# Final Report



# BART Analysis for

Jim Bridger 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

Jim Bridger 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 Jim Bridger Unit 2 (hereafter refe rred to as Jim Bridger 2). A Best Available

Retrofit Technology analysis has been conducted for the following criteria pollutants: oxides of

nitrogen oxide (NO

x 

# ), sulfur dioxide (SO 2 

# ), and particulate matter le ss than 10 micrometers in

aerodynamic diameter (PM 10 

# ). The Jim Bridger Station cons ists of four 530-megawatt (MW)

units with a total generating cap acity of 2,120 MW. Because the to tal generating capacity of the

Jim Bridger Station exceeds 750 MW, presumptive BART limits apply to Jim Bridger 2, based on

the United States Environmental Protection Agency ’s (EPA) guidelines. BART emissions limits

must be achieved within 5 years after the Stat e Implementation Plan (SIP) is approved by the

EPA. A compliance date of 2014 wa s 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)

− LNBs with rotating opposed fire air (ROFA)

− LNBs with selective non-catalyt ic reduction (SNCR) system

− LNBs with selective catalytic reduction (SCR) system

• SO 2 

# emission controls:

− Optimize current operation of existing wet sodi um flue gas desulfurization (FGD) system

− Upgrade wet sodium FGD system to achieve an SO 2 

# emission rate of 0.10 pound per

million British thermal unit (pounds [lbs] per MMBtu)

− New dry FGD system

• PM 10 

# emission controls:

− Sulfur trioxide (SO 3 

# ) injection flue gas conditioning system on existing electrostatic

precipitator (ESP)

− Polishing fabric filter

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# BART Engineering Analysis

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

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

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

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

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

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

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

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Available Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

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

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

applicability of options and their impacts)

• Step 3 – Evaluate Control Effectiven ess of Remaining Control Technologies

• Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

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

• Step 5 – Evaluate Visibility Impacts

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

BART

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included in

the BART analyses are in 2006 dollars, and cost s have not been escalated to the assumed 2014

BART implementation date.



# Coal Characteristics

The main source of coal burned at Jim Bri dger 2 will be the Bridger Underground Mine.

Secondary sources are the Bridger Surface Mine , the Bridger Highwall Mine, the Black Butte

Mine, and the Leucite Hills Mine . These coals are ranked as sub- bituminous, but are closer in

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# characteristics to bituminous coal in many of the parameters influencing NO

x 

# formation. These

coals have higher nitrogen content than co als from the Powder River Basin (PRB), which

represent the bulk of sub-bitumi nous coal use in the United Stat es. This BART analysis has

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

compared with those coals used at Jim Bridger 2, and has evaluated the effect of these qualities

on NO

x 

# formation and achievable emission rates.



# Recommendations

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

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

as Scenario 1 throughout this report.



# NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by EPA for tangentially fired boilers burning

sub-bituminous coal is 0.15 lb per MMBtu. Howe ver, as documented in this analysis, the

characteristics of the Jim Bridger 2 coals are more closely aligned with bituminous coals, with a

presumptive BART NO

x 

# limit of 0.28 lb per MMBtu.

CH2M HILL recommends the existing LNBs with OFA (LNB with an OFA) as BART for

Jim Bridger 2, based on the proj ected significant reduction in NO

x 

# emissions, reasonable control

costs, and the advantages of no additional power requirements or non-air quality environmental

impacts. NO

x 

# reductions have been realized at Jim Br idger 2. CH2M HILL recommends that the

unit be permitted at a ra te of 0.26 lb per MMBtu.



# SO 2 

# Emission Control

CH2M HILL recommends upgrading the existin g wet sodium FGD system as BART for

Jim Bridger 2, based on the significant reduction in SO 2 

# emissions, reasonable control costs, and

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

environmental impacts. This upgrade appr oach will meet the BART presumptive SO 2 

# limit of

0.15 lb per MMBtu.



# PM 10



# Emission Control

CH2M HILL recommends finalizing the permitting of the flue gas conditioning (FGC) system to

enhance the performance of the existing ESP as BART for Jim Bridger 2, based on the

significant reduction in PM 10 

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

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



# Control Scenario 1

These BART selections, which include maintaining the existing low NO

x 

# burners with OFA,

upgrading the existing FGD system, and operating the existing electrostatic precipitator with an

SO 3 

# FGC system, are identified as Sc enario 1 throughout this report.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# BART Modeling Analysis

CH2M HILL used the CALPUFF modeling system (Gaussian puff dispersion model) to assess

the visibility impacts of emissions from Jim Br idger 2 at Class I areas. The Class I areas

potentially affected are located more than 50 kilometers (km), but less than 300 km, from the

Jim Bridger Plant.

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

• 

# Bridger WA

• 

# Fitzpatrick WA

• 

# Mt. Zirkel WA

Because Jim Bridger 2 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four

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

effectiveness for combining the individual NO

x 

# , SO 2 

# and PM 10 

# control technologies under

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

• 

# Scenario 1 : Existing LNB with OFA, upgraded we t FGD system, and FGC for enhanced

ESP performance. As indicated previousl y, this scenario represents CH2M HILL’s

preliminary BART recommendation.

• 

# Scenario 2 : Existing LNB with OFA, upgraded wet FGD system, and new polishing fabric

filter.

• 

# Scenario 3 : Existing LNB with OFA and SCR, upgraded wet FGD system, and FGC for

enhanced ESP performance.

• 

# Scenario 4 : Existing LNB with OFA and SCR, upgraded wet FGD system, and new

polishing fabric filter.

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

compared utilizing a least-cost envel ope, as outlined in the draft EPA 1990 New Source Review

Workshop Manual (NSR Manual).



# Least-cost Envelope Analysis

EPA has adopted the least-cost envelope anal ysis methodology as an accepted methodology for

selecting the most reasonable, cost-effective controls. Incremental cost-effectiveness

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

alternatives. The dominant set of control alternat ives is determined by generating what is called

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

emissions reductions for all control altern atives identified in the BART analysis.

To evaluate the impacts of the modeled control scenarios on the three Cl ass 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 provides a comparison of the average incremental costs

between relevant scenarios for th e three Class I areas; th e total annualized cost versus number of

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC ES-5 

# days above 0.5 dV, and the tota l annualized cost versus 98 th 

# percentile delta-deciview ( Δ dV)

reduction.

Results of the least-cost envel ope analysis validate the sele ction of Scenario 1, based on

incremental cost and visibility improvements. Scenario 2 (LNB with OFA, upgraded wet FGD,

and polishing fabric filter) is eliminated, because it is to the left of the curve formed by the

dominant control alternative scen ario, which indicates a scenario with lower improvement and/or

higher costs. Scenario 3 (LNB with OFA and SCR, upgraded wet FGD, and FGC for enhanced

ESP performance) is not selected due to very hi gh incremental costs, based on cost per day of

improvement and cost per dV reduction. While S cenario 4 (LNB with OFA and SCR, upgraded

wet FGD, and polishing fabric filter) provi des some potential visi bility advantage over

Scenario 1, the projected improvement is less than half a dV, and the projected costs are

excessive. Therefore, Scenario 1 re presents BART for Jim Bridger 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 person. Therefore, the modeling analysis results indicate that only

minimal, if any, observable visibility improveme nts at the Class I areas studied would be

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

discernable visibility improvements may result, even though PacifiCorp will be spending many

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

of coal-fired power plants.

# Contents

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

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

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

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

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

3.2.1 BART NO

x 

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

3.2.2 BART SO 2 

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

3.2.3 BART PM 10 

# Analysis.................................................................3-16

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.............................................................................4-7

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

4.3.5 Modeling Process.........................................................................4-8

4.3.6 Receptor Grids .............................................................................4-8

4.4 CALPOST..............................................................................................4-10

4.5 Presentation of Modeling Results ..........................................................4-11

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario.............4-11

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 Results...........................................................................5-8

5.2 Recommendations....................................................................................5-8

5.2.1 NO

x 

# Emission Control .................................................................5-8

5.2.2 SO 2 

# Emission Control ..................................................................5-8

5.2.3 PM 10 

# Emission Control ................................................................5-8

5.3 Just-Noticeable Differences in Atmospheric Haze ..................................5-9

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

\\SNOWBIRD\PROJ\PACIFICORP\348295BART\OCT 2007 REVISIONS\BART_JB2_OCT2007_FINAL.DOC iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC iv 

# Tables

2-1 Unit Operation and Study Assumptions

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 (Incremental to Existing Wet 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 Control Scenario Results for the Bridger Class 1 Wilderness Area

5-2 Control Scenario Results for the Fitzpatrick Class I Wilderness Area

5-3 Control Scenario Results for the Mt. Zirkel Class I Wilderness Area

5-4 Bridger Class I Wilderness Area Incremental Analysis Data

5-5 Fitzpatrick Class I Wilderness Area Incremental Analysis Data

5-6 Mt. Zirkel Class I Wilderness Area Incremental Analysis 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 Various 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 PM Air Pollution Control Options

4-1 Jim Bridger Source-specific Cla ss I Areas to be Addressed

4-2 Surface and Upper Air Station Used in the Jim Bridger BART Analysis

5-1 Least-cost Envelope Bridger Cla ss I Wilderness Area Days Reduction

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

# Percentile Reduction

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

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

# Percentile Reduction

5-5 Least-cost Envelope Mt. Zirkel Cl ass I Wilderness Area Days Reduction

5-6 Least-cost Envelope Mt. Zirk el Class I Wilderness Area 98 th 

# Percentile Reduction

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

°C Degrees Celsius

°F Degrees Fahrenheit

ASOS Automated Surface Observing System

BACT Best Availa ble Control Technology

BART Best Availabl e Retrofit Technology

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

Δ dV Delta Deciview, Change in Deciview

DCS Distributed Control System

dV Deciview

EIA Energy Information Administration

EPA United States Environmental Protection Agency

ESP Electrostatic Precipitator

f (RH) Relative Humidity Factors

FGC Flue Gas Conditioning

FGD Flue Gas Desulfurization

Fuel NO

x 

# Oxidation of Fuel-bound Nitrogen

hp Horsepower

ID Internal Diameter

km Kilometer

kW Kilowatts

kW-Hr Kilowatt-hour

LAER Lowest Achievable Emission Rate

lb Pound(s)

LNB Low-NO

x 

# Burner

LOI Loss on Ignition

MM5 Mesoscale Meteorologi cal Model, Version 5

MMBtu Million British Thermal Units

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC vi 

# MW Megawatt(s)

N 2 

# Nitrogen

NO Nitric Oxide

NO

x 

# Nitrogen Oxide

NP National Park(s)

NSR Manual New Service Review Workshop Manual (EPA, 1990)

NWS National Weather Service

OFA Over-fire Air

PM Particulate Matter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PM 2.5 

# Particulate Matter less than 2.5 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Study Multi-pollutant Cont rol Report dated October 2002

S&L Sargent & Lundy

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction System

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

TRC TRC Companies, Inc.

USGS U.S. 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 othe r Class I protected air quality areas in the

United States (40 CFR Part 51). These guidelines provide guidance for states when determining

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

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

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

The Wyoming Department of Environmental 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 Jim Bridger Unit 2 (hereafter referred to as Jim Bridger 2) by January 12, 2007. The

BART report that was submitted to the WDEQ in January 2007 included a BART analysis, and

a proposal and justification for BART at the source. This revi sed report, submitted in October

2007, incorporates editorial revisions and ne w model runs since the January 2007 version.

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

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

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

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

guidelines also state that the BART emission lim its must be fully implemented within 5 years

of EPA’s approval of the SIP.

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

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

• The cost of the controls

• The remaining useful life of the source

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

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

such technology

This report documents the BART analysis that was performed on Jim Bridger 2 by

CH2M HILL for PacifiCorp. The analysis wa s performed for the po llutants nitrogen oxide

(NO

x 

# ), sulfur dioxide (SO 2 

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

diameter (PM 10 

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

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

discussion of coal sources and characteristics. The BART Engineering An alysis is provided in

Section 3, by pollutant type. Section 4 provi des the methodology and results of the BART

Modeling Analysis, followed by recommendations in Section 5 and references in Section 6.

Appendices provide more detail on the economic analysis and the 2006 Wyoming BART

Protocol.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 1-1

# 2.0 Present Unit Operation

The Jim Bridger Station consists of four units with a total generating capacity of

2,120 megawatts (MW). Jim Bridger 2 is a nominal 530-net-MW unit located approximately

35 miles northeast of Rock Spri ngs, Wyoming. Unit 2 is equippe d with a tangentially fired

pulverized coal boiler. Low-NO

x 

# burner (LNB) TFS 2000 LNBs with over-fire air (OFA) were

installed in 2005. The unit was cons tructed with a Flakt wire fr ame electrostatic precipitator

(ESP). The unit contains a Babcock & Wilcox we t sodium flue gas desulfurization (FGD)

system with three absorber towers installed in 1986. An Emerson Ovation distributed control

system (DCS) was installed in 2005.

Jim Bridger 2 was placed in service in 1975. It s current economic depr eciation life is through

2040; however, this analysis is based on a 20- year life for BART control technologies.

Assuming a BART implementation date of 2014, this will result in an approximate remaining

useful life for Jim Bridger 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 and these contro l devices at Jim Bridge r 2 to operate until 2040.

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

The BART presumptive NO

x 

# limit for tangentially fired boilers burning sub-bituminous coal is

0.15 pound per British thermal unit (lb per MMBtu) and the BART presumptive NO

x 

# limit for

burning bituminous coal is 0.28 lb per MMBt u. The main sources of coal burned at

Jim Bridger 2 are the Bridger Mine, and seconda rily, the Black Butte Mine and Leucite Hills

Mine. These coals are ranked as sub-bituminous, but are closer in charac teristics to bituminous

coal in many of the parameters influencing NO

x 

# formation. These coals have higher nitrogen

content than coals from the Powder Rive r Basin (PRB), which represent the bulk of

sub-bituminous coal used in the United States. This BART analysis has considered the higher

nitrogen content and different combustion characte ristics of PRB coals, as compared with those

coals used at Jim Bridger 2, and has eval uated the effect of these qualities on NO

x 

# formation

and achievable emission rates. Coal sources a nd characteristics are summarized in Table 2-2.

