# Final Report



# BART Analysis for

Jim Bridger Unit 3

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Jim Bridger Unit 3

Submitted to



# PacifiCorp

December 2007

# Executive Summary

Background

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

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

PacifiCorp’s Jim Bridger Unit 3 (hereafter refe rred to as Jim Bridger 3). Best Available

Retrofit Technology analysis has been conducted fo r the following criteria pollutants: nitrogen

oxide (NO

x 

# ), sulfur dioxide (SO 2 

# ), and particulate matter less than 10 micrometers in

aerodynamic diameter (PM 10 

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

units with a total generating capacity of 2,120 MW. Because the total generating capacity of

the Jim Bridger Station exceeds 750 MW, pres umptive BART emission limits apply to

Jim Bridger 3, based on the United States Environmental Protection Agency’s (EPA)

guidelines. BART emissions limits must be achieved within five years after the State

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

for this analysis.

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

reductions in NO

x 

# , SO 2 

# , and PM 10 

# emissions rates were identified. The following technology

alternatives were investigat ed, listed below by pollutant:

• NO

x 

# emission controls:

− Low-NO

x 

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

− Rotating opposed fire air (ROFA)

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

− LNB with selective catalytic reduction (SCR) system

• SO 2 

# emission controls:

− Optimize current operation of existing wet sodium flue gas desulfurization (FGD)

system

− Upgrade wet sodium FGD system to achieve an SO 2 

# emission rate of 0.10 lb 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_JB3_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 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 equipm ent in use at the source (which affects

the applicability of optio ns and their impacts)

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

• Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

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

• Step 5 – Evaluate Visibility Impacts

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

of BART

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included

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

2014 BART implementation date.



# Coal Characteristics

The main source of coal burned at Jim Bri dger 3 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

characteristics to bituminous coal in many of the parameters influencing NO

x 

# formation.

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



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

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

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

qualities on NO

x 

# formation and achievable emission rates.



# Recommendations

CH2M HILL recommends these BART sel ections, which include installing low NO

x 

# burners

with over-fire air, upgrading the existing FGD sy stem, and operating the existing electrostatic

precipitator with an SO 3 

# flue gas conditioning system. 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 tange ntially-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 coals are more closely aligned with bituminous coals, with

a presumptive BART NO

x 

# limit of 0.28 lb per MMBtu.

CH2M HILL recommends low-NO

x 

# burners with over-fire air (L NB with OFA) as BART for

Jim Bridger 3, 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 are expected to be similar to those realized at

Jim Bridger 2. CH2M HILL recommends that th e unit be permitted at a rate 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 3, 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 permitti ng of the flue gas conditioning system to

enhance the performance of the existing ESP as BART for Jim Bridger 3, based on the

significant reduction in PM 10 

# emissions, reasonable control co sts, and the advantages of

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



# BART Modeling Analysis

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

emissions from Jim Bridger 3 at Class I areas. The Class I areas potentially affected are

located more than 50 kilometers, but less than 300 kilometers, from the Jim Bridger Plant.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



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

• 

# Bridger WA

• 

# Fitzpatrick WA

• 

# Mt. Zirkel WA

Because Jim Bridger 3 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four

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

effectiveness for combining the individual NO

x 

# , SO 2 

# , and PM 10 

# control technologies under

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

• 

# Scenario 1 : New LNB with OFA modi fications, upgraded wet FGD system, and flue gas

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

represents CH2M HILL HILL’s pr eliminary BART recommendation.

• 

# Scenario 2 : New LNB with OFA modifications, upgraded wet FGD system, and new

polishing fabric filter.

• 

# Scenario 3 : New LNB with OFA modifications a nd SCR, upgraded wet FGD system,

and flue gas conditioning for enhanced ESP performance.

• 

# Scenario 4 : New LNB with OFA modifications a nd SCR, upgraded wet FGD system,

and new polishing fabric filter.

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

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

Workshop Manual. 1



# Least-cost Envelope Analysis

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

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

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

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

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

for total emissions reductions fo r all control alternatives iden tified 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 provid es a comparison of the average incremental

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

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

# percentile deltadeciview ( 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, b ecause it is to the left of the curve formed by

the dominant control alternat ive scenario, which indicates a scenario with lower

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-5 

# improvement and/or higher costs. Scenario 3 (LNB with OFA and SCR, upgraded wet FGD,

and flue gas conditioning for e nhanced ESP performance) is not selected due to very high

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

reduction. While Scenario 4 (LNB with OFA and SCR, upgraded wet FGD, and polishing

fabric filter) provides some pot ential visibility advantage ove r Scenario 1, the projected

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

Scenario 1 represents BART for Jim Bridger 3.



# Just-Noticeable Differences in Atmospheric Haze

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

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

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

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

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

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

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

entire fleet of coal-fired power plants.

