.



# 5.1 Least-cost Envelope Analysis

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

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



# 5.1.1 Analysis Methodology

On page B-41 of the NSR Manual, the EP A states (EPA, 1990): “Incremental costeffectiveness comparisons should focus on annualized cost and emission reduction

differences between dominant alternatives. Dominant set of control alternatives are

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

graphical plot of total annua lized costs for a total emissions reductions for all control

alternatives identified in the BACT analysis.”

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

performed in the following manner. First, the control option scen arios are ranked in

ascending order of annualized total costs as s hown in Tables 5-1 and 5-2. The incremental

cost-effectiveness data, expressed per day a nd per dV reduction, repr esent a comparison of

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

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

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

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

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

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

by the operation of Naughton 2.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR NAUGHTON UNIT 2



# TABLE 5-1



# Bridger WA Class I Agent Control Data

Naughton 2

Scenario Controls 98 th



# Percentile

deciview

(dV(

Reduction Exceedance

Reduction

(Days) Total

Annualized

Cost

(million$) Cost per

dV

Reduction

(million$/

dV

Reduced) Cost per

Reduction

in No. of

Days Above

0.5 dV

(million$/

Day

Reduced)

Base Current Operation with

Electrostatic Precipitator

(ESP) 0.00 0.0 $0.0 $0.0 $0.0

1 Low-NO

x 

# Burner (LNB)

with Over-fire Air (OFA),

Dry Flue Gas

Desulfurization (FGD),

ESP 1.14 35.7 $16. 0 $14.0 $0.4

2 LNB with OFA, Dry FGD,

New Fabric Filter 1.36 45.0 $19. 7 $14.5 $0.4

3 LNB with OFA and

Selective Catalytic

Reduction (SCR), Dry

FGD, Fabric Filter 1.73 54.7 $27. 4 $15.9 $0.5

4 LNB with OFA and SCR,

Wet FGD, ESP, New

Stack 1.57 51.0 $26. 7 $17.0 $0.5

TABLE 5-2



# Fitzpatrick WA Class I Area Control Data

Naughton 2

Scenario Controls 98 th



# Percentile

dV

Reduction Exceedance

Reduction

(Days) Total

Annualized

Cost

(million$) Cost per dV

Reduction

(million$/dV

Reduced) Cost per

Reduction in

No. of Days

Exceeding

0.5 dV

(million$/Day

Reduced)

Base Current Operation wi th ESP 0.00 0.0 $0.0 $0.0 $0.0

1 LNB with OFA, Dry FGD,

ESP 0.68 18.3 $16. 0 $23.4 $0.9

2 LNB with OFA, Dry FGD,

New Fabric Filter 0.82 20.3 $19. 7 $24.0 $1.0

3 LNB with OFA and SCR,

Dry FGD, Fabric Filter 0.97 23.3 $27. 4 $28.2 $1.2

4 LNB with OFA and SCR,

Wet FGD, ESP, New Stack 0.95 23.0 $26. 7 $28.0 $1.2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-2

# BART ANALYSIS FOR NAUGHTON UNIT 2



# TABLE 5-3



# Bridger WA Class I Agent Incremental Data

Naughton 2

Options Compared Incremental

Exceedance

Reductions

(Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(million$/Days) Incremental

Cost

Effectiveness

(million$/dV)

Baseline and Scenario 1 35.7 1.14 $0.45 $13.96

Scenario 1 and Scenario 2 9.3 0.22 $0.4 $17.4

Scenario 1 and Scenario 3 19.0 0.58 $0.6 $19.7

Scenario 1 and Scenario 4 15.3 0.43 $0.7 $25.1

NOTE:

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

TABLE 5-4



# Fitzpatrick WA Class I Area Incremental Data

Naughton 2

Options Compared Incremental

Exceedance

Reductions

(Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(million$/Days) Incremental

Cost

Effectiveness

(million$/dV)

Baseline and Scenario 1 18.3 0.68 $0.87 $23.41

Scenario 1 and Scenario 2 2.0 0.14 $1.9 $27.2

Scenario 1 and Scenario 3 5.0 0.29 $2.3 $39.3

Scenario 1 and Scenario 4 4.7 0.27 $2.3 $39.5

NOTE:

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-3

# BART ANALYSIS FOR NAUGHTON UNIT 2



# FIGURE 5-1



# Least-cost Envelope Bridger WA Cl ass I Area Reduction Days Reduction

Naughton 2

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



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

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



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



# 0



# FIGURE 5-2



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



# Percentile dV Reduction

Naughton 2

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3



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

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00



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



# JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-4

# BART ANALYSIS FOR NAUGHTON UNIT 2



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick WA Class I Area Days Reduction

Naughton 2

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4



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

0 5 10 15 20 25



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



# FIGURE 5-4



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



# Percentile dV Reduction

Naughton 2

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0.00 0.20 0.40 0.60 0.80 1.00 1.20



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



# JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-5

# BART ANALYSIS FOR NAUGHTON UNIT 2



# 5.1.2 Analysis of Results

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

the selection of Scenario 1, ba sed on incremental cost and visibility improvements. The other

scenarios were eliminated for the following reasons:

• Scenario 2 is to the left of the curve fo rmed by the “dominant” control alternative

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

• Scenario 3 has high incremental costs on the ba ses of a cost per day of improvement and

a cost per dV reduction.

• While Scenario 4 provides some potential vi sibility advantage ov er Scenario 1, the

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

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

Thus, the scenario was eliminated from consideration.

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

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

# percentile dV and

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

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

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



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

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

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

per dV.

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

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

than in the Bridger WA. Therefore, the EPA L east-cost Analysis indi cates that Scenario 1

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

Scenario 1.