The primary source of coal will be the Bridger Underground Mine, and data on coal from this

source were used in the modeli ng analysis. For the coal analysis that is presented in

Section 3.2.1, the data from all the coal sources were used.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 2-2



# TABLE 2-1



# Unit Operation and Study Assumptions

Jim Bridger 2

General Plant Data

Site Elevation (feet above mean sea level) 6669

Stack Height (feet) 500

Stack Exit Internal Diameter (f eet) /Exit Area (square feet) 24 /452.4

Stack Exit Temperature °F (degrees Fahrenheit) 140

Stack Exit Velocity (feet per second) 84.0

Stack Flow (actual cubic feet per minute) 2,281,182

Latitude (degree: minute : second) 41:44:16.42 north

Longitude (degree: minute : second) 108:47:10.59 west

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 530

Net Unit Heat Rate (British thermal unit [Btu]/kilowatt-hour

[kW-Hr])(100% load) 10,400 (as measured by fuel

throughput)

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

hour)(100% load) 6,000 (as measured by continuous

emission monitoring)

Type of Boiler Tangentially fired

Boiler Fuel Coal

Coal Sources Bridger Mine, Black Butte Mine,

Leucite Hills Mine

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

# 9,660

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

# 0.58

Coal Ash Content (wt. %) a 

# 10.3

Coal Moisture Content (wt. %) a 

# 19.3

Coal Nitrogen Content (wt. %) a 

# 0.98

Current Nitrogen Oxide (NO

x 

# ) Controls Low NO

x

# burners

NO

x 

# Emission Rate (lb/MMBtu) 0.24

Current Sulfur Oxide (SO 2 

# ) Controls Sodium based wet scrubber

SO 2 

# Emission Rate (lb/MMBtu) 0.267

Current PM 10 

# Controls Electrostatic Precipitator

PM 10 

# Emission Rate (lb/MMBtu) b 

# 0.074

NOTES:

a 

# Coal characteristics based on Bridger Underground Mine (primary coal source)

b 

# Based on maximum historic emission rate from 199 9 – 2001, before installati on of the sulfur trioxide

(SO 3 

# ) injection system.BART ANALYSIS FOR JIM BRIDGER UNIT 2TABLE 2-2Coal Sources and CharacteristicsJim Bridger 2Ultimate Analysis (% dry basis)MinesMoist.(%)Ash (%)VolatileMatter(%)FixedCarbon(%)Btu/lbSulfur(%)Moistureand AshFree(Btu/lb)HydrogenCarbonSulfurNitrogenOxygenAshBridger MineUnderground19.310.332.238.396600.58137124.6669.20.721.2211.812.4MaximumNot enough data yet to run statistical analysis for variabilityMinimumNot enough data yet to run statistical analysis for variabilityBridger MineSurface19.110.632.338.093900.57133404.3837.40.711.2613.213.0Maximum20.512.535.541.998000.72135004.694.00.901.4314.815.8Minimum17.59.031.036.090000.49131004.0064.30.601.1411.711.2Bridger MineHighwall18.09.533.039.597000.5813500No samples of separate highwall coalMaximumNot enough data yet to run statistical analysis for variabilityMinimumNot enough data yet to run statistical analysis for variabilityBlack ButteMine20.09.233.335.694500.45133304.4368.70.561.4713.411.5Max21.110.835.441.9102750.62135004.6670.50.781.6914.813.6Min18.07.629.936.891800.33131404.2166.10.411.2511.69.7Leucite HillsMine (through2009)19.411.530.738.390800.64131404.2066.00.811.4813.214.4Maximum23.015.033.043.0102500.90138004.7070.01.201.6417.119.0Minimum17.08.028.333.680000.40123003.7061.00.501.3210.510.0JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC2-3

# 3.0 BART Engineering Analysis

This section presents the requi red BART engineering analysis.



# 3.1 Applicability

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

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

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

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

EPA approval of the SIP.



# 3.2 BART Process

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

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

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

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

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

• The energy and non-air quality enviro nmental impacts of compliance

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

BART.

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Availabl e Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

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

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

applicability of options and their impacts)

• Step 3 – Evaluate Control Effectiven ess of Remaining Control Technologies

• Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

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

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# • Step 5 – Evaluate Visibility Impacts

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

of BART

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

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

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

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

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

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included

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

2014 BART implementation date.



# 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 operating conditions, equipment desi gn, and coal characteristics.

Formation of NO

x



# During coal combustion, NO

x 

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

x 

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

x 

# ). During combustion, part of the

fuel NO

x 

# is released from the coal with the volatile ma tter, and part of it is retained in the solid

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

and nitrogen dioxide) and partially reduced to molecular nitrogen (N 2 

# ). A smaller part of NO

x 

# formation is due to high temper ature fixation of atmospheric n itrogen in the combustion air

(thermal NO

x 

# ). A very small amount of NO

x 

# is called “prompt” NO

x 

# . Prompt NO

x 

# results from

an interaction of hydrocarbon radicals, nitrogen, and oxygen.

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

mixing of fuel and air, which pr ovides 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 coals accordi ng to their degree of metamorphism in the

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

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

x 

# emissions than

higher rank bituminous coals, due to their highe r reactivity and lower nitrogen content. The

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

indices of the reactivity of a coal. Lower-rank coals releas e more organically bound nitrogen

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

sub-bituminous coals create a longer time for the kinetics to promote more stable molecular

nitrogen and, hence, result in lower NO

x 

# emissions.

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

low NO

x 

# production characteristics described ab ove. Based on data from the Energy

Information Administration (EIA), PRB coals cu rrently represent 88 percent of total United

States sub-bituminous production and 73 percent of western coal production. Most references

to western coal and sub-bituminous coal infe r PRB origin and characteristics. Emissions

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# standards differentiating between bituminous a nd sub-bituminous coals are presumed to use

PRB coal as the basis for the sub-bituminous sta ndards, due to their dominant market presence

and unique characteristics.

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

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

including most of the low NO

x 

# forming characteristics. Coals from the Bridger, Black Butte,

and Leucite Hills Mines fall into this category.

As defined by the American Society for Tes ting and Materials, the only distinguishing

characteristic that classifies the coals used at Jim Bridger 2 as sub-bituminous rather than

bituminous – that is, they are “agglomerati ng” as compared with “non-agglomerating.”

Agglomerating as applied to coal is “the property of softening wh en it is heated to above about

400 degrees Celsius (°C) in a non-oxidizing atmos phere, and then appearing as a coherent mass

after cooling to room temperatur e.” Because the agglomerating prope rty of coals is the result of

particles transforming into a plastic or semi-liq uid state when heated, it reflects a change in

surface area of the particle. Thus, with the appl ication of heat, agglomerating coals would tend

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

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

more particle surface area, resulting in more favorable combustion conditions. This nonagglomerating property assists in making sub-b ituminous coals more amenable to controlling

NO

x 

# by allowing less air to be introduced during the initial ignition portion of the combustion

process. The coals from the Bridger, Black Butte and Leucite Hills Mines just barely fall into

the category of non-agglomerating coals. While each of these coals is considered nonagglomerating, they either do not exhibit those properties of non- agglomerating coals or exhibit

them to only a minor degree. The conditions du ring combustion of t ypical non-agglomerating

coals that make it easier to control NO

x 

# emissions do not exist during combustion of the

Bridger blends of coals.

FIGURE 3-1



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

Jim Bridger 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# Table 3-1 shows key characteristics of a typical PRB coal, compared with coals from the

Bridger, Black Butte, and Leucite Hills Mines, as well as coal from Twentymile, which is a

representative western bituminous coal.

TABLE 3-1



# Coal Characteristics Comparison

Jim Bridger 2

Parameter Typical

PRB Bridger

Mine Black

Butte Leucite

Hills Twentymile

Nitrogen (% dry) 1. 10 1.26 1.47 1.48 1.85

Oxygen (% dry) 16. 2 13.2 13.4 13.2 7.19

Coal rank Sub C Sub B Sub B Sub B Bituminous highvolatility B



# As shown in Table 3-1, although Bridger, Black Bu tte, and Leucite Hills co als are classified as

sub-bituminous, they all exhibi t higher nitrogen content and lower oxygen content than the

PRB coal. The higher nitrogen content is an indica tion that more nitrogen is available to the

combustion process and higher NO

x 

# emissions are likely. Oxygen c ontent can be correlated to

the reactivity of the coal, with more reactive coals generally containing higher levels of oxygen.

More reactive coals tend to produce lower NO

x 

# emissions, and are more conducive to reduction

of NO

x 

# emissions through the use of combustion c ontrol measures, such as LNBs and OFA.

These characteristics indicate that higher NO

x 

# formation is likely with coal from the Bridger,

Black Butte, and Leucite Hills Mines, rather than with PRB coal. The Bridger, Black Butte, and

Leucite Hills coals all contain qua lity characteristics that fall between a typical PRB coal and

Twentymile. Twentymile is a clearly b ituminous coal that produces higher NO

x 

# , as has been

demonstrated at power plan ts that burn this fuel.

Figures 3-2 and 3-3 show the relationship of nitrogen and oxygen content to the BART

presumptive NO

x 

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

BART limit associated with a typical bitumi nous and sub-bituminous coal, and demonstrates

how the Jim Bridger 2 coal falls between these two general coal classifications.

The Bridger blend data point represents a combin ation of coals from the Bridger, Black Butte,

and Leucite Hills Mines that has been used at Jim Bridger 2, and indicates the average NO

x 

# emission rate achieved during the years 2003 through 2005. The Jim Bridger 2 data point

represents the NO

x 

# emission rate achieved afte r installation of Alstom’s current state of the art

TFS2000 LNB and OFA System. The long-term sust ainable emission rate for this system is

expected to be 0.24 lb per MMBtu.

Figures 3-2 and 3-3 both demonstrate that for the Jim Bridger 2 units with the

TFS2000 low-NO

x 

# emission system installed and burning a combination of the Bridger, Black

Butte, and Leucite Hill coals, the likely NO

x 

# emission rate (0.28) will be closer to the

bituminous end of the BART presumptive NO

x 

# limit range, rather than the BART presumptive

NO

x 

# limit of 0.15 lb per MMBtu for sub-bituminous co al. All these factors are consistent with

the observed sustainable rate of 0.24 lb per MMBtu.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# FIGURE 3-2



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

x 

# Limits

Jim Bridger 2

PRB Subbituminous Bridger Blend

Jim Bridger 2 Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

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



# Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu



# FIGURE 3-3



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

x 

# Limits

Jim Bridger 2

PRB Subbituminous Twentymile Bituminous Bridger Blend

Jim Bridger 2

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

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



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



# JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR 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 qua lity can sometimes be accommodated through

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

assumptions of “average” quality for performance projections can be problematic. This is

particularly troublesome when dea ling with performance issues that are very sensitive to both

coal quality and combustion conditions, such as NO

x 

# formation. There is significant variability

in the quality of coals burned at Jim Bridger 2. In addition to burning coal from Black Butte

and Leucite Hills Mines, Jim Bridger 2 burns co al supplied from the Bridger Mine consisting of

three sources: underground, surf ace, and highwall operations. Each of these coal sources has

different quality characteristics, as well as inherent vari ability in the composition of coal within

the mine.

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

x 

# formation have been

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

achieving and maintaining consistent low NO

x 

# emissions with pulverized coal on a shorter

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

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

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

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

requirement such as NO

x 

# emission limits is subsequently changed, conflicts with and between

other performance i ssues can result.

Jim Bridger 2 is located at an altitude of 6,669 feet above mean sea level. At this elevation,

atmospheric pressure is lower (11.5 pounds per square inch) as comp ared with sea level

pressure of 14.7 pounds per square inch. This lower pressure means that less oxygen is

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

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

air flows and distri bution to reduce NO

x 

# emissions, using low NO

x 

# burners and OFA, original

boiler design restrictions again limit the modifi cations that can be ma de and still achieve

satisfactory combustion performance.

Another significant factor in controlling NO

x 

# emissions is the fineness of the coal entering the

burners. Fineness is influenced by the grindability index (Hardgr ove) of the coal. Finer coal

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

to air. Nitrogen oxide reduction with high-volat ile coals is improved w ith greater fineness and

with proper air staging. The lower rank sub-b ituminous coals such as PRB coals are quite

friable and easy to grind. Coals with lower Har dgrove Grindability Index values, such as those

used at Jim Bridger 2, are more difficult to grind and can contribute to higher NO

x 

# levels. In

addition, coal fineness can dete riorate over time periods betw een pulverizer maintenance and

service, as pulverizer gr inding surfaces undergo wear.

In summary, when all the factors of agglom eration versus non-agglomeration, nitrogen and

oxygen content of the coals, and the grindability inde x are taken into acc ount, this analysis

demonstrates that for the coal used at Jim Br idger 2, the more applicable presumptive BART

limit for NO

x 

# emissions is 0.28 lb per MMBtu. The BART analysis for NO

x 

# emissions from

Jim Bridger 2 is further described below.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# 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 Jim Bridger 2, incl uding those control techno logies 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 at Jim Bridger 2 are currently controlled through the use of good combustion

practices and OFA.

The following potential NO

x 

# control technology options were considered:

• New/modified LNB with advanced OFA

• Mobotec rotating opposed fire air (ROFA)

• LNB with OFA and conventiona l selective non-cata lytic reduction (SNCR) system

• LNB with OFA and selective catal ytic reduction (SCR) system

Step 2: Eliminate Technically Infeasible Options

For Jim Bridger 2, a tangentially fired confi guration burning sub-bituminous coal, technical

feasibility will primarily be de termined by physical constraints, boiler configuration, and the

ability to achieve th e regulatory presumptive limit (use d as a guide) of 0.28 lb of NO

x 

# per

MMBtu. Jim Bridger 2 has a current NO

x 

# emission rate of 0.24 lb per MMBtu.

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

the Multi-pollutant Control Report dated October 2002 (Sargent & Lundy [S&L], 2002,

hereafter referred to as S&L Study). Updated cost estimates for SCR and SNCR were used.

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

and OFA. Also, CH2M HILL solicited a propos al from Mobotec for its ROFA technology.

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

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

x 

# to

nitrogen and water. NO

x 

# reductions of up to 40 to 60 per cent have been achieved, although

15 to 30 percent is more realistic for most a pplications. SNCR is typically applied on smaller

units.

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

with projected NO

x 

# emission rates. All of the evaluated t echnologies are projected to meet the

applicable presumptive BART limit of 0.28 lb per MMBtu.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# TABLE 3-2



# NO

x 

# Control Technology Projected Emission Rates

Jim Bridger 2

Technology Projected Emission Rate (lb per MMBtu)

Presumptive BART Limit 0.28

LNB with OFA 0.24

ROFA 0.22

LNB with OFA and SNCR 0.20

LNB with OFA and SCR 0.07



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

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

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

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

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

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

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

after more detailed analysis has been complete d. The following subsections describe the control

technologies and the control effectivene ss evaluated in this BART analysis.

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 temperatur e zone to burn out the char.

Both LNBs and OFA are considered to be a capital cost, combustion technology retrofit. For

LNB retrofits to units configured with tangentia l-firing such as Jim Bridger 2, it is generally

necessary to increase the burner spacing; this prevents interacti on of the flames from adjacent

burners and reduces burner zone heat flux. These modifications us ually require boiler

waterwall tube replacement. However, Jim Bri dger 2 has already been modified with the

installation of a TFS-20 00 LNB with OFA system.