# Contents

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

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

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

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

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

3.2.1 BART NO

x 

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

3.2.2 BART SO 2 

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

3.2.3 BART PM 10 

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

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

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

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

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

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

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 ...................................................................... 5-9

5.2 Recommendations .................................................................................. 5-9

5.2.1 NO

x 

# Emission Control ............................................................. 5-9

5.2.2 SO 2 

# Emission Control ............................................................. 5-9

5.2.3 PM 10 

# Emission Control ........................................................... 5-9

5.3 Just-Noticeable Differences in Atmospheric Haze .............................. 5-10

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

P:\PACIFICORP\348295BART\DAVEJOHNSTON3_FINALSUBMITTAL\BART_JB3_OCT2007_FINAL.DOC iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_JB3_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 FGD System)

3-6 PM 10 

# Control Technology Emission Rates

3-7 PM 10 

# Control Cost Comparison (Incremental to Existing ESP)

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 Ba seline 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 1 Wilderness Area

5-3 Control Scenario Results for the Mt. Zirkel Class 1 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 Va rious Coals and Applicable Presumptive

BART NO

x 

# Limits

3-3 Plot of Typical Oxygen Content of Vari ous Coals and Applicable Presumptive

BART NO

x 

# Limits

3-4 First Year Control Cost for NO

x 

# Air Pollution Control Options

3-5 First Year Control Cost for PM Air Pollution Control Options

4-1 Jim Bridger Source-Specific Cl ass I Areas to be Addressed

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

5-1 Least-cost Envelope Bridge r Class I WA Days Reduction

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

# Percentile Reduction

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

5-4 Least-cost Envelope Fi tzpatrick Class I WA 98 th 

# Percentile Reduction

5-5 Least-cost Envelope Mt. Zirk el Class I WA Days Reduction

5-6 Least-cost Envelope Mt. Zirkel Class I WA 98 th 

# Percentile Reduction

Appendices

A Economic Analysis

B 2006 Wyoming BART Protocol

# Acronyms and Abbreviations

°F Degree Fahrenheit

BACT Best Availa ble Control Technology

BART Best Availabl e Retrofit Technology

CALDESK Program to Display Data and Results

CALMET Meteorological Data Pr eprocessing Program for CALPUFF

CALPOST Post-processing Program fo r Calculating Visibility Impacts

CALPUFF Gaussian Puff Dispersion Model

COHPAC Compact Hybrid Particulate Collector

dV Deciview

Δ dV Delta Deciview, Change in Deciview

DEQ Department of Environmental Quality

ESP Electrostatic Precipitator

EPA United States Environmental Protection Agency

FGC Flue Gas Conditioning

FGD Flue Gas Desulfurization

kW Kilowatt

kW-Hr Kilowatt-hour

LNB Low-NO

x 

# Burner

lb Pound

MMBtu Million British Thermal Units

MM5 Mesoscale Meteorologi cal Model, Version 5

MW Megawatts

NO

x 

# Nitrogen Oxides

OFA Over Fire Air

PM Particulate Matter

PM 2.5 

# Particulate Matter less than 2.5 Mi crometers in Aerodynamic Diameter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Sargent & Lundy

SCR Selective Catalytic Reduction

SIP State Implementation Plan

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC vi 

# SNCR Selective Non-catalytic Reduction

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

USGS U.S. Geological Survey

WA Wilderness Area

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

# 1.0 Introduction

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

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

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

the United States (40 CFR Part 51). These gui delines provide guidance for states when

determining which facilities must install additi onal controls, and the t ype of controls that

must be used. Facilities eligible for BA RT installation were built between 1962 and 1977,

and have the potential to emit more than 250 tons per year of visibili ty-impairing pollutants.

The Wyoming Department of Environmental Qu ality (DEQ) BART regulations state that

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

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

BART report for Jim Bridger Unit 3 (hereafter referred to as Jim Bridger 3) by January 12,

2007. The BART Report that was submitted to WDEQ in January 2007 included a BART

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

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

January 2007 version.

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

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

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

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

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

5 years of EPA’s approval of the SIP.

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 may reasonably be anticipated from the use

of such technology

This report documents the BART analysis that was performed on Jim Bridger 3 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 Analysis is provided

in Section 3, by pollutant type. Section 4 provides the met hodology and results of the BART

Modeling Analysis, followed by recommendations in Section 5. References are provided in

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

BART Protocol.

JMS EY102007001SLC\BART_JB3_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 3 is a nominal 530 net MW unit located approximately

35 miles northeast of Rock Springs, Wyoming. It is equipped with a tangentially fired

pulverized coal boiler with low NO

x 

# burners manufactured by Combustion Engineering. The

unit was constructed with a Flakt wire frame electrostatic precipitator (ESP). The unit

contains a Babcock & Wilcox wet sodium flue gas desulfurization (FGD) system with three

absorber towers installed in 1988. An Emerson Ovation distributed control system (DCS)

was installed in 2003.