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

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

produce higher NO

x 

# emissions than typical sub-bitumi nous coals, such as PRB coals.

CH2M HILL recommends LNB with OFA as BART for Naughton 2, 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 LNB with OFA at Naughton 2 is projected to

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

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-6

# BART ANALYSIS FOR NAUGHTON UNIT 2

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 

# 5-7 

# 5.2.2 SO 2 

# Emission Control

CH2M HILL recommends inst alling a dry lime FGD syst em as BART for Naughton 2,

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

recommendation is based on the significant reduction in SO 2 

# emissions, reasonable control

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

quality environmental impacts.



# 5.2.3 PM 10



# Emission Control

CH2M HILL recommends the addition of an FG C system to enhance the performance of the

existing ESP as BART for Naughton 2. This reco mmendation is based on the 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 (2002), state that onl y dV differences of approximately 1.5 to

2.0 dV or more are perceivable by the human ey e. Deciview changes of less than 1.5 cannot

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

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

under any of the scenarios. Thus, the results indicate that, although many millions of dollars

would be spent, only minimal visi bility improvements might result.

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

through 2003, several mega-wildfire s occurred and lasted for many days, and the fires could

have had a significant impact on vi sibility in these Class I areas . If natural obscuration were

to reduce the visibility impacts modeled fo r the Naughton 2 facilit y, the costs per dV

reduction that are presented in this report would increase.

# 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

.

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

and Nonattainment Area Permitting . Draft. October 1990.

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

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

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

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

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

http://docs.lib.noaa.gov/rescue/dwm/d ata_rescue_daily_weather_maps.html

. Accessed October 2006.

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

Improvement Modeling Analysis in North Dakota . North Dakota Department of

Health. October 26, 2005.

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

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

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

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

Quality Division. September 2006.