Information provided to CH2M HILL by Pacifi Corp, based on the S&L Study and data from

boiler vendors, indicates th at the existing TFS-2000 LNB with and OFA system at

Jim Bridger 2 could be more finely tuned to result in an expected NO

x 

# emission rate of 0.24 lb

per MMBtu. PacifiCorp has indicated that this rate corresponds to a vendor guarantee, not a

vendor prediction, and they believ e that this emission rate can be sustained as an average

between overhauls. This emissi on rate represents a significa nt reduction from the current NO

x 

# emission rate, and is below the more applicable presumptive NO

x 

# emission rate of 0.28 lb per

MMBtu.

ROFA. Mobotec markets ROFA as an improved sec ond generation OFA syst em. Mobotec states

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

Rotation is reported to prevent laminar flow, so that the entire volume of the furnace can be

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# used more effectively for the combustion proces s. In addition, the swir ling action reduces the

maximum temperature of the flames and increases heat absorption. The combustion air is also

mixed more effectively.” A typical ROFA instal lation would have a booste r fan(s) to supply the

high velocity air to the ROFA boxes, a nd Mobotec would propose two 4,000- to 4,300-

horsepower (hp) fans for Jim Bridger 2.

Mobotec proposes to achieve a NO

x 

# emission rate of 0.18 lb per MMBtu using ROFA

technology. An operating margin of 0.04 lb per MMBtu was added to the expected rate due to

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

proposal, which is primarily based on ROFA equipment, the operation of existing LNB and

OFA ports would be analyzed. While a typical in stallation does not require modification to the

existing LNB system and the existing OFA ports are not used, results of computational fluid

dynamics modeling would determine the quant ity and location of new ROFA ports. The

Mobotec proposal includes bent tube a ssemblies for OFA port installation.

Mobotec would not provide installation services b ecause the Owner could more cost effectively

contract for these services. Ho wever, it would provide one on site construction supervisor

during installation and startup.

SNCR. Selective non-catalytic redu ction is generally utilized to achieve modest NO

x 

# reductions

on smaller units. With SNCR, an amine-based re agent such as ammonia, or more commonly

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

reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 60 percent have been achieved,

although 20 to 40 percent is more re alistic for most applications.

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

x 

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

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

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

downstream. The ammonia may render fly ash unsa leable, react with su lfur to foul heat

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

significant impact on economics, with higher levels of NO

x 

# reduction generally resulting in

lower reagent utilization and higher operating cost.

Reductions from higher baseline concentrations (inlet NO

x 

# ) are lower in cost per ton, but result

in higher operating costs, due to greater reagent consumption. Unit 2 has already had

combustion modifications including LNBs a nd advanced OFA, capable of achieving a

projected NO

x 

# emission rate of 0.24 lb per MMBtu

. At a further reduction of 15 percent in NO

x 

# emission rates for SNCR would result in a projected emission rate of 0.20 lb per MMBtu.

SCR. Selective catalytic reduction works on the sa me chemical principle as SNCR, but SCR

uses a catalyst to promote the chemical reaction. Ammonia is injected into the flue gas stream,

where it reduces NO

x 

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

in SCR, the reaction takes place on the surface of a vanadium/titanium-based catalyst at a

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

than SNCR and results in lower NO

x 

# emissions. The most common type of SCR is the highdust configuration, where the ca talyst is located downstream from the boiler economizer, and

upstream of the air heater and any particulate co ntrol equipment. In this location, the SCR is

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# exposed to the full concentration of fly ash in th e flue gas that is leav ing the boiler. The highdust configuration is assumed for Jim Bridger 2.

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

With in-duct SCR, the catalyst is located in th e existing gas duct, which may be expanded in

the area of the catalyst to reduce flue gas flow velocity and increase flue gas residence time.

Due to the higher removal rate, a full-scale S CR was used as the basis for analysis at

Jim Bridger 2.

Sargent and Lundy prepared the design conditions and cost estimates for SCR at Jim Bridger 2.

Unit 2 has already had combustion modifications including LNBs and advanced OFA, capable

of achieving a projected NO

x 

# emission rate of 0.24 lb per MMBtu

. The S&L design basis for

LNB with OFA and SCR results in a projected NO

x 

# emission rate of 0.07 lb per MMBtu.

Additional catalyst surface was included in the SCR design to accommodate the characteristics

of the coal used at Jim Bridger 2.

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

of NO

x 

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

of typical NO

x 

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

review, it was noted that NO

x 

# emissions can vary significan tly around an average emissions

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

operation including excess air, boiler slaggi ng, burner equipment condition, and coal mill

fineness.

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

follows:

1. Establish expected NO

x 

# emissions value from vendor.

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

3. Review and evaluate unit physical and operati onal characteristics a nd restrictions. The

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

variant the NO

x 

# emissions.

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

x 

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

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

Step 4: Evaluate Impacts and Document the Results

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

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

considered during the evaluation.

Energy Impacts. Installation of LNBs and modification to the existing OFA systems are not

expected to significantly affect th e boiler efficiency or forced dr aft fan power usage. Therefore,

these technologies will not have energy impacts.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# The Mobotec ROFA system would require inst allation and operation of two 4,000- to 4,300-hp

ROFA fans (6,410 kilowatts [kW] total). Th e SNCR system would re quire approximately

530 kW of additional power.

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

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

additional power requirements for SCR instal lation at Jim Bridger 2 are estimated at

approximately 3,250 kW, based on the S&L Study.

Environmental Impacts. Mobotec has predicted that car bon monoxide (CO) emissions, and

unburned carbon in the ash, commonly referred to as LOI (loss on ignition) , would be the same

or lower than prior levels for the ROFA system.

The installation of SNCR and SCR could affect the saleability a nd disposal of fly ash due to

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

visibility improvements. Other environmenta l 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. Costs and schedules for the LNBs and OFA, SNCR, and SCR were

furnished to CH2M HILL by PacifiCorp, develope d using S&L’s internal proprietary database,

and supplemented (as needed) by vendor-obtained pr ice quotes. The relative accuracy of these

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

ROFA system was obtained from Mobotec.

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

NO

x 

# removed is summarized in Table 3-3, and th e first-year control co sts are presented in

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

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-12 

# TABLE 3-3



# NO

x 

# Control Cost Comparison

Jim Bridger 2

Factor Low-NOx

Burners

(LNBs) with

Over-fire Air

(OFA)

(Existing) Mobotec

Rotating

Opposed Fire

Air (ROFA) Selective

NonCatalytic

Reduction

(SNCR) Selective

Catalytic

Reduction

(SCR)

Total Installed Capital Costs $0 $20.5 million 13.4 million $120.9 million

Total First Year Fixed and Variable

Operation and Maintenance Costs $0 $2.6 million $1.0 million $3.2 million

Total First Year Annualized Cost $0 $4. 6 million $2.3 million $14.7 million

Power Consumption (megawatts) 0 6.4 0.5 3.3

Annual Power Usage (1,000 million kilowatthours per year) 0 50.6 4.2 25.6

NO

x 

# Design Control Efficiency 0.0% 8.3% 16.7% 70.8%

NO

x 

# Removed per Year (Tons) 0 473 946 4,021

First Year Average Control Cost

($/Ton of NO

x

# Removed) $0/ton $9,695/ton $2, 389/ton $3,654/ton

Incremental Control Cost

($/Ton of NO

x

# Removed) $0/ton $9,695/ton $2, 389/ton $4,044/ton



# Preliminary BART Selection. CH2M HILL recommends selection of the existing LNBs with

OFA as BART for Jim Bridger 2, based on the projected significant reduction in NO

x 

# emissions, reasonable control costs, and the adva ntages of no additional power requirements or

non-air quality environmental impacts. Low-NO

x 

# burner with OFA does not meet the EPA

presumptive limit of 0.15 lb per MMBtu for s ub-bituminous coal; however, it meets an

emission rate that falls between the presumptive limit of 0.28 lb per MMBtu for bituminous

coal and the limit of 0.15 lb per MMBtu for sub- bituminous coal. As discussed in the section

on coal quality, the recommended technology an d the achieved emission rate are deemed

appropriate as BART for NO

x 

# emissions from the coals co mbusted at Jim Bridger 2.

Step 5: Evaluate Visibility Impacts

See Section 4, BART Modeling Analysis.BART ANALYSIS FOR JIM BRIDGER UNIT 2FIGURE 3-4First Year Control Cost for NOXAir Pollution Control OptionsJim Bridger 202,0004,0006,0008,00010,00012,000Exist. LNB w/OFAROFASNCRSCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# 3.2.2 BART SO 2 

# Analysis

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

coal sulfur content. The BART analysis for SO 2 

# emissions on Jim Bridger 2 is described below.

Step 1: Identify All Availabl e Retrofit Control Technologies

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

applicable emission control technologies for SO 2 

# at Jim Bridger 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:

• Optimize current operation of ex isting wet sodium FGD system

• Upgrade wet sodium FGD system to meet SO 2 

# emission rate of 0.10 lb per MMBtu

• New dry FGD system

Step 2: Eliminate Technically Infeasible Options

Technical feasibility will primarily be base d on the regulatory presumptive limit (used as a

guideline) of 95 percent reduction in SO 2 

# emissions, or 0.15 lb per MMBtu. Based on the coal

that Jim Bridger 2 currently burns, the unit w ould be required to achieve an 87.5 percent SO 2 

# removal efficiency to meet the pres umptive limit of 0.15 lb per MMBtu.

Table 3-4 summarizes the control technology options evaluated in this BART analysis, along

with projected SO 2 

# emission rates. Only one technology option can meet the applicable

presumptive BART limit of 0.15 lb per MMBtu.

TABLE 3-4



# SO 2 

# Control Technology Emission Rates

Jim Bridger 2

Technology Projected Emission Rate

(lb per MMBtu)

Presumptive BART Limit 0.15

Upgrade Existing Wet Sodium System 0.10

Optimize Existing Wet Sodium System 0.20

New Dry FGD System 0.21



# Wet Sodium FGD System. Wet sodium FGD systems operate by treating the flue gas in large

scrubber vessels with a soda ash solution. The sc rubber mixes the flue ga s and alkaline reagent

using a series of spray nozzles to distribute th e reagent across the scr ubber vessel. The sodium

in the reagent reacts with the SO 2 

# in the flue gas to form sodium sulfite and sodium bisulfite,

which are removed from the scrubber and disposed.

The wet sodium FGD system at Jim Bridger 2 currently achie ves approximately 78 percent SO 2



# removal to achieve an SO 2 

# outlet emission rate of 0.27 lb per MMBtu. Optimizing the existing

wet FGD system is projected to achieve an SO 2 

# outlet emission rate of 0.20 lb per

MMBtu (83.3 percent SO 2 

# removal). Optimization would be accomplished by partially closing

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# the bypass damper to reduce the routine bypass flue ga s flow used to reheat the treated flue gas

from the scrubber, relocating the opacity monitor, and modi fying the system to minimize

scaling problems.

Upgrading the wet FGD system is projected to achieve an SO 2 

# outlet emission rate of 0.10 lb

per MMBtu (91.7 percent SO 2 

# removal). Upgrading the syst em would involve closing the

bypass damper to eliminate the routine bypass flue ga s flow used to reheat the treated flue gas

from the scrubber, relocating th e opacity monitor, adding new fans, adding a stack liner and

drains for wet operation, and using a refined soda as h reagent. It is consid ered to be technically

infeasible for the present wet FGD system to achieve a 95 percent SO 2 

# removal rate (0.06 lb per

MMBtu) on a continuous basis because this high leve l of removal must be incorporated into the

original design of the scrubber.

Optimizing the existing wet sodium scrubbing FGD system is projected to achieve an outlet

emission rate of 0.20 lb per MMBtu, which would not meet the presumptive limit of 0.15 lb of

SO 2 

# per MMBtu. Therefore, this opti on is eliminated as technically infeasible for this analysis.

An upgraded wet sodium scrubbing FGD system is projected to achieve an outlet emission rate

of 0.10 lb per MMBtu (91.7 percent SO 2 

# removal), which would meet the presumptive limit of

0.15 lb of SO 2 

# per MMBtu for Jim Bridger 2.

New Dry FGD System. The lime spray dryer typically injects lime slurry in the top of the

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

causes the lime slurry to separate into very 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 dry calcium sulfate

particles. At Jim Bridger 2, this dry particulate matter (PM) would be captured downstream in

the existing ESP, along with the fly ash. A lime spray dryer system typically produces a dry

waste product suitable for landfill disposal.

The dry FGD system with the existing E SP is projected to achieve 82.5 percent SO 2 

# removal at

Jim Bridger 2. This would result in a controlled SO 2 

# emission rate of 0.21 lb per MMBtu, based

on an uncontrolled SO 2 

# emission rate of 1.20 lb per MMBtu. Therefore, this option cannot meet

the presumptive limit of 0.15 lb SO 2 

# per MMBtu, and is eliminated from further analysis as

technically infeasible.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

When evaluating the control effectiveness of SO 2 

# reduction technologies, each option can be

compared against benchmarks of performance. One such benchmark is the presumptive BART

emission limit because Jim Bridger 2 is required to meet this limit. As indicated previously, the

presumptive limit for SO 2 

# on a BART-eligible coal burning unit is 95 percent removal, or

0.15 lb per MMBtu.

The projected emission rate for an upgraded we t sodium FGD system fo r Jim Bridger 2 would

be 0.10 lb per MMBtu. This option would meet the presumptive SO 2 

# limit of 0.15 lb per

MMBtu.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# Step 4: Evaluate Impacts and Document the Results

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

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

considered during the evaluation.

Energy Impacts. Upgrading the existing wet sodium FGD system would require an additional

530 kW of power.

Environmental Impacts. There will be incremental additions to scrubber waste disposal and

makeup water requirements, and a reduction of the stack gas temperature from 140 to 120°F,

due to elimination of rehea ting by the bypassed flue gas.

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

# removed for the upgraded wet

sodium FGD system is provided in Table 3-5. The complete econom ic analysis is contained in

Appendix A.

TABLE 3-5



# SO 2 

# Control Cost Comparison (Incremental to Existing Wet FGD System)

Jim Bridger 2

Factor Upgraded Wet Flue Gas Desulfurization

Total Installed Capital Costs $13.0 million

Total First Year Fixed & Variable Operation and

Maintenance Costs $1.3 million

Total First Year Annualized Cost $2.5 million

Additional Power Consumption (megawatt) 0.5

Additional Annual Power Usage (1000 megawatt-hour

per year) 4.2

Incremental SO 2 

# Design Control Efficiency 62.5% (91.7% based on Uncontrolled SO 2 

# )

Incremental Tons SO 2 

# Removed per Year 3,950

First Year Average Control Cost (dollars per ton

[$/Ton] of SO 2 

# Removed) 632

Incremental Control Cost

($/Ton of SO 2 

# Removed) 632



# Preliminary BART Selection. CH2M HILL recommends upgrading the existing wet sodium FGD

system as BART for Jim Bridger 2, based on significant reduction in SO 2 

# emissions (meeting

presumptive limit of 0.15 lb per MMBtu), reasonab le control costs, a nd the advantages of

minimal additional power requirements and environmental impacts.