Jim Bridger 3 was placed in service in 1976. 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 3 of 20 years from the installation date of any new or modified

BART-related equipment. This report does not attempt to quantify any additional life

extension costs needed to allow the unit and thes e control devices at Ji m Bridger 3 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 tangential-fired boilers burning sub-bituminous coal is

0.15 lb per MMBtu and the BART presumptive NO

x 

# limit for burning bituminous coal is

0.28 lb per MMBtu. The main sources of coal bu rned at Jim Bridger 3 are the Bridger Mine

and secondarily the Black Butte Mine and Le ucite Hills Mine. These coals are ranked as

sub-bituminous, but are closer in characteristics to bituminous coal in many of the parameters

influencing NO

x 

# formation. These coals have higher nitrogen content than coals from the

Powder River Basin (PRB), which represent the bulk of sub-bituminous coal use in the U.S.

This BART analysis has considered the highe r nitrogen content and the different combustion

characteristics of PRB coals, as compared to those coals used at Jim Bridger 3, and has

evaluated the effect of these qualities on NO

x 

# formation and achievable emission rates. Coal

sources and characteristics are summarized in Table 2-2. The primary source of coal will be

the Bridger Underground Mine, a nd data on coal from this source were used in the modeling

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_JB3_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 2-2



# TABLE 2-1



# Unit Operation and Study Assumptions

Jim Bridger 3

General Plant Data

Site Elevation feet above MSL 6669

Stack Height (feet) 500

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

Stack Exit Temperature (degrees Fahrenheit) 140

Stack Exit Velocity (feet per second) 84.04

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

Latitude (degree: minute: second) 41:44:18.54 north

Longitude (degree: minute: se cond) 108:47:12.82 west

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 530

Net Unit Heat Rate (British thermal unit [Btu]/kilowatthour)(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 per MMBtu) 0.45

Current Sulfur Dioxide (SO 2 

# ) Controls Sodium based wet scrubber

SO 2 

# Emission Rate (lb per MMBtu) 0.267

Current PM 10 

# Controls Electrostatic Precipitator

PM 10 (c) 

# Emission Rate (lb per MMBtu) (b) 

# 0.057

NOTES:

(a) 

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

(b) 

# Based on maximum historic emission rate fr om 1999-2001, prior to installation of the SO 3 

# injection

system.

(c) 

# PM 10 

# refers to particulate matter less than 10 micrometers in aerodynamic diameterBART ANALYSIS FOR JIM BRIDGER UNIT 3TABLE 2-2Coal Sources and CharacteristicsJim Bridger 3Ultimate Analysis (% dry basis)MinesMoisture(%)Ash (%)VolatileMatter(%)FixedCarbon(%)Britishthermalunits perpound(Btu/lb)Sulfur(%)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 ButteMine20.09.233.335.694500.45133304.4368.70.561.4713.411.5Maximum21.110.835.441.9102750.62135004.6670.50.781.6914.813.6Minimum18.07.629.936.891800.33131404.2166.10.411.2511.69.7Leucite 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_JB3_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 environm ental impacts of compliance, and

• 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_JB3_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# • Step 5 – Evaluate Visibility Impacts

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

of BART

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

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

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

implementation date).



# 3.2.1 BART NO

x 

# Analysis

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

number of variables, including 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 nitrog en. During combustion, pa rt of the fuel-bound

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

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

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

smaller part of NO

x 

# formation is due to high temperature fixation of atmospheric nitrogen in

the combustion air. A very small amount of NO

x 

# is called “prompt” NO

x 

# . Prompt NO

x 

# results

from an interaction of hydrocar bon radicals, nitrogen, and oxygen.

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

mixing of fuel and air, 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 rele ase more organically bound nitrogen

earlier in the combustion process than do highe r rank bituminous coals. When used with lowNO

x 

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

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

x 

# emissions.

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

low NO

x 

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

Information Administration, PRB coals curren tly represent 88 percent of total U.S.

sub-bituminous production and 73 percent of we stern coal production (Energy Information

Administration, 2006). Most references to “weste rn” coal and sub-bituminous coal infer PRB

origin and characteristics. Em issions standards differentiating between bituminous and subJMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# bituminous coals are presumed to use PRB coal as the basis for the sub-bituminous standards,

due to its dominant market pres ence and unique characteristics.

There are a number of western co als that are classified as su b-bituminous, however, they border

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

most of the low NO

x 

# forming characteristics. Coals from 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 3 as sub-bituminous rather than

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

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

400°C in a non-oxidizing atmosphere, and then ap pearing as a coherent mass after cooling to

room temperature.” Because the agglomerating property of coals is th e result of particles

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

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

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

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

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

property assists in making sub-bituminous coals more amenable to controlling NO

x 

# by allowing

less air to be introduced during the initial igniti on 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 non-agglomerating, they

either do not exhibit those prope rties of non-agglomerating coals or exhibit them to only a

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

it easier to control NO

x 

# emissions do not exist for the Bridger blends of coals.

FIGURE 3-1



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

Jim Bridger 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



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

Mine, Black Butte, and Leucite Hills, as well as Twentymile, which is a representative western

bituminous coal.