JMS EY102007001SLC\BART_NAUGHTON2__OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios8Index No. Name of Unit1 Dave Johnston Unit 32 Dave Johnston Unit 43 Jim Bridger Unit 14 Jim Bridger Unit 25 Jim Bridger Unit 36 Jim Bridger Unit 47 Naughton Unit 18 Naughton Unit 29 Naughton Unit 310 WyodakScenario First Year Cost ScenarioFirst YearCost Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/A N/A N/A $ 15,951,704 N/AN/A N/A N/A $ 15,951,704 N/AN/A N/A N/A $ 19,686,224 N/AN/A N/A N/A $ 19,686,224 N/AN/A N/A N/A $ 27,429,327 N/AN/A N/A N/A $ 27,429,327 N/AN/A N/A N/A $ 26,693,951 N/AN/A N/A N/A $ 26,693,951 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 2Scenario 3 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 2 - LNB with OFA, Dry FGD,Fabric FilterScenario 1 - LNB with OFA, Dry FGD, ESPBaseline - Current Operation with Dry FGD,ESPWyodakWyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYNaughton Unit 2Boiler 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 ($)0 7,500,001 10,586,222 19,878,765 72,960,588 88,896,713 141,244,778 126,095,338 1,298,352 34,898,710FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 506,128 506,128 809,804 0 0Maintenance Material ($) 0 32,000 48,000 93,000 160,000 860,174 905,190 1,226,386 0 45,016Maintenance Labor ($) 0 48,000 72,000 139,500 240,000 573,044 640,568 817,591 10,000 67,524Administrative Labor ($) 0 0 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 80,000 120,000 232,500 400,000 1,939,345 2,051,885 2,853,781 10,000 112,540Makeup Water Cost 0 0 0 0 0 94,962 94,962 126,616 0 0Reagent Cost 0 0 0 547,170 365,145 2,425,901 1,141,778 954,332 62,194 0SCR Catalyst / FF Bag Cost 0 0 0 0 303,000 0 124,072 0 0 124,072Waste Disposal Cost 0 0 0 0 0 1,139,518 612,026 711,213 0 0Electric Power Cost 0 0 1,028,842 86,724 527,834 886,556 1,431,734 1,300,860 19,710 545,179TOTAL VARIABLE O&M COST0 0 1,028,842 633,894 1,195,979 4,546,936 3,404,572 3,093,020 81,904 669,251TOTAL FIRST YEAR O&M COST 0 80,000 1,148,842 866,394 1,595,979 6,486,281 5,456,457 5,946,802 91,904 781,791FIRST YEAR DEBT SERVICE ($)0 713,459 1,007,044 1,891,024 6,940,582 8,456,551 13,436,308 11,995,175 123,509 3,319,838TOTAL FIRST YEAR COST ($)0 793,459 2,155,887 2,757,418 8,536,561 14,942,832 18,892,766 17,941,977 215,414 4,101,629Power Consumption (MW) 0.0 0.0 2.6 0.2 1.3 2.2 3.6 3.3 0.1 1.4Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 20.6 1.7 10.6 17.7 28.6 26.0 0.4 10.9CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0% 55.6% 51.9% 64.8% 87.0% 0.0% 0.0% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 2,838 2,649 3,311 4,446 0 0 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 280 814 833 1,920 0 0 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 280 814 4,152 3,550 0 0 0 0 02-1 3-1 4-2 5-3SO2 Removal Rate (%)0.0% 0.0% 0.0% 0.0% 0.0% 80.1% 87.3% 91.5% 0.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 15,645 9,768 10,241 0 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 955 1,934 1,752 0 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 955 1,934 1,752 0 06-1 7-1 8-1PM Removal Rate (%) 98.43% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 37.50% 76.56%PM Removed (Tons/Yr) 0 0 0 0 0 0 0 0 227 464First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 0 0 949 8,848Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 0 0 949 16,4329-1 10-9PRESENT WORTH COST ($)0 8,477,429 24,622,608 30,464,242 92,460,027 168,145,144 207,910,972 198,752,487 2,421,226 44,450,517PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls1 of 1INPUT CALCULATIONSNaughton Unit 2Boiler 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)210,000 210,000210,000 210,000 210,000 210,000 210,000 210,000 210,000 210,000Net Plant Heat Rate (Btu/kW-Hr)11,42811,428 11,428 11,428 11,428 11,428 11,428 11,428 11,428 11,428Boiler 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)2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400 2,400Coal Flow Rate (Lb/Hr)244,886 244,886 244,886 244,886 244,886 243,026 244,886 244,886 244,886 244,886(Ton/Yr)965,339 965,339 965,339 965,339 965,339 958,008 965,339 965,339 965,339 965,339(MMBtu/Yr)18,920,65418,920,65418,920,65418,920,65418,920,65418,920,65418,920,65418,920,65418,920,65418,920,654EmissionsUncontrolled SO2 (Lb/Hr)2,838 2,838 2,838 2,838 2,838 4,953 2,838 2,838 2,838 2,838(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)44.30 44.30 44.30 44.30 44.30 77.31 44.30 44.30 44.30 44.30(Tons/Yr)11,187 11,187 11,187 11,187 11,187 19,524 11,187 11,187 11,187 11,187SO2 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 3,969 2,478 2,598 0 0(Ton/Yr)0 0 0 0 0 15,645 9,768 10,241 0 0SO2 Emission Rate (Lb/Hr)2,838 2,838 2,838 2,838 2,838 984 360 240 2,838 2,838(Lb/MMBtu)1.181.18 1.18 1.18 1.180.41 0.15 0.101.18 1.18(Ton/Yr)11,187 11,187 11,187 11,187 11,187 3,879 1,419 946 11,187 11,187Uncontrolled NOx (Lb/Hr)1,296 1,296 1,296 1,296 1,296 1,296 1,296 1,296 1,296 1,296(Lb/MMBtu)0.540.