Step 5: Evaluate Visibility Impacts

See Section 4, BART Modeling Analysis.



# 3.2.3 BART PM 10



# Analysis

Jim Bridger 2 is currently equipped with an ESP. Electrostatic precipitators remove PM from

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

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# attracting these charged particle s to grounded collection plates. A layer of collected PM forms

on the collecting plates and is removed by period ically rapping the plates. The collected ash

particles drop into hoppers belo w the precipitator and are remove d periodically by the fly ashhandling system. Historically, the ESP at Jim Bridger 2 has controlled PM 10 

# emissions to levels

below 0.074 lb per MMBtu.

The BART analysis for PM 10 

# emissions at Jim Bridger 2 is described below. For the modeling

analysis in Section 4, PM 10 

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

# includes particulate

matter less than 2.5 micrometers in aerodynamic diameter (PM 2.5 

# ) as a subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

The following two retrofit control technologies have been identified for additional PM control:

• 

# Flue gas conditioning

• 

# Polishing fabric filter (baghouse) downstream of existing ESP

Another available control technology is replacing the existing ESP with a new fabric filter.

However, because the environmental benefits th at would be achieved by a replacement fabric

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

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

Step 2: Eliminate Technically Infeasible Options

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

sub-bituminous coal, the ash is not collected effectively in an ESP. This is because the high

resistivity makes the particles less willing to accept an electrical charge. Adding flue gas

conditioning (FGC), which is typically accomp lished by injection of sulfur trioxide (SO 3 

# ), will

lower the resistivity of the part icles so that they will accept mo re charge and allow the ESP to

collect the ash more effectively. Flue gas conditioning systems 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 Jim Bridger 2. One such technology is licensed by the Electric Power Research Institute, and

referred to as a COHPAC (Compact Hybrid Pa rticulate Collector). The COHPAC collects the

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

in service for the COHPAC fabric filter to operate effectively.

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

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

jet fabric filter (3.5 to 4:1).

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

The existing ESP at Jim Bridge r 2 is achieving a controlled PM emission rate of 0.074 lb per

MMBtu. Utilizing FGC upstream of the existing ESP is projecte d to reduce PM emissions to

approximately 0.030 lb per MMBtu. Adding a COHP AC fabric filter downstream of the

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

The PM 10 

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

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-17

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# TABLE 3-6



# PM 10



# Control Technology Emission Rates

Jim Bridger 2

Control Technology Short-term Expected PM 10 

# Emission Rate (lb per MMBtu)

Flue Gas Conditioning 0.030

Polishing Fabric Filter 0.015



# Step 4: Evaluate Impacts and Document the Results

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

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

considered during the evaluation.

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

COHPAC fabric filter and asso ciated ductwork. Therefore, a C OHPAC retrofit will require an

internal diameter (ID) fan upgrade and upgrad e of the auxiliary power supply system.

A COHPAC fabric filter at Jim Bridger 2 would require a pproximately 3.4 MW of power,

equating to an annual power usage of appr oximately 26.5 million kilowatt-hour (kW-Hr).

There is only a small power requirement of approximately 50 kW associated with FGC.

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

COHPAC polishing fabric filter or FGC system.

Economic Impacts. A summary of the costs and PM removed for COHPAC and FGC is

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

Figure 3-5. The complete economic anal ysis is contained in Appendix A.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-18

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 3-19 

# TABLE 3-7



# PM 10



# Control Cost Comparison

Jim Bridger 2

Factor Flue Gas

Conditioning Polishing Fabric Filter

Total Installed Capital Costs $0 $48.4 million

Total First Year Fixed and Variable Operations and

Maintenance Costs $0.2 million $1.8 million

Total First Year Annualized Cost $0.2 million $ 6.4 million

Additional Power Consumption (megawatts) 0.05 3.4

Additional Annual Power Usage (million kilowatthours per year) 0.4 26.5

Incremental Particulate Matter (PM) Design Control

Efficiency 59.5% 79.7%

Incremental Tons PM Removed per Year 1,041 1,395

First Year Average Control Cost

(dollars per ton [$/Ton] of PM Removed) 169 4,556

Incremental Control Cost

($/Ton of SO 2 

# PM Removed) 169 17,426



# Preliminary BART Selection. CH2M HILL recommends selec tion of flue gas conditioning

upstream of the existing ESP as BART for Jim Br idger 2, based on the sign ificant reduction in

PM emissions, reasonable control costs, a nd advantages of minimal additional power

requirements and no environmental impacts.

Step 5: Evaluate Visibility Impacts

See Section 4, BART Modeling Analysis.BART ANALYSIS FOR JIM BRIDGER UNIT 2FIGURE 3-5First Year Control Cost for PM Air Pollution Control OptionsJim Bridger 202,0004,0006,0008,00010,00012,00014,00016,00018,00020,000Flue Gas ConditioningFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC3-20

# 4.0 BART Modeling Analysis

4.1 Model Selection

CH2M HILL used the CALPUFF modeling system (Gaussian puff dispersion model) to assess

the visibility impacts of emissions from Jim Bri dger 2 at nearby Class I areas. The Class I areas

potentially affected are located more than 50 kilometers (km) but le ss than 300 km from the

Jim Bridger 2 facility. The Class I areas incl ude the following wilderness areas (WAs):

• Bridger WA

• Fitzpatrick WA

• Mt. Zirkel WA

The CALPUFF modeling system includes th e CALMET meteorological model, CALPUFF

modeling system with algorithms for chemical transformation and deposition, and a post

processor capable of calculating concentrations, visibility imp acts, and deposition (CALPOST).

The CALPUFF modeling system wa s applied in a full, refined mode. Version numbers of the

various programs in the CALPUFF modeling sy stem used by CH2M HILL were as follows:

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

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

meteorological parameters suitable for us e by the CALPUFF modeling system. A modeling

domain was established to encompass the Jim Br idger 2 facility and allow for a 50-km buffer

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

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

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

(WDEQ-AQD), CH2M HILL followed the me thodology spelled out in the WDEQ-AQD

BART Modeling Protocol, a copy of which is included in this report as Appendix B.

CH2M HILL used the Lambert Conformal Conic ma p projection for the analysis because of the

large extent of the domain. The la titude of the projection origin and the longitude of the central

meridian were chosen at the approximate cente r of the domain. Standard parallels were drawn

to represent one-sixth and five-sixths of the north-south ex tent of the domain to minimize

distortion in the north-south direction.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-1BridgerWilderness AreaFitzpatrickWilderness AreaMount ZirkelWilderness AreaIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinLEGEND300 KilometersClass I AreasCALMET DomainStandard Parallels0 100 200 300KilometersFigure 4-1Jim Bridger 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" LatitudeJim BridgerSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\JIM_BRIDGER_CLASSI.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



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

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

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

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

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

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

analysis.

TABLE 4-1



# User-Specified CALMET Options

Jim Bridger 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-km reso lution Mesoscale Meteorologica l Model, Version 5 (MM5)

meteorological data fields that covered th e entire modeling domain for each study year.

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

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

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

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-4 

# Step 1 wind field, and further re fined using local surface observati ons to create a final Step 2

wind field.

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

CH2M HILL processed the data from the National Weather Service’s Automated Surface

Observing System (ASOS) network for all sta tions that are in the domain. The surface data

were obtained in abbreviated DATSAV3 format. A conversion routine av ailable from the TRC

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

preprocessor and CALMET.

Land use and terrain data were obtained from the U.S. 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, roughne ss length, and leaf area index were computed

from the land use values. Terrain data were taken from USGS 1-degr ee Digital Elevation

Model data, which primarily derive from USGS 1:250,000 scale topographic maps. Missing

land use data were filled with values that were assumed appropriate for the missing area.

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

fixed-length, TD-3240 format were obtained 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)APACAGITRASEAKOBridgerWilderness AreaFitzpatrickWilderness AreaMount ZirkelWilderness AreaIdahoUtahWyomingMontanaKansasColoradoNebraskaIowaNevadaSouth DakotaMinnesotaNorth DakotaMissouriOregonWashingtonWisconsinRAPIENPHPD07CUT2WXSNYBFFCDRAIALVMDLNBTMBZNBILLEGENDClass I AreasCALMET DomainASOS Surface StationsUpper Air Station0 100 200 300KilometersFigure 4-2Surface and Upper Air Stations Used in theJim Bridger 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" LatitudeJim BridgerSLC \\SLCDB\GIS\PROJECTS\HUNTER\MAPFILES\JIM_BRIDGER_ASOS.MXD 11/9/2006 MSLAYDEN

# BART ANALYSIS FOR JIM BRIDGER 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 with observed weather

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

Atmospheric Administration Central Librar y U.S. Daily Weather Maps Project ( National

Oceanic Atmospheric Administration, 2006).



# 4.3 CALPUFF Modeling Approach

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

WDEQ-AQD guidance provide d in the document titled BART Air Modeling

Protocol-Individual Source Visibility Assessments for BART Control Analyses (WDEQ-AQD,

2006).

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

the modeling domain described in this report . The CALPUFF modeling system was used to

predict visibility impacts for the pre-control (bas eline) scenario for comparison to the predicted

impacts for post-control scenarios for Jim Bridger 2.



# 4.3.1 Background Ozone and Ammonia

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

of SO 2 

# and NO

x 

# transformation with the MESOPUFF II chemical transformation scheme.

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

modeling domain for 2001, 2002, and 2003:

• Rocky Mountain National Park, Colorado

• Craters of the Moon National Park, Idaho

• Highland, Utah

• Thunder Basin National Grasslands, Wyoming

• Yellowstone National Park, Wyoming

• Centennial, Wyoming

• Pinedale, Wyoming

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

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

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



# 4.3.2 Stack Parameters

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

current permit for Jim Bridger 2, except for the NO

x 

# emission rate where 0.24 lb per MMBtu

(achieved with the new LNB with OFA system) was used in lieu of the permit limit of 0.45 lb

per MMBtu. Post-control stack parameters reflec t the anticipated changes associated with

installation of the control technology alternativ es that are being evaluated. The maximum heat

input rate of 6,000 MMBtu per hour was used to calculate a maximum emission rate. Measured

velocities and stack flow rates were used in the modeling to represen t a worst-case situation.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# 4.3.3 Emission Rates

Pre-control emission rates for Jim Bridger 2 refl ect peak 24-hour average emissions that could

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

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

Guidelines for Best Available Retrofit Technology Determinations; Final Rule

(40 CFR Part 51).

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

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

more recent period was more repr esentative. Allowable short-term (24-hour or shorter period)

emissions or short-term emission limits were us ed if continuous emissi on monitoring data were

not available.

Emissions were modeled for the following pollutants:

• 

# SO 2



# • 

# NO

x



# • 

# Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• 

# Fine particulate (diameter<PM 2.5 

# )

• 

# Sulfates

Post-control emission rates reflect the effect s of the emissions control scenario under

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



# 4.3.4 Post-control Scenarios

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

the combination of the individual NO

x 

# , SO 2 

# , and PM control technolog ies being evaluated. The

selection of each control device was made base d on the engineering analyses described in

Section 3 for reasonable technologies that woul d meet or exceed the presumptive BART levels

for each pollutant.

• 

# Scenario 1 : Existing LNB with OFA, upgraded we t FGD system, and FGC for enhanced

ESP performance. As indicated previousl y, this scenario represents CH2M HILL’s

preliminary BART recommendation.

• 

# Scenario 2 : Existing LNB with OFA, upgraded wet FGD system, and new polishing fabric

filter.

• 

# Scenario 3 : Existing LNB with OFA and SCR, upgr aded wet FGD system, and flue gas

conditioning for enhanced ESP performance.

• 

# Scenario 4 : Existing LNB with OFA and SCR, upgraded wet FGD system, and new

polishing fabric filter.

The ROFA and SNCR options for NO

x 

# control were not included in the modeling scenarios

because their control effectiveness is betw een the existing LNB with OFA option and the

SCR option. Modeling of NO

x 

# , SO 2 

# , and PM controls alone was not performed because any

final BART solution will include a comb ination of control technologies for NO

x 

# , SO 2 

# , and PM.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-8 

# Table 4-2 presents the stack parameters and emi ssion rates used for the Jim Bridger 2 analysis

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

protocol, elemental carbon stack emissions and organic aerosol emissions were not modeled.



# 4.3.5 Modeling Process

The CALPUFF modeling system for the control technology options for Jim Bridger 2 followed

this sequence:

• 

# Model pre-control (baseline) emissions

• 

# Model preferred post-control scenario (if applicable)

• 

# Determine degree of visibility improvement

• 

# Model other control scenarios

• 

# Determine degree of visibility improvement

• 

# Factor visibility results into BART five-step evaluation



# 4.3.6 Receptor Grids

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

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

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

TRC COORDS program was used to convert a ll latitude/longitude coordinates to Lambert