TABLE 3-1



# Coal Characteristics Comparison

Jim Bridger 3

Parameter Typical

Powder

River

Basin Bridger

Mine Black

Butte Leucite

Hills Twentymile

Nitrogen (percentage dry) 1.10 1.26 1.47 1.48 1.85

Oxygen (percentage dry) 16.2 13.2 13.4 13.2 7.19

Coal rank Sub C Sub B Sub B Sub B Bituminous high

volatility B



# As shown in Table 3-1, although Bridger, Black Butte, and Leucite Hills 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 they are also more conducive to

reduction of NO

x 

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

x 

# burners and over-fire air (O FA). 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 quality characteristics that

fall between a typical PRB coal and Twentymile. Twentymile is a clearly bituminous coal that

produces higher NO

x 

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

Figures 3-2 and 3-3 graphically i llustrate the relationship of ni trogen 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 ty pical bituminous and sub-bituminous coal, and

demonstrates how the Jim Bridger coal falls be tween these two general coal classifications.

The Bridger blend data point represents a comb ination of coals from the Bridger Mine, Black

Butte, and Leucite Hills that has been used at Jim Bridger 3, and i ndicates the average NO

x 

# emission rate achieved during the years 2003-2005. Th e Jim Bridger 2 data point consists of the

same blend of coals as Jim Bridger 3, and represents the NO

x 

# emission rate achieved after

installation of Alstom’s current state-of-the-art TFS2000 LNB and OFA system. The long-term

sustainable emission rate for this system is exp ected to be 0.24 lb per MMBtu. All four units at

Jim Bridger consist of identical boilers; while there may be some differences in performance

among them, installation of the TFS2000 firing syst em at Jim Bridger 3 would likely result in

performance and NO

x 

# emission rates comparable to those at Jim Bridger 2.

Figures 3-2 and 3-3 both demons trate that for the Jim Bridger units—with the TFS2000 low

NO

x 

# emission system installed, and burning a comb ination of the Bridger, Black Butte, and

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# Leucite Hill coals—the likely NO

x 

# emission rate will be closer to the bituminous end (0.28) 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 coal. All of these factors are consistent with the

observed sustainable rate of 0.24 lb per MMBtu.

FIGURE 3-2



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

x 

# Limits

Jim Bridger 3

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



# JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# FIGURE 3-3



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

x 

# Limits

Jim Bridger 3

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



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

auxiliary equipment. Minor changes in qual ity can sometimes be accommodated through

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

variations in quality or assump tions of “average” quality for performance projections can be

problematic. This is particularly troublesome when dealing with perfor mance issues that are

very sensitive to both co al quality and combustion conditions, such as NO

x 

# formation. There is

significant variability in the quality of coals burned at Jim Bridger 3. In addition to burning

coal from Black Butte and Leucite Hills, Jim Br idger 3 burns coal supplied from the Bridger

Mine consisting of three sources: underground, su rface, and highwall operat ions. Each of these

coal sources has different quality characteristics , as well as inherent variability in composition

of the 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 take n into consideration wh en 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.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# Jim Bridger 3 is located at an altitude of 6,669 feet above sea level. Atmospheric pressure is

lower at this elevation, 11.5 pounds per square in ch, as compared with sea level pressure of

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

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

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

flows and distribution to reduce NO

x 

# emissions using LNB and OF A, original boiler design

restrictions again limit the modifications that can be made while sti ll achieving 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 Hardgrove Grindability Index of the coal. Finer coal

particles promote release of vol atiles and assist char burnout due to more surface area being

exposed to air. NO

x 

# reduction with high volatile coals is improved with 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 3, 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 grinding surfaces 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 3, 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 3 is further described below.

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 3, 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 3 are currently controlled through the use of good combustion

practices and OFA.

The following potential NO

x 

# control technology options were considered:

• New/modified LNBs with advanced OFA

• Rotating Opposed Fire Air (ROFA)

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

• Selective catalytic reduction (SCR) system

Step 2: Eliminate Technically Infeasible Options

For Jim Bridger 3, a tangential-fired configur ation burning sub-bituminous coal, technical

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

ability to achieve the regul atory presumptive limit (used as a guide) of 0.28 lb NO

x 

# per MMBtu.

Jim Bridger 3 has an uncontrolled NO

x 

# emission rate of 0.45 lb per MMBtu.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



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

the Multi-Pollutant Control Report (Sargent and Lundy, 2002, hereaf ter referred to as the S&L

Study). Updated cost estimates for SCR a nd SNCR were used (Sargent & Lundy, 2006).

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

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

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

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

it reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 40 to 60 percent have been

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

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

problematic.

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

with projected NO

x 

# emission rates. All technologies can meet the applicable presumptive

BART limit of 0.28 lb per MMBtu.