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54 0.54(Lb Moles/Hr)43.18 43.18 43.18 43.18 43.18 43.18 43.18 43.18 43.18 43.18(Tons/Yr)5,109 5,109 5,109 5,109 5,109 5,109 5,109 5,109 5,109 5,109NOx Removal Rate (%)0.0%55.6%51.9%64.8%87.0%0.0%0.0%0%0.0%0%(Lb/Hr)0 720 672 840 1,128 0 0 0 0 0(Lb Moles/Hr)0.00 23.99 22.39 27.99 37.59 0.00 0.00 0.00 0.00 0.00(Ton/Yr)0 2,838 2,649 3,311 4,446 0 0 0 0 0NOx Emission Rate (Lb/Hr)1,296 576 624 456 168 1,296 1,296 1,296 1,296 1,296(Lb/MMBtu)0.540.24 0.26 0.19 0.070.54 0.54 0.54 0.54 0.54(Ton/Yr)5,109 2,270 2,460 1,797 662 5,109 5,109 5,109 5,109 5,109Uncontrolled Fly Ash (Lb/Hr)9,795 154 154 154 154 154 154 154 154 154(Lb/MMBtu)4.082 0.064 0.064 0.064 0.064 0.064 0.064 0.064 0.064 0.064(Lb Moles/Hr)326.4 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1(Tons/Yr)38,614 605 605 605 605 605 605 605 605 605Fly Ash Removal Rate (%)98.43%0.00%0.00%0.00%0.00%0.00%0.00%0.00%37.50%76.56%(Lb/Hr)9,642 0 0 0 0 0 0 0 58 118(Ton/Yr)38,008 0 0 0 0 0 0 0 227 464Fly Ash Emission Rate (Lb/Hr)154 154 154 154 154 154 154 154 96 36(Lb/MMBtu)0.0640.064 0.064 0.064 0.064 0.064 0.064 0.0640.040 0.015(Ton/Yr)605 605 605 605 605 605 605 605 378 142ParameterCommentsCurrentOperationSO2 ControlNOx ControlPM ControlEY102007001SLC\App A_PCorp Naughton 2 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)07,500,001 10,586,222 19,878,76572,960,588 0 0 0 0 0SO2 Emission Control System ($2006)00 0 0 0 88,896,713 141,244,778 126,095,338 0 0PM Emission Control System ($2006)00 0 0 0 0 0 0 1,298,352 34,898,710Total Emission Control Systems ($2006)0 7,500,001 10,586,222 19,878,76572,960,588 88,896,713 141,244,778 126,095,338 1,298,352 34,898,710NOx Emission Control System ($/kW)0 36 50 95 347 0 0 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 423 673 600 0 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 0 6 166Total Emission Control Systems ($/kW)0 36 50 95 347 423 673 600 6 166Total Fixed Operating & Maintenance CostsOperating Labor ($)0 0 0 0 0 506,128 506,128 809,804 0 0Maintenance Material ($)0 32,000 48,000 93,000 160,000 860,174 905,190 1,226,386 0 45,016Maintenance Labor ($)0 48,000 72,000 139,500 240,000 573,044 640,568 817,591 10,000 67,524Administrative Labor ($)00000 0 0 0 0 0Total Fixed O&M Cost ($)0 80,000 120,000 232,500 400,000 1,939,345 2,051,885 2,853,781 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 0 165 165 220 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 94,962 94,962 126,616 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 0.51 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 0 375 232 6,744 3,174 2,653430First Year Reagent Cost ($)0 0 0 547,170 365,145 2,425,901 1,141,778 954,332 62,194 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags Bags Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000101 0 1,193 0 0 1,193SCR Catalyst ($/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 0 303,000 0 124,072 0 0 124,072Annual 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 11,880 6,381 7,415 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 1,139,518 612,026 711,213 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%1.24%0.10%0.64%1.07%1.73%1.57%0.02%0.66%(MW)0.00 0.00 2.61 0.22 1.34 2.25 3.63 3.30 0.05 1.38Unit 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 1,028,842 86,724 527,834 886,556 1,431,7341,300,860 19,710 545,179Annual 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\App A_PCorp Naughton 2 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\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls1 of 5Table 3 - EmissionsControlledSO2 Controlled NOxControlledPM Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9 Case 101 Dave Johnston Unit 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\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls2 of 5Table 6 - Case 3 O&M Costs (Mobotec ROFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 60,000$ 90,000$ -$ -None - 2.762 Dave Johnston Unit 4-$ 54,000$ 81,000$ $ - -None - 4.333 Jim Bridger Unit 1-$ 42,000$ 63,000$ $ - -None - 6.414 Jim Bridger Unit 2-$ 42,000$ 63,000$ $ - -None - 6.415 Jim Bridger Unit 3-$ 42,000$ 63,000$ $ - -None - 6.416 Jim Bridger Unit 4-$ 42,000$ 63,000$ $ - -None - 6.417 Naughton Unit 1-$ 48,000$ 72,000$ $ - -None - 1.428 Naughton Unit 2-$ 48,000$ 72,000$ $ - -None - 2.619 Naughton Unit 3-$ 48,000$ 72,000$ $ - -None - 4.4710 Wyodak-$ 36,000$ 54,000$$ --None-5.22Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 98,000$ 147,000$ -$ -Urea 0.41 0.232 Dave Johnston Unit 4-$ 105,000$ 157,500$ $ - -Urea 0.45 0.333 Jim Bridger Unit 1-$ 123,000$ 184,500$ $ - -Urea 0.45 0.534 Jim Bridger Unit 2-$ 95,000$ 142,500$ $ - -Urea 0.45 0.535 Jim Bridger Unit 3-$ 122,000$ 183,000$ $ - -Urea 0.45 0.526 Jim Bridger Unit 4-$ 123,000$ 184,500$ $ - -Urea 0.45 0.537 Naughton Unit 1-$ 83,000$ 124,500$ $ - -Urea 0.45 0.168 Naughton Unit 2-$ 93,000$ 139,500$ $ - -Urea 0.51 0.229 Naughton Unit 3-$ 75,000$ 112,500$ $ - -Urea 0.45 0.3310 Wyodak-$ 93,000$ 139,500$--Urea0.450.34Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.AnnualSCRCatalyst Replace.