Conformal Conic coordinates, including rece ptors, meteorological stations, and source

locations.TABLE 4-2BART Model Input DataJim Bridger 2BaselinePost-control Scenario 1Post-control Scenario2Post-control Scenario 3 Post-control Scenario 4Current Operations with Existing LowNOXBurners (LNBs), wet Flue GasDesulfurization (FGD) andElectrostatic Precipitator (ESP)LNB with Over-fire Air (OFA), WetFGD, Flue Gas Conditioning(FGC) for enhanced ESPPerformanceLNB with OFA, Wet FGD, NewFabric FilterLNB with OFA and SelectiveCatalytic Reduction (SCR), WetFGD, FGC for enhanced ESPPerformanceLNB with OFA and SCR,Wet FGD, Fabric FilterSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])1,602 600 600 600 600Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,4401,4401,440420420PM10Stack Emissions (lb/hr)444 180 90.0 180 90.0Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)191 77.4 51.3 77.4 51.3Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)253 103 38.7 103 38.7Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 55.2 55.2 55.2 94.8 94.8H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 54.1 54.1 54.1 92.9 92.9Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)7.027.02(NH4)2SO4as SO4Stack Emissions (lb/hr)5.105.10(NH4)HSO4Stack Emissions (lb/hr)12.2 12.2(NH4)HSO4as SO4Stack Emissions (lb/hr)10.2 10.2Total Sulfate (SO4) (lb/hr)54.1 54.1 54.1 108 108Stack ConditionsStack Height (meters)152 152 152 152 152Stack Exit Diameter (meters)7.32 7.32 7.32 7.32 7.32Stack Exit Temperature (Kelvin)333 322 333 333 333Stack Exit Velocity (meters per second)27.4 24.7 27.4 27.4 27.4NOTES:Scenarios 2, 3, and 4 were not remodeled at the lower, correct velocity of 81.24 feet per second due to lack of time and the fact that the conclusions to select Scenario 1 would not have changed.aBased on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 43 percent ESP and 57 percent baghouse.bBased 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)TABLE 4-2BART Model Input DataJim Bridger 2Baseline Post-control Scenario 1 Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Current Operations with Existing LowNOXBurners (LNBs), wet Flue GasDesulfurization (FGD) andElectrostatic Precipitator (ESP)LNB with Over-fire Air (OFA), WetFGD, Flue Gas Conditioning(FGC) for enhanced ESPPerformanceLNB with OFA, Wet FGD, NewFabric FilterLNB with OFA and SelectiveCatalytic Reduction (SCR), WetFGD, FGC for enhanced ESPPerformanceLNB with OFA and SCR,Wet FGD, Fabric FilterSulfur Dioxide (SO2) StackEmissions(pounds per hour [lb/hr])1,602 600 600 600 600Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 1,440 1,440 1,440 420 420PM10Stack Emissions (lb/hr)444 180 90.0 180 90.0Coarse Particulate (PM2.5<diameter< PM10) Stack Emissions (lb/hr)(a)191 77.4 51.3 77.4 51.3Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)253 103 38.7 103 38.7Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 55.2 55.2 55.2 94.8 94.8H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 54.1 54.1 54.1 92.9 92.9Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr) 7.02 7.02(NH4)2SO4as SO4Stack Emissions (lb/hr)5.10 5.10(NH4)HSO4Stack Emissions (lb/hr)12.2 12.2(NH4)HSO4as SO4Stack Emissions (lb/hr)10.2 10.2Total Sulfate (SO4) (lb/hr)54.1 54.1 54.1 108 108Stack ConditionsStack Height (meters)152 152 152 152 152Stack Exit Diameter (meters)7.32 7.32 7.32 7.32 7.32Stack Exit Temperature (Kelvin)333 322 333 333 333Stack Exit Velocity (meters per second)27.4 24.7 27.4 27.4 27.4NOTES:Scenarios 2, 3, and 4 were not remodeled at the lower, correct velocity of 81.24 feet per second due to lack of time and the fact that the conclusions to select Scenario 1 would not have changed.aBased on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 43 percent ESP and 57 percent baghouse.bBased 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 JIM BRIDGER UNIT 2



# 4.4 CALPOST

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

specified in deciview (dV) units . Calculations of light extincti on were made for each pollutant

modeled. The sum of all extinction values were used to calculate the delta-dV ( Δ dV) change

relative to natural background. The following defa ult light extinction co efficients for each

pollutant were used:

• 

# Ammonium sulfate 3.0

• 

# Ammonium nitrate 3.0

• 

# PM coarse (PM 10 

# ) 0.6

• 

# PM fine (PM 2.5 

# ) 1.0

• 

# Organic carbon 4.0

• 

# Elemental carbon 10.0

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

humidity factors [ f (RH)] were used in the light extinc tion calculations to account for the

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

Modeling Protocol (Appendi x B) lists the monthly f (RH) factors for the Class I areas. These

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

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

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

values for the 10 percent best days for each Cla ss I area, but did not provide individual species

concentration data for the 20 percent best da ys. Species concentrations corresponding to the

20 percent best days were calculated for each Class I area by scaling b ack the annual average

species concentrations given in Table 2-1 of Guidance for Estimating Natural Visibility

Conditions Under the Regional Haze Rule (EPA, 2003). A separate scaling factor was derived

for each Class I area such that, when multiplied by the guidance table annual concentrations,

the 20 percent best days dV value for that area would be calculated. Th is procedure was taken

from Protocol for BART-Related Visibility Impr ovement Modeling Analys is in North Dakota

(North Dakota Department of Health, 2005). Th e Wyoming BART Air Modeling Protocol (see

Appendix B) provided natural background concentra tions of aerosol components to use in the

BART analysis. Table 4-3 lists the annual aver age species concentrations from the BART

protocol.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-10

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 4-11 

# TABLE 4-3



# Average Natural Levels of Aerosol Components

Jim Bridger 2

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Mt. Zirkel Class I

Wilderness Area Average Natural Concentration

(micrograms per cubic meter)

for Fitzpatrick and Bridger Class I

Wilderness Areas

Ammonium Sulfate 0.046 0.045

Ammonium Nitrate 0.038 0.038

Organic Carbon 0.179 0.178

Elemental Carbon 0.008 0.008

Soil 0.190 0.189

Coarse Mass 1.141 1.136

NOTES:

Data in this table was taken from Table 6 of the Wyoming BART Air Modeling Protocol.



# 4.5 Presentation of Modeling Results

This section presents the result s of the CALPUFF visi bility improvement modeling analysis for

Jim Bridger 2.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Jim Bridger 2 for the baselin e conditions and post-c ontrol scenarios. The

post-control scenarios included emission rates for NO

x, 

# SO 2 

# , and PM 10 

# that would be achieved

if BART technology were installed on Unit 2.

Baseline (and post-control) 98 th 

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

Fitzpatrick, and Mt. Zirkel WAs. The 98 th 

# percentile results for each Class I area are presented

in Table 4-4.BART ANALYSIS FOR JIM BRIDGER UNIT 2TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasJim Bridger 2ModelingResultsScenarioTotal First YearAnnualized CostClass I AreaHighest Delta-(dV)98thPercentileDelta- (dV)Number (No.)of Days Above0.5 dVCost per dV ReductionCost per Reductionin No. of Days Above0.5 dVIncremental Costper dV ReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2001Bridger WA1.7300.53010----Fitzpatrick WA1.3580.2984----Baseline: current operation with wet FGD, ESPMt. Zirkel WA1.3840.84223----$2,494,828Bridger WA1.3700.3857$17,205,710$831,609$2,494,828Fitzpatrick WA1.3680.2233$33,264,373$2,494,828Scenario 1: Existing LNB with OFA, upgrade wet FGD,FGC for enhanced ESP performance$2,494,828Mt. Zirkel WA1.1630.73316$22,888,330$356,404$8,852,380Bridger WA1.3960.3756$57,112,131$2,213,095$635,755,230$6,357,552$8,852,380Fitzpatrick WA1.1770.2103$100,595,230$8,852,380$489,042,485NAScenario 2: Existing LNB with OFA, upgrade wet FGD,polishing fabric filter$8,852,380Mt. Zirkel WA1.1030.68115$54,983,728$1,106,548$122,260,621$6,357,552$17,187,631Bridger WA0.8760.2793$68,476,618$2,455,376$86,825,531$2,778,417$17,187,631Fitzpatrick WA0.6780.1271$100,512,463$5,729,210$100,424,711$4,167,625Scenario 3: Existing LNB with OFA and SCR, upgradewet FGD, FGC for enhanced ESP performance$17,187,631Mt. Zirkel WA0.7580.4555$44,412,484$954,868$36,881,641$833,525$23,545,184Bridger WA0.8380.2683$89,867,113$3,363,598$577,959,300NA$23,545,184Fitzpatrick WA0.6570.1251$136,099,327$7,848,395$3,178,776,151NAScenario 4: Existing LNB with OFA and SCR, upgradewet FGD, polishing fabric filter$23,545,184Mt. Zirkel WA0.7310.4392$58,424,773$1,121,199$397,347,019$2,119,1842002Bridger WA2.8380.99020----Fitzpatrick WA1.2730.5348----Baseline: current operation with wet FGD, ESPMt. Zirkel WA1.9751.00818----$2,494,828Bridger WA2.4420.84714$17,446,349$415,805$2,494,828Fitzpatrick WA1.0730.3775$15,890,624$831,609Scenario 1: Existing LNB with OFA, upgrade wet FGD,FGC for enhanced ESP performance$2,494,828Mt. Zirkel WA1.5450.81513$12,926,570$498,966$8,852,380Bridger WA2.3170.78413$42,972,720$1,264,626$100,913,529$6,357,552$8,852,380Fitzpatrick WA0.9970.3486$47,593,442$4,426,190$219,225,941NAScenario 2: Existing LNB with OFA, upgrade wet FGD,polishing fabric filter$8,852,380Mt. Zirkel WA1.4870.77713$38,321,992$1,770,476$167,304,008NA$17,187,631Bridger WA1.3160.5169$36,260,825$1,562,512$31,101,683$2,083,813$17,187,631Fitzpatrick WA0.5460.2261$55,803,997$2,455,376$68,321,729$1,667,050Scenario 3: Existing LNB with OFA and SCR, upgradewet FGD, FGC for enhanced ESP performance$17,187,631Mt. Zirkel WA0.8840.4745$32,186,575$1,322,125$27,509,079$1,041,906$23,545,184Bridger WA1.2900.4997$47,953,531$1,811,168$373,973,665$3,178,776$23,545,184Fitzpatrick WA0.5360.2221$75,465,332$3,363,598$1,589,388,076NAScenario 4: Existing LNB with OFA and SCR, upgradewet FGD, polishing fabric filter$23,545,184Mt. Zirkel WA0.8650.4654$43,361,296$1,681,799$706,394,700$6,357,552JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC4-12BART ANALYSIS FOR JIM BRIDGER UNIT 2JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC4-13TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasJim Bridger 2ModelingResultsScenarioTotal First YearAnnualized CostClass I AreaHighest Delta-(dV)98thPercentileDelta- (dV)Number (No.)of Days Above0.5 dVCost per dV ReductionCost per Reductionin No. of Days Above0.5 dVIncremental Costper dV ReductionIncremental Cost perReduction in No. ofDays Above 0.5 dV2003Bridger WA1.2080.5339----Fitzpatrick WA1.3480.2633----Baseline: current operation with wet FGD, ESPMt. Zirkel WA1.3040.80320----$2,494,828Bridger WA0.9950.4165$21,323,316$623,707$2,494,828Fitzpatrick WA1.1180.2002$39,600,444$2,494,828Scenario 1: Existing LNB with OFA, upgrade wet FGD,FGC for enhanced ESP performance$2,494,828Mt. Zirkel WA1.0430.73516-$10,395,116$623,707$8,852,380Bridger WA0.9830.4095$71,390,163$2,213,095$908,221,758NA$8,852,380Fitzpatrick WA1.0900.1882$118,031,737$8,852,380$529,796,025NAScenario 2: Existing LNB with OFA, upgrade wet FGD,polishing fabric filter$8,852,380Mt. Zirkel WA1.0540.68815$76,977,220$1,770,476$135,267,070$6,357,552$17,187,631Bridger WA0.8520.2583$62,500,477$2,864,605$55,200,338$4,167,625$17,187,631Fitzpatrick WA0.6830.1182$118,535,388$17,187,631$119,075,014NAScenario 3: Existing LNB with OFA and SCR, upgradewet FGD, FGC for enhanced ESP performance$17,187,631Mt. Zirkel WA0.6670.4355$46,705,520$1,145,842$32,945,656$833,525$23,545,184Bridger WA0.8080.2483$82,614,679$3,924,197$635,755,230NA$23,545,184Fitzpatrick WA0.6650.1152$159,089,078$23,545,184$2,119,184,101NAScenario 4: Existing LNB with OFA and SCR, upgradewet FGD, polishing fabric filter$23,545,184Mt. Zirkel WA0.6350.4235$61,961,009$1,569,679$529,796,025NA3-year AveragesBridger WA0.68413.0Fitzpatrick WA0.3655.0Baseline: current operation with wet FGD, ESPMt. Zirkel WA0.88420.3$2,494,828Bridger WA0.5498.7$18,480,207$575,730$2,494,828Fitzpatrick WA0.2673.3$25,371,132$1,496,897Scenario 1: Existing LNB with OFA, upgrade wet FGD,FGC for enhanced ESP performance$2,494,828Mt. Zirkel WA0.76115.0$20,228,335$467,780$8,852,380Bridger WA0.5238.0$54,756,991$1,770,476$238,408,211$9,536,328$8,852,380Fitzpatrick WA0.2493.7$76,094,959$6,639,285$353,197,350NAScenario 2: Existing LNB with OFA, upgrade wet FGD,polishing fabric filter$8,852,380Mt. Zirkel WA0.71514.3$52,380,948$1,475,397$139,216,474$9,536,328$17,187,631Bridger WA0.3515.0$51,562,894$2,148,454$48,554,860$2,778,417$17,187,631Fitzpatrick WA0.1571.3$82,632,842$4,687,536$90,930,011$3,572,250Scenario 3: Existing LNB with OFA and SCR, upgradewet FGD, FGC for enhanced ESP performance$17,187,631Mt. Zirkel WA0.4555.0$40,002,245$1,120,932$31,976,666$893,063$23,545,184Bridger WA0.3384.3$68,049,663$2,716,752$501,912,024$9,536,328$23,545,184Fitzpatrick WA0.1541.3$111,588,548$6,421,414$2,119,184,101NAScenario 4: Existing LNB with OFA and SCR, upgradewet FGD, polishing fabric filter$23,545,184Mt. Zirkel WA0.4423.7$53,269,646$1,412,711$515,477,214$4,768,164NOTES:Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $2,494,828 / (0.814 - 0.424) = $6,396,995Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $2,494,828 / (20 - 7) = $191,910.

# 5.0 Preliminary Assessment and

Recommendations

As a result of the completed technical and ec onomic evaluations, and consideration of the

modeling analysis for Jim Bridger 2, the pr eliminary recommended BART controls for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# Existing LNBs and OFA system for NO

x 

# control

• 

# Upgrade the existing wet sodium FGD for SO 2 

# control

• 

# Add flue gas conditioning upstream of the existing ESP for PM control

The above recommendations were identified as S cenario 1 for the modeling analysis described

in Section 4. Visibility improvements for all em ission control scenarios were analyzed, and the

results are compared below, utilizing a least- cost envelope, as outlined in the draft EPA 1990

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

purpose of this analysis is to use an object ive, EPA-approved methodology to evaluate and

make the final recommendation of BART control technology.



# 5.1 Least-cost Envelope Analysis

For the control scenarios modeled in Section 4, Tables 5-1 through 5-3 lis t the total annualized

cost, cost per dV reduction, and cost per reduc tion in number of days above 0.5 dV for each of

the three Class I areas. A comparison of the incr emental results between selected scenarios is

provided in Tables 5-4 through 5- 6. Figures 5-1 to 5-6 show the total annualized cost versus

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

# percentile Δ dV

reduction, for the three Class I areas.



# 5.1.1 Analysis Methodology

On page B-41 of the New Source Manual, EPA st ates that “incremental cost-effectiveness

comparisons should focus on annualized cost and emission reduction differences between

dominant alternatives. Dominant set of control alternatives are determined by generating what

is called the envelope of least- cost alternatives. This is a gr aphical plot of total annualized

costs for a total emissions reductions for all control alternatives identified in the BACT

analysis...”