TABLE 3-2



# NO

x 

# Control Technology Projected Emission Rates

Jim Bridger 3

Technology Projected Emission Rate (pounds per

million British thermal units)

Presumptive Best Available

Retrofit Technology (BART) Limit 0.28

Low-NO

x 

# burners (LNBs) with

over-fire air (OFA) 0.24

Rotating Opposed Fire Air 0.22

LNB with OFA and Selective

Non-catalytic Reduction (SNCR) 0.20

LNB with OFA and Selective

Catalytic Reduction (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 uncerta inties. These proposals are usua lly prepared in a limited time

frame, may be based on incomplete informati on, may contain over-optimistic conclusions, and

are non-binding. Therefore, emissi on rate values obtained in su ch preliminary proposals must

be qualified, and it must be recognized that co ntractual guarantees are established only after

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

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

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

x 

# with LNBs is to stage the

combustion process and provide a fuel rich condi tion initially; this is so oxygen needed for

combustion is not diverted to combine with nitrogen and form NO

x 

# . Fuel-rich conditions favor

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# the conversion of fuel nitroge n to nitrogen instead of NO

x 

# . Additional air (or OFA) is then

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

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

LNB retrofits to units configured with tangentia l-firing such as Jim Bridger 3, it is generally

necessary to increase the burner spacing; this pr events interaction of the flames from adjacent

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

waterwall tube replacement.

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

boiler vendors—indicates that a ne w LNB and OFA retrofit at Jim Bridger 3 would result in an

expected NO

x 

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

corresponds to a vendor guarantee, not a vendor pr ediction, and they believe that this emission

rate can be sustained as an average between overhauls. This emissi on rate represents a

significant reduction from the current NO

x 

# emission rate, and is be low the more applicable

presumptive NO

x 

# emission rate of 0.28 lb per MMBtu.

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

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

asymmetrically placed air nozzles. Rotation is re ported to prevent laminar flow, so that the

entire volume of the furnace can be used more effectively for the combustion process. In

addition, the swirling action reduces the maximum te mperature of the flames and increases heat

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

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

would propose two 4,000 to 4,300 horsepower fans for Jim Bridger 3.

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 they believe that the Owner can more

cost effectively contract for these servi ces. However, they would provide one onsite

construction supervisor duri ng installation and startup.

Selective Non-catalytic Reduction. With SNCR—a process generally utilized to achieve modest

NO

x 

# reductions on smaller units—an amine-base d reagent such as ammonia, or more

commonly urea, is injected into the furnace wi thin a temperature range of 1,600°F to 2,100°F,

where it reduces NO

x 

# to nitrogen and water. NO

x 

# reductions of up to 60 percent have been

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

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

x 

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

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

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 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 reag ent consumption. To redu ce reagent costs, S&L

has assumed that combustion modifications incl uding LNBs and 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.

Selective Catalytic Reduction. While working on the same chemical principle as SNCR, 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°F to 750°F. Due to the catalyst, the SCR process is more

efficient than SNCR and results in lower NO

x 

# emissions. The most common type of SCR is the

high-dust configuration, where th e catalyst is located downstream from the boiler economizer

and upstream of the air heater a nd any particulate control equipmen t. . In this location, the SCR

is exposed to the full concentra tion of fly ash in the flue gas that is leaving the boiler. The

high-dust configuration is assume d for Jim Bridger 3. In a full-scale SCR, the flue ducts are

routed to a separate large reac tor containing the catalyst. With in-duct SCR, the catalyst is

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

flue gas flow velocity and incr ease flue gas residence time. Due to the higher removal rate, a

full-scale SCR was used as the basis for analysis at Jim Bridger 3.

S&L prepared the design conditions and cost estimates for SCR at Jim Bridger 3. As with

SNCR, it is generally more cost effective to reduce NO

x 

# emission levels as much as possible

through combustion modifications, in order to mi nimize the catalyst surface area and ammonia

requirements of the SCR. The S&L design basi s for LNB with OFA and SCR results in a

projected NO

x 

# emission rate of 0.07 lb per MMBtu. Add itional catalyst surface was included in

the SCR design to accommodate the characteris tics of the coal used at Jim Bridger 3.

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 slagging, burner equipment condition, coal mill fineness,

and so forth.

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

follows:

• Establish expected NO

x 

# emissions value from vendor.

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR JIM BRIDGER UNIT 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 are.

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

x 

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

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

Step 4: Evaluate Impacts and Document the Results

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

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

considered during the evaluation.

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

expected to significantly impact the boiler e fficiency or forced draft fan power usage.

Therefore, these technologies will not have energy impacts.

The Mobotec ROFA system would require installation and operation of two 4,000 to

4,300 horsepower ROFA fans (6,410 kW tota l). The SNCR system would require

approximately 520 kW of additional power.

Selective catalytic reduction re trofit impacts the existing flue gas fan systems, due to the

additional pressure drop associated with the catal yst, which is typically a 6- to 8-inch water

gage increase. Total additional power requireme nts for SCR installation at Jim Bridger 3 are

estimated at approximately 3,220 kW, based on the S&L Study.

Environmental Impacts. Mobotec has predicted that carbon monoxide emissions, and unburned

carbon in the ash, commonly referred to as loss on ignition, would be the same or lower than

prior levels for the ROFA system.