(m3)Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 155,000$ 232,500$ -$ -Anhydrous NH31.00 1281.572 Dave Johnston Unit 4-$ 166,000$ 249,000$ $ - -Anhydrous NH31.00 1232.293 Jim Bridger Unit 1-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 1983.284 Jim Bridger Unit 2-$ 162,000$ 243,000$ $ - -Anhydrous NH31.00 1983.255 Jim Bridger Unit 3-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2003.226 Jim Bridger Unit 4-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2143.367 Naughton Unit 1-$ 132,000$ 198,000$ $ - -Anhydrous NH31.00 670.988 Naughton Unit 2-$ 160,000$ 240,000$ $ - -Anhydrous NH31.00 1011.349 Naughton Unit 3-$ 156,000$ 234,000$ $ - -Anhydrous NH31.00 1671.9910 Wyodak-$ 181,000$ 271,500$$ --Anhydrous NH31.001602.42Annual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls3 of 5Table 9 - Case 6 O&M Costs (Dry FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 -2.492 Dave Johnston Unit 4-$ -$ -$ $ - -Lime- --3 Jim Bridger Unit 1-$ -$ -$ $ - -Lime- --4 Jim Bridger Unit 2-$ -$ -$ $ - -Lime- --5 Jim Bridger Unit 3-$ -$ -$ $ - -Lime- --6 Jim Bridger Unit 4-$ -$ -$ $ - -Lime- --7 Naughton Unit 1506,128$ 587,643$ 391,762$ $ - 120Lime1.40 -1.648 Naughton Unit 2506,128$ 860,174$ 573,044$ $ - 165Lime1.40 -2.259 Naughton Unit 3-$ -$ -$ $ - -Lime- --10 Wyodak-$ 21,900$ 14,600$-25Lime1.10-0.11Table 10 - Case 7 O&M Costs (Dry FGD w/Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3506,128$ 714,175$ 476,928$ -$ 173Lime1.15 1,4573.882 Dave Johnston Unit 4506,128$ 1,102,288$ 734,858$ $ - 248Lime1.10 1,7984.543 Jim Bridger Unit 1-$ -$ -$ $ - -Lime- --4 Jim Bridger Unit 2-$ -$ -$ $ - -Lime- --5 Jim Bridger Unit 3-$ -$ -$ $ - -Lime- --6 Jim Bridger Unit 4-$ -$ -$ $ - -Lime- --7 Naughton Unit 1506,128$ 632,660$ 459,286$ $ - 120Lime1.15 8652.668 Naughton Unit 2506,128$ 905,190$ 640,568$ $ - 165Lime1.15 1,1933.639 Naughton Unit 3-$ 21,900$ 14,600$ $ - 66Waste Liquor1.02 -0.3310 Wyodak-$ 30,660$ 20,440$-30Lime1.10-0.15Table 11 - Case 8 O&M Costs (Wet FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3809,804$ 1,182,587$ 788,391$ -$ 230Lime1.02 -3.452 Dave Johnston Unit 4809,804$ 1,430,784$ 953,856$ $ - 330Lime1.02 1,7986.293 Jim Bridger Unit 1-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.534 Jim Bridger Unit 2-$ 25,550$ 17,033$ $ - 53Soda Ash1.02 -0.535 Jim Bridger Unit 3-$ 25,550$ 17,033$ $ - 52Soda Ash1.02 -0.526 Jim Bridger Unit 4-$ 25,550$ 17,033$ $ - 27Soda Ash1.02 -0.537 Naughton Unit 1809,804$ 963,589$ 642,393$ $ - 160Lime1.05 -2.408 Naughton Unit 2809,804$ 1,226,386$ 817,591$ $ - 220Lime1.05 -3.309 Naughton Unit 3-$ 21,900$ 14,600$ $ - 66Soda Ash1.02 -0.3310 Wyodak303,677$ 328,496$ 218,998$$ -82Lime1.02-1.75Variable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsEY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ -$ $ - -None- --10 Wyodak-$ -$ -$--None---Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak-$ 48,666$ 72,999$$ --None-1,7982.06Table 14 - Major Materials Design and Supply Costs2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3$ 5,449,830 $ 3,556,617 $ 5,773,000 $ 49,355,000 $ 56,379,000 $ 85,647,000 $ 88,913,000 $ - $ 18,359,0002 Dave Johnston Unit 4$ 2,673,501 $ 4,343,192 $ 7,171,085 $ 66,200,000 $ - $ 137,267,000 $ 178,174,384 $ - $ 30,853,5303 Jim Bridger Unit 1$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0004 Jim Bridger Unit 2$ - $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0005 Jim Bridger Unit 3$ 2,981,982 $ 6,056,955 $ 9,419,000 $ 80,923,000 $ - $- $ 8,010,093 $ - $ 29,814,0006 Jim Bridger Unit 4$ 2,981,982 $ 6,056,955 $ 9,528,000 $ 93,009,000 $ - $- $ 3,549,000 $ - $ 29,814,0007 Naughton Unit 1$ 2,502,123 $ 2,675,792 $ 7,257,000 $ 37,292,000 $ 39,617,991 $ 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\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls5 of 5CAPITAL COSTNaughton Unit 2CaseNOx 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 $2,570,674Vendor $3,123,533Vendor $2,570,674Vendor $2,570,674Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$2,193,65385.3%$2,665,42885.3%$2,193,65385.3%$2,193,65385.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$1,328,83751.7%$1,614,62151.7%$1,328,83751.7%$1,328,83751.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$937,0600.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$340,57213.2%$413,81613.2%$340,57213.2%$340,57213.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$422,24616.4%$513,05616.4%$422,24616.4%$422,24616.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$314,09712.2%$381,64812.2%$314,09712.2%$314,09712.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal $7,170,079 $9,649,162 $7,170,079 $7,170,079 $0 $0 $0 $0 $0Contingency12.8%$329,92230.0%$937,06012.8%$329,92212.8%$329,92212.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $7,500,001 $10,586,222 $7,500,001 $7,500,001 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $8,784,000 S&L Report $47,934,000 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0Contingency20.0%$020.0%$020.0%$1,756,80010.0%$4,793,40020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$491,2895.6%$2,680,9495.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$4,048,9858.4%$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%$96,8001.1%$528,2331.1%$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%$246,5670.0%$02.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$1,003,30811.4%$5,475,02111.