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

in the following way. First, the control opti on scenarios are ranked in ascending order of

annualized total costs, as shown in Tables 5- 1 through 5-3. The incremen tal cost effectiveness

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

summarized in Tables 5-4 through 5-6 for each of the three wilderness areas. Then the most

reasonable smooth curve of least-cost control option scenarios is plotted for each analysis.

Figures 5-1 through 5-6 present th e two analyses (cost per dV reduction and cost per reduction

in number of days above 0.5 dV) for each of the three Class I areas aff ected by the operation of

Jim Bridger 2.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



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

number of days above 0.5 dV. EPA states that “in calculating incrementa l costs, the analysis

should only be conducted for control options that are dominant among all possible options.” In

Figure 5-1, the dominant set of control options, Scenarios 1, 3 and 4, represent the least-cost

envelope depicted by the curvilin ear line connecting them. Scenario 2 is an inferior option and

should not be considered in the derivation of incremental cost effec tiveness. Scenario 2

represents inferior controls, because Scenario 1 provides approximately the same amount of

visibility impact reduction for less cost than S cenario 2. The incremental cost effectiveness is

determined by the difference in total annual co sts between two contiguo us scenarios divided

by the difference in emissions reduction.

TABLE 5-1



# Control Scenario Results for the Br idger Class 1 Wilderness Area

Jim Bridger 2

Scenario Controls 98 th



# Percentile

deciview

(dV)

Reduction Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualize

d 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

Wet Flue Gas

Desulfurization (FGD),

Electrostatic Precipitator

(ESP) 0.00 0.0 $0.0 $0.0 $0.0

1 Existing Low-NO X 

# burner

(LNB) with OFA,

upgraded wet FGD

system, and Flue Gas

Conditioning (FGC) for

enhanced ESP

performance 0.14 4.3 $2.5 $18.5 $0.6

2 LNB with OFA, upgraded

wet FGD system, and

new polishing fabric filter 0.16 5.0 $8.9 $54.8 $1.8

3 LNB with OFA and SCR,

upgraded wet FGD

system, FGC for

enhanced ESP

performance 0.33 8.0 $17.2 $51.6 $2.1

4 LNB with OFA and SCR,

upgraded wet FGD

system, new polishing

fabric filter 0.35 8.7 $23.5 $68.0 $2.7

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# TABLE 5-2



# Control Scenario Results for the Fitzpatrick Class I Wilderness Area

Jim Bridger 2

Scenario Controls 98 th



# Percentile

dV

Reduction Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualized

Cost

(Million$) Cost per

dV

Reduction

(Million$/dV

Reduced) Cost per

Reduction in No.

of Days Above

0.5 dV

(Million$/Day

Reduced)

Base Current Operation with Wet

FGD and ESP 0.00 0.0 $0.0 $0.0 $0.0

1 Existing LNB with OFA,

upgraded wet FGD system,

and FGC for enhanced

ESP performance 0.10 1.7 $2.5 $25.4 $1.5

2 LNB with OFA, upgraded

wet FGD system, and new

polishing fabric filter 0.12 1.3 $8.9 $76.1 $6.6

3 LNB with OFA and SCR,

upgraded wet FGD system,

FGC for enhanced ESP

performance 0.21 3.7 $17.2 $82.6 $4.7

4 LNB with OFA and SCR,

upgraded wet FGD system,

new polishing fabric filter 0.21 3.7 $23.5 $111.6 $6.4

TABLE 5-3



# Control Scenario Results for the Mt. Zirkel Class I Wilderness Area

Jim Bridger 2

Scenario Controls 98 th



# Percentile

dV

Reduction Average

Number of

Days

Above

0.5 dV

(Days) Total

Annualized

Cost

(Million$) Cost per

dV

Reduction

(Million$/dV

Reduced) Cost per

Reduction in No.

of Days Above

0.5 dV

(Million$/Day

Reduced)

Base Current Operation with Wet

FGD and ESP 0.00 0.0 $0.0 $0.0 $0.0

1 Existing LNB with OFA,

upgraded wet FGD system,

and FGC for enhanced

ESP performance 0.12 5.3 $2.5 $20.2 $0.5

2 LNB with OFA, upgraded

wet FGD system, and new

polishing fabric filter. 0.17 6.0 $8.9 $52.4 $1.5

3 LNB with OFA and SCR,

upgraded wet FGD system,

FGC for enhanced ESP

performance 0.43 15.3 $17. 2 $40.0 $1.1

4 LNB with OFA and SCR,

upgraded wet FGD system,

new polishing fabric filter. 0.44 16.7 $23. 5 $53.3 $1.4

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# TABLE 5-4



# Bridger Class I Wilderness Area Incremental Analysis Data

Jim Bridger 2

Options Compared Incremental

Reduction in

Days Above

0.5 deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 4.3 0.14 $0.58 $18.5

Scenario 1 and Scenario 2 0.7 0.03 $9.5 $238.4

Scenario 1 and Scenario 3 3.7 0.20 $4.0 $74.1

Scenario 1 and Scenario 4 4.3 0.21 $4.9 $99.8

TABLE 5-5



# Fitzpatrick Class I Wilderness Area Incremental Analysis Data

Jim Bridger 2

Options Compared Incremental

Reduction in

Days Above

0.5 deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 1.7 0.10 $1.50 $25.4

Scenario 1 and Scenario 2 NA 0.02 NA $353.2

Scenario 1 and Scenario 3 2.0 0.11 $7.3 $134.0

Scenario 1 and Scenario 4 2.0 0.11 $10.5 $186.8

TABLE 5-6



# Mt. Zirkel Class I Wilderness Area Incremental Analysis Data

Jim Bridger 2

Options Compared Incremental

Reduction in

Days Above

0.5 dV (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 5.3 0.12 $0.47 $20.23

Scenario 1 and Scenario 2 0.7 0.05 $9.5 $139.2

Scenario 1 and Scenario 3 10.0 0.31 $1.5 $48.0

Scenario 1 and Scenario 4 11.3 0.32 $1.9 $66.1

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# FIGURE 5-1



# Least-cost Envelope Bridger Cla ss I Wilderness Area Days Reduction

Jim Bridger 2

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

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

0123456789



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



# 1 0



# FIGURE 5-2



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



# Percentile Reduction

Jim Bridger 2

Scenario 3

Scenario 2

Scenario 1 Baseline Scenario 4

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

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40



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



# JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick Cla ss I Wilderness Area Days Reduction

Jim Bridger 2

Scenario 3

Scenario 2

Scenario 1 Baseline Scenario 4

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

011223344



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



# FIGURE 5-4



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



# Percentile Reduction

Jim Bridger 2

Scenario 3

Scenario 2

Scenario 1 Baseline Scenario 4

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

0.00 0.05 0.10 0.15 0.20 0.25



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



# JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# FIGURE 5-5



# Least-cost Envelope Mt. Zirkel Class I Wilderness Area Days Reduction

Jim Bridger 2

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0 2 4 6 8 1 0 1 2 1 4 1 6



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



# 1 8



# FIGURE 5-6



# Least-cost Envelope Mt. Zirkel Class I Wilderness Area 98 th



# Percentile Reduction

Jim Bridger 2

Scenario 3

Scenario 2

Scenario 1 Baseline Scenario 4

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

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50



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



# JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 2



# 5.1.2 Analysis Results

Results of the least-cost analysis, shown in Tables 5-1 th rough 5-6 and Figures 5-1 through 5-6

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

visibility improvements. Scenario 2 is eliminated because it is to the left of the curve formed

by the dominant control alternat ive scenarios, which indicat es a scenario with lower

improvement and/or higher costs. Scenario 3 is not selected due to very high incremental costs

for both a cost per day of improvement and a co st per dV reduction. While Scenario 4 provides

some potential visibility advantage over Scenar io 1, the projected improvement is less than

half a dV, and the projected costs are excessive.

Analysis of the results for the Jim Bridger Cl ass 1WA in Tables 5-1 and 5-4 and Figures 5-1

and 5-2 illustrates the co nclusions stated above. Th e greatest reduction in 98 th 

# percentile dV

and number of days above 0.5 dV is between the baseline and Scenario 1. The incremental cost

effectiveness for Scenario 1 compared with the baseline for the Bridger WA, for example, is

reasonable at $580,000 per day and $18.5 million per deciview. However, the incremental cost

effectiveness for Scenario 3 compared with Scenario 1 is excessive at $4.0 million per day and

$71.1 million per deciview. The same conclusion s are reached for each of the three WAs

studied. Therefore, Scenario 1 repr esents BART for Jim Bridger 2.



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by EPA for tangentially fired boilers burning

sub-bituminous coal is 0.15 lb per MMBtu. Ho wever, as documented in Section 3.2.1, the

characteristics of the Jim Bridger coals are more closely aligned with bituminous coals, with a

presumptive BART NO

x 

# limit of 0.28 lb per MMBtu.

CH2M HILL recommends the existing LNBs with OFA (LNB with OFA) as BART for

Jim Bridger 2, based on the proj ected significant reduction in NO

x 

# emissions, reasonable

control costs, and the advantages of no a dditional power requireme nts or non-air quality

environmental impacts. NO

x 

# reductions have been realized at Jim Bridger 2. CH2M HILL

recommends that the unit be permitte d at a rate of 0.26 lb per MMBtu.



# 5.2.2 SO 2 

# Emission Control

CH2M HILL recommends upgrading the existin g wet sodium FGD system as BART for

Jim Bridger 2, based on the significant reduction in SO 2 

# emissions, reasonable control costs,

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

environmental impacts. This upgrade appr oach will meet the BART presumptive SO 2 

# limit of

0.15 lb per MMBtu.



# 5.2.3 PM 10



# Emission Control

CH2M HILL recommends finalizing the permitting of the FGC system to enhance the

performance of the existing ESP as BART for Jim Bridger 2, based on the significant reduction

in PM 10 

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

requirements and no non-air quality environmental impacts.

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 2

JMS EY102007001SLC\BART_JB2_OCT2007_FINAL.DOC 5-9 

# 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 perceptible by the human eye. Deciview changes of less than 1.5 cannot be

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

minimal, if any, observable visibility improveme nts at the Class I areas studied would be

expected under any of the scenarios. Thus th e results indicate that even though many millions

of dollars will be spent, only minimal, if any, visibility improvements could result.

None of the data were corrected for natura l obscuration. Water in various forms (fog, clouds,

snow, or rain) or other naturally caused aer osols can obscure the atmosphere and reduce

visibility. During the period of 2001 through 200 3, there were several mega-wildfires that

lasted for many days, with a sign ificant impact on background visibi lity in these Class 1 areas.

If natural obscuration lessens the achievable reduction in visibility impacts modeled for BART

controls at the Jim Bridger 2 f acility, the overall effect would be to increase the costs per dV

reduction that are presen ted in this report.

# 6.0 References

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

Technology Determinations; Final Rule. July 6, 2005.

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

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

.