The installation of SNCR or SCR systems could impact the saleability and disposal of fly ash

due to ammonia levels, and could potentially cr eate a visible stack plume, which may negate

other visibility improvements. Other environm ental impacts involve the storage of ammonia

(especially if anhydrous ammonia is used), and the 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_JB3_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-12 

# TABLE 3-3



# NO

x 

# Control Cost Comparison

Jim Bridger 3

Factor Low-NO

x 

# Burners

(LNBs) with

Over-fire Air

(OFA) Mobotec

Rotating

Opposed Fire

Air (ROFA) LNB with

OFA and

Selective

NonCatalytic

Reduction

(SNCR) LNB with OFA

and Selective

Catalytic

Reduction

(SCR)

Total Installed Capital Costs $8.7 million $20.5 million 22.0 million $129.6 million

Total First Year Fixed and Variable

Operation and Maintenance Costs $0.1 million $2.6 million $1.5 million $3.3 million

Total First Year Annualized Cost $0.9 million $4.6 million $3.6 million $15.6 million

Power Consumption (megawatts [MW]) 0 6.4 0.5 3.3

Annual Power Usage

(million MW-hours per year) 0 50.6 4.1 25.4

NO

x 

# Design Control Efficiency 46.7% 51.1% 55.6% 84.4%

NO

x 

# Removed per Year (T ons) 4,967 5,440 5,913 8,987

Nitrogen Oxide (NO

x 

# ) Design Control

Efficiency $181/ton $843/ton $610/ton $1,734/ton

Incremental Control Cost

(dollars per ton [$/ton] of NO

x

# Removed) $181/ton $7,797/ton $2, 863/ton $3,896/ton



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

for Jim Bridger 3 based on its significant reduction in NO

x 

# emissions, reasonable control cost,

and no additional power requirements or environmental impacts. Low-NO

x 

# burners with OFA

does not meet the EPA presumptive limit of 0.15 lb per MMBtu for sub-bituminous coal, but it

does meet 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 MMBt u for sub-bituminous coal. As discussed in

the section on coal quality, the recommended technology and the achieved emission rate are

deemed appropriate as BART for NO

x 

# emissions from the coals combusted at Jim Bridger 3.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR JIM BRIDGER UNIT 3FIGURE 3-4First Year Control Cost for NOxAir Pollution Control OptionsJim Bridger 301,0002,0003,0004,0005,0006,0007,0008,0009,000LNB w/OFAROFALNB w/OFA & SNCRLNB w/OFA & SCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 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 3 is described below.

Step 1: Identify All Availabl e Retrofit Control Technologies

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

applicable emission control technologies for SO 2 

# at Jim Bridger 3. This included control

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

The following potential SO 2 

# control technology options were considered:

• 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 3 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 3

Technology Projected Sulfur Dioxide (SO 2 

# )

Emission Rate (pound per million

British thermal units)

Presumptive Best Available Retrofit

Technology Limit 0.15

Upgrade Existing Wet Sodium System 0.10

Optimize Existing Wet Sodium System 0.20

New Dry Flue Gas Desulfurization

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.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# The wet sodium FGD system at Jim Bridger 3 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 would achieve an SO 2 

# outlet emission rate of 0.20 lb per MMBtu

(83.3 percent SO 2 

# removal) by partially closing the bypass damper to reduce routine bypass

flue gas flow used to reheat the treated flue gas from the scrubber, relocating the opacity

monitor, and modifying the system to minimize scaling problems.

Upgrading the wet FGD system would achieve an SO 2 

# outlet emission rate of 0.10 lb per

MMBtu (91.7 percent SO 2 

# removal) by closing the bypass da mper to eliminate routine bypass

flue gas flow used to reheat the treated flue gas from the scrubber, relocating the opacity

monitor, adding new fans, adding a stack liner an d drains for wet operation, and using a refined

soda ash reagent. It is considered technically infeasible for the present wet FGD system to

achieve 95 percent SO 2 

# removal (0.06 lb per MMBtu) on a continuous basis, since this high

level of removal must be incorporated in to 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 SO 2 

# per MMBtu. Therefore, this option is eliminated as technically infeasible for this analysis. An

upgraded wet sodium scrubbing FGD system is proj ected 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 SO 2 

# per MMBtu for Jim Bridger 3.

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 3, this dry particul ate matter would be captu red downstream in the

existing ESP, along with the fly ash. A lime spra y 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 3. 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 3 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 3 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_JB3_OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 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

520 kW of power.

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

makeup water requirements. Another environmen tal impact is a reduction of the stack gas

temperature from 140°F to 120°F due to elimin ation of the bypassed flue gas which had

provided approximately 20°F of reheat.