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $12,378,764 $65,460,588 $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 $54,775,108 S&L Report $87,030,191 S&L Report $77,695,625S&L Report $800,000 S&L Report $21,503,389Contingency20.0%$020.0%$020.0%$020.0%$020.0%$10,955,02220.0%$17,406,03820.0%$15,539,12520.0%$160,00020.0%$4,300,678Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$3,063,5725.6%$4,867,5995.6%$4,345,5165.6%$44,7445.6%$1,202,685EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$4,626,8538.4%$7,351,4408.4%$6,562,9498.4%$67,5768.4%$1,816,391Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$1,541,3722.8%$2,449,0302.8%$2,186,3552.8%$22,5122.8%$605,105Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$603,6221.1%$959,0731.1%$856,2061.1%$8,8161.1%$236,967Escalation10.1%$010.1%$010.1%$010.1%$010.1%$5,537,21610.1%$8,797,88210.1%$7,854,25110.1%$80,87210.1%$2,173,778Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$1,537,5372.8%$2,442,9372.8%$2,180,9162.8%$22,4562.8%$603,600Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$6,256,41311.4%$9,940,58811.4%$8,874,39411.4%$91,37611.4%$2,456,117Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $88,896,713 $141,244,778 $126,095,338 $1,298,352 $34,898,710Fabric Filter8NoneFabric Filter10NoneNoneNoneNoneFlue Gas ConditioningDry FGD w/Fabric FilterDry FGD w/ESP & HigherLNB w/OFA & SNCRSO2 ControlWet FGD w/ESPWet FGD w/ESPESPLNB w/OFANoneESP ESPROFANoneNoneDry FGD w/Fabric FilterParameterLNB w/OFA ROFA LNB w/OFA & SCRESPNoneDry FGD w/ESP & Higher S CoalESPLNB w/OFA & SNCRNoneESP ESPLNB w/OFA & SCRNonePM ControlFlue Gas ConditioningNOx Control45 76293EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls1 of 1Naughton Unit 2LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 80,000------713,459793,4592802 2015 81,600------713,459795,0592803 2016 83,232------713,459796,6912814 2017 84,897------713,459798,3552815 2018 86,595------713,459800,0532826 2019 88,326------713,459801,7852837 2020 90,093------713,459803,5522838 2021 91,895------713,459805,3542849 2022 93,733------713,459807,19128410 2023 95,607------713,459809,06628511 2024 97,520------713,459810,97828612 2025 99,470------713,459812,92928613 2026 101,459------713,459814,91828714 2027 103,489------713,459816,94728815 2028 105,558------713,459819,01728916 2029 107,669------713,459821,12828917 2030 109,823------713,459823,28229018 2031 112,019------713,459825,47829119 2032 114,260------713,459827,71829220 2033 116,545------713,459830,004292Present Worth977,428------7,500,0018,477,429149(% of PW)11.5% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 88.5% 100.0%Naughton Unit 2ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 120,000----1,028,8421,028,8421,007,0442,155,8878142 2015 122,400----1,049,4191,049,4191,007,0442,178,8638233 2016 124,848----1,070,4081,070,4081,007,0442,202,3008314 2017 127,345----1,091,8161,091,8161,007,0442,226,2058405 2018 129,892----1,113,6521,113,6521,007,0442,250,5888506 2019 132,490----1,135,9251,135,9251,007,0442,275,4598597 2020 135,139----1,158,6441,158,6441,007,0442,300,8278698 2021 137,842----1,181,8161,181,8161,007,0442,326,7038789 2022 140,599----1,205,4531,205,4531,007,0442,353,09688810 2023 143,411----1,229,5621,229,5621,007,0442,380,01789811 2024 146,279----1,254,1531,254,1531,007,0442,407,47790912 2025 149,205----1,279,2361,279,2361,007,0442,435,48591913 2026 152,189----1,304,8211,304,8211,007,0442,464,05493014 2027 155,233----1,330,9171,330,9171,007,0442,493,19494115 2028 158,337----1,357,5361,357,5361,007,0442,522,91795216 2029 161,504----1,384,6861,384,6861,007,0442,553,23596417 2030 164,734----1,412,3801,412,3801,007,0442,584,15897618 2031 168,029----1,440,6281,440,6281,007,0442,615,70198719 2032 171,390----1,469,4401,469,4401,007,0442,647,8741,00020 2033 174,817----1,498,8291,498,8291,007,0442,680,6911,012Present Worth1,466,142----12,570,24412,570,24410,586,22224,622,608465(% of PW)6.0% 0.0% 0.0% 0.0% 0.0% 51.1% 51.1% 43.0% 100.0%EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls1 of 5Naughton Unit 2LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 232,500-547,170--86,724633,8941,891,0242,757,4188332 2015 237,150-558,114--88,458646,5721,891,0242,774,7468383 2016 241,893-569,276--90,228659,5041,891,0242,792,4208434 2017 246,731-580,661--92,032672,6941,891,0242,810,4488495 2018 251,665-592,275--93,873686,1471,891,0242,828,8378546 2019 256,699-604,120--95,750699,8701,891,0242,847,5938607 2020 261,833-616,203--97,665713,8681,891,0242,866,7248668 2021 267,069-628,527--99,619728,1451,891,0242,886,2388729 2022 272,411-641,097--101,611742,7081,891,0242,906,14387810 2023 277,859-653,919--103,643757,5621,891,0242,926,44588411 2024 283,416-666,997--105,716772,7141,891,0242,947,15389012 2025 289,085-680,337--107,830788,1681,891,0242,968,27689613 2026 294,866-693,944--109,987803,9311,891,0242,989,82190314 2027 300,764-707,823--112,187820,0101,891,0243,011,79791015 2028 306,779-721,979--114,430836,4101,891,0243,034,21291616 2029 312,914-736,419--116,719853,1381,891,0243,057,07692317 2030 319,173-751,147--119,053870,2011,891,0243,080,39793018 2031 325,556-766,170--121,435887,6051,891,0243,104,18593819 2032 332,067-781,494--123,863905,3571,891,0243,128,44894520 2033 338,709-797,124--126,340923,4641,891,0243,153,196952Present Worth2,840,651-6,685,245--1,059,5817,744,82719,878,76530,464,242460(% of PW)9.3% 0.0% 21.9% 0.0% 0.0% 3.5% 25.4% 65.3% 100.0%Naughton Unit 2LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 400,000-365,145303,000-527,8341,195,9796,940,5828,536,5611,9202 2015 408,000-372,448309,060-538,3901,219,8996,940,5828,568,4811,9273 2016 416,160-379,897315,241-549,1581,244,2976,940,5828,601,0391,9344 