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_JB2_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios4Index 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 Wyodak Unit 1Scenario First Year Cost ScenarioFirst YearCost Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/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/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/A N/AN/A N/A N/A N/A N/AScenario First Year Cost Scenario First Year Scenario First Year Cost Scenario First Year Cost Scenario First Year CostN/AN/A $ 2,494,828 N/A N/AN/AN/A $ 2,494,828 N/A N/AN/A $ 2,494,828 N/A N/AN/AN/AN/A $ 8,852,380 N/A N/AN/A $ 8,852,380 N/A N/AN/AN/A $ 8,852,380 N/A N/A N/AN/A $ 17,187,631 N/A N/A N/AN/A $ 17,187,631 N/A N/A N/AN/A $ 17,187,631 N/A N/AN/A $ 23,545,184 N/A N/AN/A $ 23,545,184 N/A N/AN/A $ 23,545,184 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 WetFGD and 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, Wet FGD,New Fabric FilterScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, Wet FGD,ESPScenario 4 - LNB with OFA and SCR, WetFGD, 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, WetFGD, ESPScenario 4 - N/AJim Bridger Unit 2Scenario 3 - LNB with OFA and SCR, WetFGD, Fabric Filter, New StackScenario 2 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 1 - LNB with OFA, Dry FGD,Fabric FilterBaseline - Current Operation with DryFGD, Fabric FilterWDK Unit 1WyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYJim Bridger Unit 2Boiler Design: Tangential-Fired PCExist. LNBw/OFAROFA SNCR SCRUpgraded WetFGDFlue GasConditioningFabric FilterCase1 2 3 4 5 8 9 10NOx Emission Control SystemLNB - TFS 2000 Exist. LNB w/OFA ROFA SNCR SCR LNB - TFS 2000 LNB - TFS 2000 LNB - TFS 2000SO2 Emission Control SystemWet FGD Wet FGD Wet FGD Wet FGD Wet FGD Upgraded Wet FGD Wet FGD Wet FGDPM Emission Control SystemESP ESP ESP ESP ESP ESP Flue Gas Conditioning Fabric FilterTOTAL INSTALLED CAPITAL COST ($)0 0 20,528,122 13,427,239 120,875,494 12,999,900 0 48,386,333FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 0 0 0Maintenance Material ($) 0 0 42,000 95,000 162,000 25,550 0 51,099Maintenance Labor ($) 0 0 63,000 142,500 243,000 17,033 10,000 76,649Administrative Labor ($) 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST 0 0 105,000 237,500 405,000 42,583 10,000 127,749Makeup Water Cost 0 0 0 0 0 30,503 0 0Reagent Cost 0 0 0 536,432 912,848 533,206 145,854 0SCR Catalyst / FF Bag Cost 0 0 0 0 594,000 0 0 300,040Waste Disposal Cost 0 0 0 0 0 442,958 0 0Electric Power Cost 0 0 2,528,012 208,926 1,282,333 208,926 19,710 1,326,877TOTAL VARIABLE O&M COST0 0 2,528,012 745,358 2,789,181 1,215,593 165,564 1,626,917TOTAL FIRST YEAR O&M COST 0 0 2,633,012 982,858 3,194,181 1,258,176 175,564 1,754,666FIRST YEAR DEBT SERVICE ($)0 0 1,952,796 1,277,304 11,498,623 1,236,652 0 4,602,887TOTAL FIRST YEAR COST ($)0 0 4,585,808 2,260,162 14,692,803 2,494,828 175,564 6,357,552Power Consumption (MW)0.0 0.0 6.4 0.5 3.3 0.5 0.1 3.4Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 50.6 4.2 25.6 4.2 0.4 26.5CONTROL COST ($/Ton Removed)NOx Removal Rate (%) 0.0% 0.0% 8.3% 16.7% 70.8% 0.0% 0.0% 0.0%NOx Removed (Tons/Yr) 0 0 473 946 4,021 0 0 0First Year Average Control Cost ($/Ton NOx Rem.) 0 0 9,695 2,389 3,654 0 0 0Incremental Control Cost ($/Ton NOx Removed) 0 0 9,695 2,389 4,044 0 0 02-1 3-2 4-2 5-4SO2 Removal Rate (%) 77.8% 0.0% 0.0% 0.0% 0.0% 62.5% 0.0% 0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 3,950 0 0First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 632 0 0Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 632 0 08-1PM Removal Rate (%) 99.13% 0.00% 0.00% 0.00% 0.00% 0.00% 59.46% 79.73%PM Removed (Tons/Yr) 0 0 0 0 0 0 1,041 1,395First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 0 169 4,556Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 169 17,4269-1 10-9PRESENT WORTH COST ($)0 0 52,697,883 25,435,659 159,901,524 28,372,107 2,145,015 69,824,582PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls1 of 1INPUT CALCULATIONSJim Bridger Unit 2Boiler Design:Tangential-Fired PCExist. LNBw/OFAROFA SNCR SCRUpgraded WetFGDFlue GasConditioningFabric FilterCase1 2 3 4 5 8 9 10NOx Emission Control SystemLNB - TFS 2000 Exist. LNB w/OFA ROFA SNCR SCRLNB - TFS 2000 LNB - TFS 2000 LNB - TFS 2000SO2 Emission Control SystemWet FGDWet FGD Wet FGD Wet FGD Wet FGDUpgraded Wet FGDWet FGD Wet FGDPM Emission Control SystemESPESP ESP ESP ESP ESPFlue GasConditioning Fabric FilterUnit Design and Coal CharacteristicsType of UnitPC PC PC PC PC PC PC PCNet Power Output (kW)530,000530,000 530,000 530,000 530,000 530,000 530,000 530,000Net Plant Heat Rate (Btu/kW-Hr)11,32011,320 11,320 11,320 11,320 11,320 11,320 11,320Boiler FuelBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundBridger MineUndergroundCoal Heating Value (Btu/Lb)9,6609,660 9,660 9,660 9,660 9,660 9,660 9,660Coal Sulfur Content (wt.%)0.58%0.58%0.58%0.58%0.58%0.581%0.58%0.58%Coal Ash Content (wt.%)10.30%10.30%10.30%10.30%10.30%10.30%10.30%10.30%Boiler Heat Input, each (MMBtu/Hr)6,000 6,000 6,000 6,000 6,000 6,000 6,000 6,000Coal Flow Rate (Lb/Hr)621,077 621,077 621,077 621,077 621,077 621,077 621,077 621,077(Ton/Yr)2,448,2842,448,2842,448,2842,448,2842,448,2842,448,2842,448,2842,448,284(MMBtu/Yr)47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846EmissionsUncontrolled SO2 (Lb/Hr)7,210 1,602 1,602 1,602 1,602 1,602 1,602 1,602(Lb/MMBtu)1.20 0.27 0.27 0.27 0.27 0.27 0.27 0.27(Lb Moles/Hr)112.54 25.00 25.00 25.00 25.00 25.00 25.00 25.00(Tons/Yr)28,421 6,315 6,315 6,315 6,315 6,315 6,315 6,315SO2 Removal Rate (%)77.8%0.0%0.0%0.0%0.0%62.5%0.0%0.0%(Lb/Hr)5,608 0 0 0 0 1,002 0 0(Ton/Yr)22,106 0 0 0 0 3,950 0 0SO2 Emission Rate (Lb/Hr)1,602 1,602 1,602 1,602 1,602 600 1,602 1,602(Lb/MMBtu)0.270.27 0.27 0.27 0.270.100.27 0.27(Ton/Yr)6,315 6,315 6,315 6,315 6,315 2,365 6,315 6,315Uncontrolled NOx (Lb/Hr)1,440 1,440 1,440 1,440 1,440 1,440 1,440 1,440(Lb/MMBtu)0.240.24 0.24 0.24 0.24 0.24 0.24 0.24(Lb Moles/Hr)47.98 47.98 47.98 47.98 47.98 47.98 47.98 47.98(Tons/Yr)5,676 5,676 5,676 5,676 5,676 5,676 5,676 5,676NOx Removal Rate (%)0.0%0.0%8.3%16.7%70.8%0%0.0%0%(Lb/Hr)0 0 120 240 1,020 0 0 0(Lb Moles/Hr)0.00 0.00 4.00 8.00 33.99 0.00 0.00 0.00(Ton/Yr)0 0 473 946 4,021 0 0 0NOx Emission Rate (Lb/Hr)1,440 1,440 1,320 1,200 420 1,440 1,440 1,440(Lb/MMBtu)0.240.24 0.22 0.20 0.070.24 0.24 0.24(Ton/Yr)5,676 5,676 5,203 4,730 1,656 5,676 5,676 5,676Uncontrolled Fly Ash (Lb/Hr)51,177 444 444 444 444 444 444 444(Lb/MMBtu)8.530 0.074 0.074 0.074 0.074 0.074 0.074 0.074(Lb Moles/Hr)1,705.3 14.8 14.8 14.8 14.8 14.8 14.8 14.8(Tons/Yr)201,739 1,750 1,750 1,750 1,750 1,750 1,750 1,750Fly Ash Removal Rate (%)99.13%0.00%0.00%0.00%0.00%0.00%59.46%79.73%(Lb/Hr)50,733 0 0 0 0 0 264 354(Ton/Yr)199,988 0 0 0 0 0 1,041 1,395Fly Ash Emission Rate (Lb/Hr)444 444 444 444 444 444 180 90(Lb/MMBtu)0.0740.074 0.074 0.074 0.074 0.0740.030 0.015(Ton/Yr)1,750 1,750 1,750 1,750 1,750 1,750 710 355ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls1 of 2Exist. LNBw/OFAROFA SNCR SCRUpgraded WetFGDFlue GasConditioningFabric FilterCase1 2 3 4 5 8 9 10ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlGeneral Plant DataAnnual Operation (Hours/Year)7,884 7,884 7,884 7,884 7,884 7,884 7,884 7,884Annual On-Site Power Plant Capacity Factor0.900.90 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%Discount Rate (%)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 20Installed Capital CostsNOx Emission Control System ($2006)00 20,528,122 13,427,239 120,875,49400 0SO2 Emission Control System ($2006)00 0 0 0 12,999,900 0 0PM Emission Control System ($2006)00 0 0 0 0 0 48,386,333Total Emission Control Systems ($2006)0 0 20,528,122 13,427,239 120,875,49412,999,900 0 48,386,333NOx Emission Control System ($/kW)0 0 39 25 228 0 0 0SO2 Emission Control System ($/kW)0 0 0 0 0 25 0 0PM Emission Control System ($/kW)0 0 0 0 0 0 0 91Total Emission Control Systems ($/kW)0 0 39 25 228 25 0 91Total Fixed Operating & Maintenance CostsOperating Labor ($)00000 0 0 0Maintenance Material ($)0 0 42,000 95,000 162,000 25,550 0 51,099Maintenance Labor ($)0 0 63,000 142,500 243,000 17,033 10,000 76,649Administrative Labor ($)00000 0 0 0Total Fixed O&M Cost ($)0 0 105,000 237,500 405,000 42,583 10,000 127,749Annual Fixed O&M Cost Escalation Rate (%)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 53 0 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 30,503 0 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Soda Ash Elemental SulfurNoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 80.00 370 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.040 0.185 0.000Molar Stoichiometry0.00 0.00 0.00 0.45 1.00 1.02 0.00 0.00Reagent Purity (Wt.%)100%100%100%100%100%100%100%90%Reagent Usage (Lb/Hr)0 0 0 368 579 1,6911000First Year Reagent Cost ($)0 0 0 536,432 912,848 533,206 145,854 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000198 0 0 2,885SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000 104 3,000 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 594,000 0 0 300,040Annual SCR Catalyst / Bag Cost Esc. Rate (%)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 4,618 0 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 442,958 0 0Annual Waste Disposal Cost Esc. Rate (%)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%1.21%0.10%0.61%0.10%0.01%0.64%(MW)0.00 0.00 6.41 0.53 3.25 0.53 0.05 3.37Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 2,528,012 208,926 1,282,333 208,926 19,710 1,326,877Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.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/AUpgraded WetFGDFlue GasConditioning Fabric Filter4 Jim Bridger Unit 2Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter5 Jim Bridger Unit 3Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter6 Jim Bridger Unit 4Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter7 Naughton Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter8 Naughton Unit 2Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Dry FGD w/ESPDry FGD w/FabricFilter Wet FGD w/ESPFlue GasConditioning Fabric Filter9 Naughton Unit 3Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/AUpgraded WetFGDFlue GasConditioning Fabric Filter10 Wyodak Unit 1Current Operation LNB w/OFA ROFA LNB w/OFA & SNCRLNB w/OFA &SCR Upgraded Dry FGD N/A Wet FGDFlue GasConditioning Fabric FilterTable 2 - Unit Design and Coal CharacteristicsNOx SO2 PM Boiler DesignNet PowerOutput (kW)NetPlantHeatRate (Btu/kWHr) 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 PC173,000 10,694Kemmerer Mine9,970 0.60% 4.64%8 Naughton Unit 2None None ESP Tangential-Fired PC226,000 10,574Kemmerer Mine9,970 0.60% 4.64%9 Naughton Unit 3LNCFS II LNB Wet FGD ESP Tangential-Fired PC356,000 10,336Kemmerer Mine9,970 0.60% 4.64%10 Wyodak Unit 1LNB Dry FGD ESP Opposed Wall-Fired PC335,000 12,087Clovis Point Mine7,977 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 JB2 BART Economic Analysis_01-12-07.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 31.20 0.70 0.200 0.27 0.210.200.07 0.210.150.10N/A0.0152 Dave Johnston Unit 40.33 0.48 0.061 0.15 0.190.120.07 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 11.20 0.58 0.056 0.24 0.280.180.07 0.180.150.100.040 0.0158 Naughton Unit 21.20 0.54 0.064 0.24 0.280.180.07 0.180.150.100.040 0.0159 Naughton Unit 30.50 0.45 0.094 0.35 0.300.250.07 N/AN/A0.100.040 0.01510 Wyodak Unit 10.50 0.50 0.0300.230.220.180.070.25N/A0.100.025 0.015Table 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 Unit 1-$ -$ -$$ --None--Table 5 - Case 2 O&M Costs (LNB w/OFA)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 40,000$ 60,000$ -$ -None - -2 Dave Johnston Unit 4-$ 36,000$ 54,000$ $ - -None - -3 Jim Bridger Unit 1-$ 28,000$ 42,000$ $ - -None - -4 Jim Bridger Unit 2-$ -$ -$ $ - -None - -5 Jim Bridger Unit 3-$ 28,000$ 42,000$ $ - -None - -6 Jim Bridger Unit 4-$ 28,000$ 42,000$ $ - -None - -7 Naughton Unit 1-$ 32,000$ 48,000$ $ - -None - -8 Naughton Unit 2-$ 32,000$ 48,000$ $ - -None - -9 Naughton Unit 3-$ -$ -$ $ - -None - -10 Wyodak Unit 1-$ 24,000$ 36,000$$ --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 JB2 BART Economic Analysis_01-12-07.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 Unit 1-$ 36,000$ 54,000$$ --None-5.22Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 98,000$ 147,000$ -$ -Urea 0.41 0.232 Dave Johnston Unit 4-$ 105,000$ 157,500$ $ - -Urea 0.45 0.333 Jim Bridger Unit 1-$ 123,000$ 184,500$ $ - -Urea 0.45 0.534 Jim Bridger Unit 2-$ 95,000$ 142,500$ $ - -Urea 0.45 0.535 Jim Bridger Unit 3-$ 122,000$ 183,000$ $ - -Urea 0.45 0.526 Jim Bridger Unit 4-$ 123,000$ 184,500$ $ - -Urea 0.45 0.537 Naughton Unit 1-$ 83,000$ 124,500$ $ - -Urea 0.45 0.168 Naughton Unit 2-$ 93,000$ 139,500$ $ - -Urea 0.51 0.229 Naughton Unit 3-$ 75,000$ 112,500$ $ - -Urea 0.45 0.3310 Wyodak Unit 1-$ 93,000$ 139,500$--Urea0.450.34Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.AnnualSCRCatalystReplace. (m3)Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 155,000$ 232,500$ -$ -Anhydrous NH31.00 1281.572 Dave Johnston Unit 4-$ 166,000$ 249,000$ $ - -Anhydrous NH31.00 1232.293 Jim Bridger Unit 1-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 1983.284 Jim Bridger Unit 2-$ 162,000$ 243,000$ $ - -Anhydrous NH31.00 1983.255 Jim Bridger Unit 3-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2003.226 Jim Bridger Unit 4-$ 190,000$ 285,000$ $ - -Anhydrous NH31.00 2143.367 Naughton Unit 1-$ 132,000$ 198,000$ $ - -Anhydrous NH31.00 670.988 Naughton Unit 2-$ 160,000$ 240,000$ $ - -Anhydrous NH31.00 1011.349 Naughton Unit 3-$ 156,000$ 234,000$ $ - -Anhydrous NH31.00 1671.9910 Wyodak Unit 1-$ 181,000$ 271,500$$ --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 JB2 BART Economic Analysis_01-12-07.