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 FGD System)

Jim Bridger Unit 3

Factor Upgraded Wet Flue Gas Desulfurization (FGD)

Total Installed Capital Costs $13.0 million

Total First Year Fixed and Variable Operation and

Maintenance Costs $1.3 million

Total First Year Annualized Cost $2.5 million

Additional Power Consumption (megawatts [MW]) 0.5

Additional Annual Power Usage (1000 MW-hours

per year) 4.1

Incremental Sulfur Dioxide (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 3 based on its 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

Please see Section 4, BART Modeling Analysis.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 3.2.3 BART PM 10



# Analysis

Jim Bridger 3 is currently equipped with an ESP. Electrostatic precipitators remove particulate

matter (PM) from the flue gas stream by chargi ng fly ash particles with a very high direct

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

collected PM forms on the collecting plates and is removed by periodically rapping the plates.

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

periodically by the fly ash-handling system. Historically, the ESP at Jim Bridger 3 has

controlled PM 10 

# emissions to levels below 0.057 lb per MMBtu.

The BART analysis for PM 10 

# emissions at Jim Bridger 3 is de scribed in this section. 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 microm eters in aerodynamic diameter (PM 2.5 

# ) as a subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

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

• 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.

Because the environmental benefits of replacing the fabric filter are also achieved by the

lower-cost option of installing a polishing fabric filter downstream of the existing ESP,

installation of a full fabric filter was not considered 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 eff ectively 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 3. One such technology is license d 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 to 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 3 is achieving a controlled PM emission rate of 0.057 lb per

MMBtu. Utilizing flue conditioning upstream of the existing ESP is projected to reduce PM

emissions to approximately 0.030 lb per MMBtu. Adding a COHPAC fabric filter downstream

of the existing ESP is projected to reduce PM emissions to approxima tely 0.015 lb per MMBtu.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-17

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# The PM 10 

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

TABLE 3-6



# PM 10



# Control Technology Emission Rates

Jim Bridger 3

Control Technology Short-term Projected PM 10 (a)



# Emission Rate (pound per

million

British thermal units)

Flue Gas Conditioning 0.030

Polishing Fabric Filter 0.015

NOTES:

(a) 

# PM 10 

# refers to particulate matter less than 10 micrometers in

aerodynamic diameter



# 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 fan upgrade and upgrad e of the auxiliary power supply system.

The COHPAC fabric filter at Jim Bridger 3 would require approximately 3.3 MW of power,

equating to an annual power usage of approximately 26.3 million kW-Hr.

There is only a small power requirement of a pproximately 50 kW associated with flue gas

conditioning.

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

COHPAC polishing fabric filter or flue gas conditioning system.

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

conditionings are recorded in Table 3-7, and the first-year control costs for flue gas

conditioning and fabric filters are shown in Figure 3-5. The complete economic analysis is

contained in Appendix A.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-18

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-19



# TABLE 3-7



# PM 10



# Control Cost Comparison (Incremental to Existing ESP)

Jim Bridger 3

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 $1.7 million

Total First Year Annualized Cost $0.2 million $ 6.3 million

Additional Power Consumption (MW) 0.05 3.43

Annual Power Usage (million kilowatt-hours per

year) 0.4 26.3

Incremental Particulate Matter (PM) Design Control

Efficiency 47.4% 73.7%

Incremental Tons PM Removed per Year 639 993

First Year Average Control Cost

(dollars per ton [$/Ton] of PM Removed) 275 6,381

Incremental Control Cost

($/Ton of PM Removed) 275 17,371



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

upstream of the existing ESP as BART for Jim Br idger 3 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

Please see Section 4, BART Modeling Analysis.BART ANALYSIS FOR JIM BRIDGER UNIT 3FIGURE 3-5First Year Control Cost for PM Air Pollution Control OptionsJim Bridger 302,0004,0006,0008,00010,00012,00014,00016,00018,00020,000Flue Gas ConditioningFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC3-20

# 4.0 BART Modeling Analysis

4.1 Model Selection

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

from Jim Bridger 3 at nearby Class I areas. The Class I areas potentially affected are located

more than 50 kilometers but less than 300 kilo meters from the Jim Bridger 3 facility. The

Class I areas include the following wilderness areas (WA):

• Bridger WA

• Fitzpatrick WA

• Mt. Zirkel WA

The CALPUFF modeling system includes the CALMET meteorological model, a Gaussian

puff dispersion model (CALPUFF) with algor ithms for chemical transformation and

deposition, and a post processor ca pable of calculating co ncentrations, visib ility impacts, and

deposition (CALPOST). The CALPUFF modeling sy stem was applied in a full, refined mode.

Version numbers of the various programs in the CALPUFF system used by CH2M HILL were

as follows:

• CALMET Version 5.53a, Level 040716

• CALPUFF Version 5.711a, Level 040716

• CALPOST Version 5.51, Level 030709



# 4.2 CALMET Methodology

4.2.1 Dimensions of the Modeling Domain

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

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

established to encompass the Jim Bridger 3 f acility and allow for a 50-kilometer buffer around

the Class I areas that were within 300 kilometers of the facility; the grid resolution was

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

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

Division (WDEQ-AQD), CH2M HILL followe d the methodology spelled out in the

WDEQ-AQD BART Modeling Protocol, a copy of which is included as Appendix B.

CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to 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_JB3_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 3



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

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

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

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

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

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

analysis.