2017 424,483-387,495321,546-560,1411,269,1836,940,5828,634,2481,9425 2018 432,973-395,245327,977-571,3441,294,5666,940,5828,668,1211,9496 2019 441,632-403,150334,536-582,7711,320,4586,940,5828,702,6721,9577 2020 450,465-411,213341,227-594,4271,346,8676,940,5828,737,9141,9658 2021 459,474-419,437348,052-606,3151,373,8046,940,5828,773,8601,9739 2022 468,664-427,826355,013-618,4411,401,2806,940,5828,810,5261,98210 2023 478,037-436,382362,113-630,8101,429,3066,940,5828,847,9251,99011 2024 487,598-445,110369,355-643,4261,457,8926,940,5828,886,0721,99912 2025 497,350-454,012376,742-656,2951,487,0506,940,5828,924,9812,00713 2026 507,297-463,093384,277-669,4211,516,7916,940,5828,964,6692,01614 2027 517,443-472,354391,963-682,8091,547,1266,940,5829,005,1512,02515 2028 527,792-481,801399,802-696,4651,578,0696,940,5829,046,4422,03516 2029 538,347-491,437407,798-710,3951,609,6306,940,5829,088,5602,04417 2030 549,114-501,266415,954-724,6031,641,8236,940,5829,131,5192,05418 2031 560,097-511,292424,273-739,0951,674,6596,940,5829,175,3382,06419 2032 571,298-521,517432,759-753,8771,708,1536,940,5829,220,0332,07420 2033 582,724-531,948441,414-768,9541,742,3166,940,5829,265,6222,084Present Worth4,887,141-4,461,2923,702,010-6,448,99614,612,29772,960,58892,460,0271,040(% of PW)5.3% 0.0% 4.8% 4.0% 0.0% 7.0% 15.8% 78.9% 100.0%EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls2 of 5Naughton Unit 2Dry FGD w/ESP & Higher S CoalYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 1,939,34594,9622,425,901-1,139,518886,5564,546,9368,456,55114,942,8329552 2015 1,978,13296,8612,474,419-1,162,309904,2874,637,8758,456,55115,072,5589633 2016 2,017,69498,7982,523,907-1,185,555922,3734,730,6338,456,55115,204,8789724 2017 2,058,048100,7742,574,385-1,209,266940,8204,825,2458,456,55115,339,8449805 2018 2,099,209102,7902,625,873-1,233,451959,6374,921,7508,456,55115,477,5109896 2019 2,141,193104,8452,678,390-1,258,120978,8295,020,1858,456,55115,617,9299987 2020 2,184,017106,9422,731,958-1,283,283998,4065,120,5898,456,55115,761,1571,0078 2021 2,227,697109,0812,786,597-1,308,9481,018,3745,223,0018,456,55115,907,2491,0179 2022 2,272,251111,2632,842,329-1,335,1271,038,7415,327,4618,456,55116,056,2631,02610 2023 2,317,696113,4882,899,176-1,361,8301,059,5165,434,0108,456,55116,208,2571,03611 2024 2,364,050115,7582,957,159-1,389,0661,080,7075,542,6908,456,55116,363,2911,04612 2025 2,411,331118,0733,016,303-1,416,8481,102,3215,653,5448,456,55116,521,4261,05613 2026 2,459,558120,4343,076,629-1,445,1851,124,3675,766,6158,456,55116,682,7241,06614 2027 2,508,749122,8433,138,161-1,474,0881,146,8545,881,9478,456,55116,847,2471,07715 2028 2,558,924125,3003,200,924-1,503,5701,169,7925,999,5868,456,55117,015,0611,08816 2029 2,610,103127,8063,264,943-1,533,6411,193,1876,119,5788,456,55117,186,2311,09917 2030 2,662,305130,3623,330,242-1,564,3141,217,0516,241,9698,456,55117,360,8251,11018 2031 2,715,551132,9693,396,847-1,595,6011,241,3926,366,8098,456,55117,538,9101,12119 2032 2,769,862135,6293,464,783-1,627,5131,266,2206,494,1458,456,55117,720,5571,13320 2033 2,825,259138,3413,534,079-1,660,0631,291,5446,624,0288,456,55117,905,8381,144Present Worth23,694,6291,160,22829,639,298-13,922,46610,831,80955,553,80188,896,713168,145,144537(% of PW)14.1% 0.7% 17.6% 0.0% 8.3% 6.4% 33.0% 52.9% 100.0%Naughton Unit 2Dry 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 2,051,88594,9621,141,778124,072612,0261,431,7343,404,57213,436,30818,892,7661,9342 2015 2,092,92396,8611,164,614126,553624,2671,460,3693,472,66413,436,30819,001,8951,9453 2016 2,134,78198,7981,187,906129,085636,7521,489,5763,542,11713,436,30819,113,2061,9574 2017 2,177,477100,7741,211,664131,666649,4871,519,3683,612,95913,436,30819,226,7441,9685 2018 2,221,026102,7901,235,897134,300662,4771,549,7553,685,21813,436,30819,342,5531,9806 2019 2,265,447104,8451,260,615136,986675,7261,580,7503,758,92313,436,30819,460,6781,9927 2020 2,310,756106,9421,285,827139,725689,2411,612,3653,834,10113,436,30819,581,1652,0058 2021 2,356,971109,0811,311,544142,520703,0261,644,6133,910,78313,436,30819,704,0632,0179 2022 2,404,110111,2631,337,775145,370717,0861,677,5053,988,99913,436,30819,829,4182,03010 2023 2,452,193113,4881,364,530148,278731,4281,711,0554,068,77913,436,30819,957,2802,04311 2024 2,501,237115,7581,391,821151,243746,0561,745,2764,150,15413,436,30820,087,6992,05712 2025 2,551,261118,0731,419,657154,268760,9771,780,1824,233,15813,436,30820,220,7272,07013 2026 2,602,286120,4341,448,051157,353776,1971,815,7854,317,82113,436,30820,356,4152,08414 2027 2,654,332122,8431,477,012160,500791,7211,852,1014,404,17713,436,30820,494,8182,09815 2028 2,707,419125,3001,506,552163,710807,5551,889,1434,492,26113,436,30820,635,9882,11316 2029 2,761,567127,8061,536,683166,985823,7061,926,9264,582,10613,436,30820,779,9812,12717 2030 2,816,799130,3621,567,416170,324840,1811,965,4654,673,74813,436,30820,926,8552,14218 2031 2,873,135132,9691,598,765173,731856,9842,004,7744,767,22313,436,30821,076,6662,15819 2032 2,930,597135,6291,630,740177,205874,1242,044,8694,862,56713,436,30821,229,4732,17320 2033 2,989,209138,3411,663,355180,749891,6062,085,7674,959,81913,436,30821,385,3362,189Present Worth25,069,6311,160,22813,950,0761,515,8937,477,64417,492,72141,596,563141,244,778207,910,9721,064(% of PW)12.1% 0.6% 6.7% 0.7% 3.6% 8.4% 