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 Unit 1-$ 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-$ -$ -$ $ - -Lime- --10 Wyodak Unit 1-$ -$ -$--Lime---Table 11 - Case 8 O&M Costs (Wet FGD)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3809,804$ 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 Wyodak Unit 1303,677$ 328,496$ 218,998$$ -82Lime1.02-1.75Variable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsEY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur67 -0.0510 Wyodak Unit 1-$ -$ 10,000$--Elemental Sulfur63-0.05Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak Unit 1-$ 48,666$ 72,999$$ --None-1,7982.06Table 14 - Major Materials Design and Supply Costs2 3 4 5 6 7 8 9 101 Dave Johnston Unit 3$ 3,221,912 $ 3,556,617 $ 5,773,000 $ 49,355,000 $ 83,871,000 $ 142,077,000 $ 108,865,669$ - $ 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 $ 26,819,000 $ 42,301,000 $ 44,000,000 $ 800,000 $ 15,482,0008 Naughton Unit 2$ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 39,262,000 $ 57,621,000 $ 56,000,000 $ 800,000 $ 18,359,0009 Naughton Unit 3$ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $- $ 2,963,000 $ 800,000 $ 20,106,00010 Wyodak Unit 1$ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 996,100 $ - $ 178,174,384 $ 1,247,061 $ 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 JB2 BART Economic Analysis_01-12-07.xls5 of 5CAPITAL COSTJim Bridger 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 $0Vendor $6,056,955Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$085.3%$5,168,62885.3%$085.3%$085.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$051.7%$3,130,97051.7%$051.7%$051.7%$051.7%$051.7%$051.7%$051.7%$0Electrical (Allowance)0.0%$030.0%$1,817,0870.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Owner's Costs13.2%$013.2%$802,44613.2%$013.2%$013.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$016.4%$994,88416.4%$016.4%$016.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$012.2%$740,06712.2%$012.2%$012.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal$0 $18,711,036$0 $0 $0 $0 $0 $0 $0Contingency12.8%$030.0%$1,817,08712.8%$012.8%$012.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $0 $20,528,122 $0 $0 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $9,528,000 S&L Report $80,923,000 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%$1,905,60020.0%$16,184,60020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$532,9015.6%$4,526,0235.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$6,835,5668.4%$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%$104,9991.1%$891,7711.1%$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%$267,4512.8%$2,271,5092.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$1,088,28811.4%$9,243,02511.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $13,427,239 $120,875,494 $0 $0 $0 $0 $0Dry or Wet FGD, FGC or Fabric FilterDry FGD Dry FGD w/FF Wet FGD FGC Fabric FilterMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $8,010,093 S&L Report $0 S&L Report $29,814,000Contingency20.0%$020.0%$020.0%$020.0%$020.0%$020.0%$020.0%$1,602,01920.0%$020.0%$5,962,800Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$05.6%$05.6%$448,0055.6%$05.6%$1,667,497EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$08.4%$08.4%$676,6138.4%$08.4%$2,518,389Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$02.8%$225,4042.8%$02.8%$838,966Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$01.1%$01.1%$88,2711.1%$01.1%$328,550Escalation10.1%$010.1%$010.1%$010.1%$010.1%$010.1%$010.1%$809,74010.1%$010.1%$3,013,897Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$02.8%$224,8432.8%$02.8%$836,879Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$011.4%$011.4%$914,91311.4%$011.4%$3,405,355Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 $0 $12,999,900 $0 $48,386,333Fabric Filter8LNB - TFS 2000Fabric Filter10LNB - TFS 2000Wet FGDLNB - TFS 2000Wet FGDFlue Gas ConditioningN/AN/ASNCRSO2 ControlUpgraded Wet FGDUpgraded Wet FGDESPExist. LNB w/OFAWet FGDESP ESPROFAWet FGDLNB - TFS 2000N/AParameterExist. LNB w/OFA ROFA SCRESPLNB - TFS 2000N/AESPSNCRWet FGDESP ESPSCRWet FGDPM ControlFlue Gas ConditioningNOx Control45 76293EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls1 of 1Jim Bridger Unit 2Exist. LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 ----------2 2015 ----------3 2016 ----------4 2017 ----------5 2018 ----------6 2019 ----------7 2020 ----------8 2021 ----------9 2022 ----------10 2023 ----------11 2024 ----------12 2025 ----------13 2026 ----------14 2027 ----------15 2028 ----------16 2029 ----------17 2030 ----------18 2031 ----------19 2032 ----------20 2033 ----------Present Worth----------(% of PW)0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%Jim Bridger Unit 2ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 105,000----2,528,0122,528,0121,952,7964,585,8089,6952 2015 107,100----2,578,5732,578,5731,952,7964,638,4689,8063 2016 109,242----2,630,1442,630,1441,952,7964,692,1829,9204 2017 111,427----2,682,7472,682,7471,952,7964,746,97010,0365 2018 113,655----2,736,4022,736,4021,952,7964,802,85310,1546 2019 115,928----2,791,1302,791,1301,952,7964,859,85410,2747 2020 118,247----2,846,9532,846,9531,952,7964,917,99510,3978 2021 120,612----2,903,8922,903,8921,952,7964,977,29910,5239 2022 123,024----2,961,9702,961,9701,952,7965,037,78910,65110 2023 125,485----3,021,2093,021,2091,952,7965,099,48910,78111 2024 127,994----3,081,6333,081,6331,952,7965,162,42310,91412 2025 130,554----3,143,2663,143,2661,952,7965,226,61611,05013 2026 133,165----3,206,1313,206,1311,952,7965,292,09211,18814 2027 135,829----3,270,2543,270,2541,952,7965,358,87811,32915 2028 138,545----3,335,6593,335,6591,952,7965,427,00011,47316 2029 141,316----3,402,3723,402,3721,952,7965,496,48411,62017 2030 144,142----3,470,4193,470,4191,952,7965,567,35811,77018 2031 147,025----3,539,8283,539,8281,952,7965,639,64911,92319 2032 149,966----3,610,6243,610,6241,952,7965,713,38612,07920 2033 152,965----3,682,8373,682,8371,952,7965,788,59812,238Present Worth1,282,875----30,886,88630,886,88620,528,12252,697,8835,571(% of PW)2.4% 0.0% 0.0% 0.0% 0.0% 58.6% 58.6% 39.0% 100.0%EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls1 of 4Jim Bridger Unit 2SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 237,500-536,432--208,926745,3581,277,3042,260,1622,3892 2015 242,250-547,161--213,105760,2661,277,3042,279,8202,4103 2016 247,095-558,104--217,367775,4711,277,3042,299,8702,4314 2017 252,037-569,266--221,714790,9801,277,3042,320,3212,4535 2018 257,078-580,652--226,148806,8001,277,3042,341,1822,4756 2019 262,219-592,265--230,671822,9361,277,3042,362,4592,4977 2020 267,464-604,110--235,285839,3951,277,3042,384,1622,5208 2021 272,813-616,192--239,990856,1831,277,3042,406,2992,5449 2022 278,269-628,516--244,790873,3061,277,3042,428,8792,56710 2023 283,834-641,086--249,686890,7721,277,3042,451,9112,59211 2024 289,511-653,908--254,680908,5881,277,3042,475,4032,61712 2025 295,301-666,986--259,773926,7601,277,3042,499,3652,64213 2026 301,207-680,326--264,969945,2951,277,3042,523,8062,66814 2027 307,232-693,933--270,268964,2011,277,3042,548,7362,69415 2028 313,376-707,811--275,673983,4851,277,3042,574,1652,72116 2029 319,644-721,967--281,1871,003,1541,277,3042,600,1022,74817 2030 326,037-736,407--286,8111,023,2171,277,3042,626,5582,77618 2031 332,557-751,135--292,5471,043,6821,277,3042,653,5432,80519 2032 339,208-766,158--298,3981,064,5551,277,3042,681,0682,83420 2033 345,993-781,481--304,3661,085,8471,277,3042,709,1432,864Present Worth2,901,740-6,554,053--2,552,6279,106,68013,427,23925,435,6591,344(% of PW)11.4% 0.0% 25.8% 0.0% 0.0% 10.0% 35.8% 52.8% 100.0%Jim Bridger Unit 2SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 405,000-912,848594,000-1,282,3332,789,18111,498,62314,692,8033,6542 2015 413,100-931,105605,880-1,307,9792,844,96411,498,62314,756,6873,6703 2016 421,362-949,727617,998-1,334,1392,901,86411,498,62314,821,8483,6874 2017 429,789-968,722630,358-1,360,8222,959,90111,498,62314,888,3133,7035 2018 438,385-988,096642,965-1,388,0383,019,09911,498,62314,956,1063,7206 2019 447,153-1,007,858655,824-1,415,7993,079,48111,498,62315,025,2563,7377 2020 456,096-1,028,015668,940-1,444,1153,141,07011,498,62315,095,7893,7558 2021 465,218-1,048,575682,319-1,472,9973,203,89211,498,62315,167,7323,7739 2022 474,522-1,069,547695,966-1,502,4573,267,97011,498,62315,241,1143,79110 2023 484,012-1,090,938709,885-1,532,5063,333,32911,498,62315,315,9643,80911 2024 493,693-1,112,757724,083-1,563,1563,399,99611,498,62315,392,3113,82812 2025 503,567-1,135,012738,564-1,594,4193,467,99611,498,62315,470,1853,84813 2026 513,638-1,157,712753,336-1,626,3083,537,35511,498,62315,549,6163,86814 2027 523,911-1,180,866768,402-1,658,8343,608,10311,498,62315,630,6363,88815 2028 534,389-1,204,484783,770-1,692,0113,680,26511,498,62315,713,2763,90816 2029 545,077-1,228,573799,446-1,725,8513,753,87011,498,62315,797,5693,92917 2030 555,978-1,253,145815,435-1,760,3683,828,94711,498,62315,883,5483,95118 2031 567,098-1,278,208831,743-1,795,5753,905,52611,498,62315,971,2473,97219 2032 578,440-1,303,772848,378-1,831,4873,983,63711,498,62316,060,6993,99520 2033 590,009-1,329,847865,346-1,868,1164,063,30911,498,62316,151,9414,017Present Worth4,948,231-11,153,0437,257,405-15,667,35234,077,800120,875,494159,901,5241,989(% of PW)3.1% 0.0% 7.0% 4.5% 0.0% 9.8% 21.3% 75.6% 100.0%EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls2 of 4Jim Bridger Unit 2Upgraded Wet FGDYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 42,58330,503533,206-442,958208,9261,215,5931,236,6522,494,8286322 2015 43,43531,113543,870-451,818213,1051,239,9051,236,6522,519,9916383 2016 44,30331,735554,747-460,854217,3671,264,7031,236,6522,545,6586454 2017 45,18932,370565,842-470,071221,7141,289,9971,236,6522,571,8386515 2018 46,09333,017577,159-479,472226,1481,315,7971,236,6522,598,5426586 2019 47,01533,678588,702-489,062230,6711,342,1131,236,6522,625,7806657 2020 47,95534,351600,476-498,843235,2851,368,9551,236,6522,653,5626728 2021 48,91435,038612,486-508,820239,9901,396,3341,236,6522,681,9016799 2022 49,89335,739624,735-518,996244,7901,424,2611,236,6522,710,80668610 2023 50,89036,454637,230-529,376249,6861,452,7461,236,6522,740,28969411 2024 51,90837,183649,975-539,964254,6801,481,8011,236,6522,770,36170112 2025 52,94637,926662,974-550,763259,7731,511,4371,236,6522,801,03670913 2026 54,00538,685676,234-561,778264,9691,541,6661,236,6522,832,32371714 2027 55,08539,459689,758-573,014270,2681,572,4991,236,6522,864,23772515 2028 56,18740,248703,554-584,474275,6731,603,9491,236,6522,896,78873316 2029 57,31141,053717,625-596,164281,1871,636,0281,236,6522,929,99174217 2030 58,45741,874731,977-608,087286,8111,668,7491,236,6522,963,85875018 2031 59,62642,711746,617-620,249292,5471,702,1231,236,6522,998,40275919 2032 60,81943,566761,549-632,654298,3981,736,1661,236,6523,033,63776820 2033 62,03544,437776,780-645,307304,3661,770,8891,236,6523,069,577777Present Worth520,271372,6796,514,628-5,412,0002,552,62714,851,93512,999,90028,372,107359(% of PW)1.8% 1.3% 23.0% 0.0% 19.1% 9.0% 52.3% 45.8% 100.0%Jim Bridger Unit 2Flue Gas ConditioningYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 10,000-145,854--19,710165,564-175,5641692 2015 10,200-148,771--20,104168,875-179,0751723 2016 10,404-151,747--20,506172,253-182,6571764 2017 10,612-154,781--20,916175,698-186,3101795 2018 10,824-157,877--21,335179,212-190,0361836 2019 11,041-161,035--21,761182,796-193,8371867 2020 11,262-164,255--22,197186,452-197,7141908 2021 11,487-167,540--22,641190,181-201,6681949 2022 11,717-170,891--23,093193,985-205,70119810 2023 11,951-174,309--23,555197,864-209,81520211 2024 12,190-177,795--24,026201,822-214,01220612 2025 12,434-181,351--24,507205,858-218,29221013 2026 12,682-184,978--24,997209,975-222,65821414 2027 12,936-188,678--25,497214,175-227,11121815 2028 13,195-192,451--26,007218,458-231,65322316 2029 13,459-196,300--26,527222,827-236,28622717 2030 13,728-200,226--27,058227,284-241,01223218 2031 14,002-204,231--27,599231,830-245,83223619 2032 14,282-208,315--28,151236,466-250,74924120 2033 14,568-212,482--28,714241,195-255,764246Present Worth122,179-1,782,023--240,8142,022,837-2,145,015103(% of PW)5.7% 0.0% 83.1% 0.0% 0.0% 11.2% 94.3% 0.0% 100.0%EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls3 of 4Jim Bridger Unit 2Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 127,749--300,040-1,326,8771,626,9174,602,8876,357,5524,5562 2015 130,304--306,041-1,353,4151,659,4564,602,8876,392,6464,5813 2016 132,910--312,162-1,380,4831,692,6454,602,8876,428,4414,6074 2017 135,568--318,405-1,408,0931,726,4984,602,8876,464,9524,6335 2018 138,279--324,773-1,436,2551,761,0274,602,8876,502,1934,6606 2019 141,045--331,268-1,464,9801,796,2484,602,8876,540,1794,6877 2020 143,866--337,894-1,494,2791,832,1734,602,8876,578,9254,7158 2021 146,743--344,652-1,524,1651,868,8164,602,8876,618,4464,7439 2022 149,678--351,545-1,554,6481,906,1934,602,8876,658,7574,77210 2023 152,671--358,576-1,585,7411,944,3174,602,8876,699,8754,80111 2024 155,725--365,747-1,617,4561,983,2034,602,8876,741,8144,83212 2025 158,839--373,062-1,649,8052,022,8674,602,8876,784,5934,86213 2026 162,016--380,523-1,682,8012,063,3244,602,8876,828,2274,89314 2027 165,256--388,134-1,716,4572,104,5914,602,8876,872,7344,92515 2028 168,562--395,896-1,750,7862,146,6834,602,8876,918,1314,95816 2029 171,933--403,814-1,785,8022,189,6164,602,8876,964,4364,99117 2030 175,371--411,891-1,821,5182,233,4094,602,8877,011,6675,02518 2031 178,879--420,128-1,857,9482,278,0774,602,8877,059,8425,05919 2032 182,456--428,531-1,895,1072,323,6384,602,8877,108,9815,09520 2033 186,106--437,102-1,933,0102,370,1114,602,8877,159,1035,131Present Worth1,560,813--3,665,845-16,211,59119,877,43648,386,33369,824,5822,502(% of PW)2.2% 0.0% 0.0% 5.3% 0.0% 23.2% 28.5% 69.3% 100.0%EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls4 of 4EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls 1 of 1First Year Cost for Air Pollution Control Options02,000,0004,000,0006,000,0008,000,00010,000,00012,000,00014,000,00016,000,000Exist. LNB w/OFA ROFA SNCR SCR Upgraded WetFGDFlue GasConditioningFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\App A_PCorp JB2 BART Economic Analysis_01-12-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options020,000,00040,000,00060,000,00080,000,000100,000,000120,000,000140,000,000160,000,000180,000,000Exist. LNB w/OFA ROFA SNCR SCR Upgraded WetFGDFlue GasConditioningFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B 

# 2006 Wyoming BART Protocol