20.0% 67.9% 100.0%EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls3 of 5Naughton Unit 2Wet 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 2,853,781126,616954,332-711,2131,300,8603,093,02011,995,17517,941,9771,7522 2015 2,910,857129,148973,419-725,4371,326,8773,154,88111,995,17518,060,9131,7643 2016 2,969,074131,731992,887-739,9461,353,4153,217,97911,995,17518,182,2271,7754 2017 3,028,455134,3651,012,745-754,7451,380,4833,282,33811,995,17518,305,9681,7885 2018 3,089,024137,0531,033,000-769,8391,408,0933,347,98511,995,17518,432,1841,8006 2019 3,150,805139,7941,053,660-785,2361,436,2553,414,94511,995,17518,560,9241,8127 2020 3,213,821142,5901,074,733-800,9411,464,9803,483,24311,995,17518,692,2391,8258 2021 3,278,097145,4421,096,228-816,9601,494,2793,552,90811,995,17518,826,1811,8389 2022 3,343,659148,3501,118,152-833,2991,524,1653,623,96611,995,17518,962,8011,85210 2023 3,410,533151,3171,140,515-849,9651,554,6483,696,44611,995,17519,102,1531,86511 2024 3,478,743154,3441,163,326-866,9641,585,7413,770,37511,995,17519,244,2931,87912 2025 3,548,318157,4311,186,592-884,3031,617,4563,845,78211,995,17519,389,2751,89313 2026 3,619,284160,5791,210,324-901,9901,649,8053,922,69811,995,17519,537,1571,90814 2027 3,691,670163,7911,234,531-920,0291,682,8014,001,15211,995,17519,687,9971,92315 2028 3,765,503167,0671,259,221-938,4301,716,4574,081,17511,995,17519,841,8531,93816 2029 3,840,814170,4081,284,406-957,1991,750,7864,162,79811,995,17519,998,7871,95317 2030 3,917,630173,8161,310,094-976,3431,785,8024,246,05411,995,17520,158,8591,96818 2031 3,995,982177,2921,336,296-995,8691,821,5184,330,97511,995,17520,322,1331,98419 2032 4,075,902180,8381,363,021-1,015,7871,857,9484,417,59511,995,17520,488,6722,00120 2033 4,157,420184,4551,390,282-1,036,1021,895,1074,505,94711,995,17520,658,5422,017Present Worth34,867,0781,546,97111,659,892-8,689,49115,893,71737,790,071126,095,338198,752,487970(% of PW)17.5% 0.8% 5.9% 0.0% 4.4% 8.0% 19.0% 63.4% 100.0%Naughton Unit 2Flue Gas ConditioningYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 10,000-62,194--19,71081,904123,509215,4149492 2015 10,200-63,438--20,10483,542123,509217,2529573 2016 10,404-64,707--20,50685,213123,509219,1279654 2017 10,612-66,001--20,91686,918123,509221,0399745 2018 10,824-67,321--21,33588,656123,509222,9909826 2019 11,041-68,668--21,76190,429123,509224,9799917 2020 11,262-70,041--22,19792,238123,509227,0091,0008 2021 11,487-71,442--22,64194,082123,509229,0791,0099 2022 11,717-72,871--23,09395,964123,509231,1901,01810 2023 11,951-74,328--23,55597,883123,509233,3441,02811 2024 12,190-75,815--24,02699,841123,509235,5401,03712 2025 12,434-77,331--24,507101,838123,509237,7811,04713 2026 12,682-78,877--24,997103,875123,509240,0661,05714 2027 12,936-80,455--25,497105,952123,509242,3971,06815 2028 13,195-82,064--26,007108,071123,509244,7751,07816 2029 13,459-83,705--26,527110,232123,509247,2011,08917 2030 13,728-85,380--27,058112,437123,509249,6741,10018 2031 14,002-87,087--27,599114,686123,509252,1981,11119 2032 14,282-88,829--28,151116,980123,509254,7711,12220 2033 14,568-90,605--28,714119,319123,509257,3971,134Present Worth122,179-759,881--240,8141,000,6951,298,3522,421,226533(% of PW)5.0% 0.0% 31.4% 0.0% 0.0% 9.9% 41.3% 53.6% 100.0%EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls4 of 5Naughton Unit 2Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 112,540--124,072-545,179669,2513,319,8384,101,6298,8482 2015 114,791--126,553-556,082682,6363,319,8384,117,2658,8823 2016 117,087--129,085-567,204696,2883,319,8384,133,2148,9164 2017 119,429--131,666-578,548710,2143,319,8384,149,4818,9515 2018 121,817--134,300-590,119724,4183,319,8384,166,0748,9876 2019 124,254--136,986-601,921738,9073,319,8384,182,9999,0247 2020 126,739--139,725-613,960753,6853,319,8384,200,2629,0618 2021 129,274--142,520-626,239768,7593,319,8384,217,8709,0999 2022 131,859--145,370-638,764784,1343,319,8384,235,8319,13810 2023 134,496--148,278-651,539799,8163,319,8384,254,1519,17711 2024 137,186--151,243-664,570815,8133,319,8384,272,8379,21812 2025 139,930--154,268-677,861832,1293,319,8384,291,8979,25913 2026 142,728--157,353-691,418848,7723,319,8384,311,3389,30114 2027 145,583--160,500-705,247865,7473,319,8384,331,1689,34315 2028 148,495--163,710-719,352883,0623,319,8384,351,3959,38716 2029 151,465--166,985-733,739900,7233,319,8384,372,0269,43117 2030 154,494--170,324-748,413918,7383,319,8384,393,0709,47718 2031 157,584--173,731-763,382937,1123,319,8384,414,5349,52319 2032 160,735--177,205-778,649955,8553,319,8384,436,4289,57020 2033 163,950--180,749-794,222974,9723,319,8384,458,7609,619Present Worth1,375,002--1,515,893-6,660,9128,176,80634,898,71044,450,5174,795(% of PW)3.1% 0.0% 0.0% 3.4% 0.0% 15.0% 18.4% 78.5% 100.0%EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls5 of 5EY102007001SLC\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 1 of 1First Year Cost for Air Pollution Control Options02,000,0004,000,0006,000,0008,000,00010,000,00012,000,00014,000,00016,000,00018,000,00020,000,000LNB 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\App A_PCorp Naughton 2 BART Economic Analysis_02-08-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options050,000,000100,000,000150,000,000200,000,000250,000,000LNB 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