TABLE 4-1



# User-specified CALMET Options

Jim Bridger 3

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-4 

# 4.2.2 CALMET Input Data

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

2003. WDEQ-AQD provided 12-km resolution Meso scale Meteorological Model, Version 5

(MM5) meteorological data fiel ds that covered the entire m odeling 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

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

wind field.

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

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

Observing System network for all stations that are in the domain. The surface data were

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

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

preprocessor and CALMET.

Land use and terrain data were obtained from the U.S. Geological Survey (USGS). Land use

data were obtained in Composite Theme Grid format from the USGS, and the Level 1 USGS

land use categories were mapped into the 14 primary CALMET land use categories. Surface

properties such as 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 3



# 4.2.3 Validation of CALMET Wind Field

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

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

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

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

Atmospheric Administration, 2006).



# 4.3 CALPUFF Modeling Approach

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

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

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

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

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

impacts for post-control scenarios for Jim Bridger 3.



# 4.3.1 Background Ozone and Ammonia

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

calculation of SO 2 

# and NO

x 

# transformation with the MESOPUFF II chemical transformation

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

the modeling domain for 2001, 2002, and 2003:

• Rocky Mountain National Park, Colorado

• Craters of the Moon National Park, Idaho

• Highland, Utah

• Thunder Basin National Grasslands, Wyoming

• Yellowstone National Park, Wyoming

• Centennial, Wyoming

• Pinedale, Wyoming

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

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

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



# 4.3.2 Stack Parameters

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

current permit for Jim Bridger 3. Post-control stack parameters re flect the anticipated

changes associated with insta llation 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 represent a wors t-case situation.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 4.3.3 Emission Rates

Pre-control emission rates for Jim Bridger 3 refl ect peak 24-hour average emissions that may

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

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

Guidelines for Best Available Retrofit Technology Determinations; Final Rule

(40 CFR Part 51).

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

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

more recent period was more representative. Allowable short-term (24-hour or shorter

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

data were not available.

Emissions were modeled for the following pollutants:

• 

# SO 2



# • 

# NO

x



# • 

# Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• 

# Fine particulate (diameter<PM 2.5 

# )

• 

# Sulfates

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

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



# 4.3.4 Post-control Scenarios

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

the combination of the individual NO

x 

# , SO 2 

# , and PM control technol ogies being evaluated.

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

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

levels for each pollutant.

• 

# Scenario 1 : New LNB with OFA modi fications, upgraded wet FGD system and flue gas

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

represents CH2M HILL’s preliminary BART recommendation.

• 

# Scenario 2 : New LNB with OFA modifications, upgraded wet FGD system and new

polishing fabric filter.

• 

# Scenario 3 : New LNB with OFA modifications and SCR, upgraded wet FGD system and

flue gas conditioning for enhanced ESP performance.

• 

# Scenario 4 : New LNB with OFA modifications and SCR, upgraded wet FGD system and

new polishing fabric filter.

The ROFA option and LNB with OFA & SCR option for NO

x 

# control were not included in

the modeling scenarios because their control effectiveness is between the 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 soluti on will include a combination of control

technologies for NO

x 

# , SO 2 

# , and PM.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-8 

# Table 4-2 presents the stack parameters a nd emission rates used for the Jim Bridger 3

analysis for baseline and post-control m odeling. In accordance with the WDEQ BART

modeling protocol, elemental car bon stack emissions and organic aerosol emissions were not

modeled.



# 4.3.5 Modeling Process

The CALPUFF modeling for the control technology options for Jim Bridger 3 followed this

sequence:

• 

# Model pre-control (baseline) emissions

• 

# Model preferred post-control scenario (if applicable)

• 

# Determine degree of visibility improvement

• 

# Model other control scenarios

• 

# Determine degree of visibility improvement

• 

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



# 4.3.6 Receptor Grids

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

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

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

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

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

locations.TABLE 4-2BART Model Input DataJim Bridger 3BaselinePost-control Scenario 1 Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Model Input DataCurrent Operations with wet FlueGas Desulfurization (FGD) andElectrostatic Precipitator (ESP)LNB with Over Fire Air (OFA),Upgrade Wet FGD & Flue GasConditioning (FGC) forEnhanced ESP PerformanceLNB with OFA, Upgrade WetFGD, New Fabric FilterLNB with OFA and SCR,Upgrade Wet FGD & FGC forEnhanced ESP PerformanceLNB with OFA andSCR, Upgrade WetFGD, New Fabric FilterSulfur Dioxide (SO2) StackEmissions (pounds per hour [lb/hr])1,602600600600600Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 2,7001,4401,440420420PM10Stack Emissions (lb/hr)342 180 90.0 180 90.0Coarse Particulates (PM2.5<diameter<PM10) Stack Emissions (lb/hr)(a)147 77.4 51.3 77.4 51.3Fine Particulates (diameter<PM2.5) Stack Emissions (lb/hr)(a)195 103 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)5.10 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)25.6 24.8 27.4 27.4 27.4NOTES:(a)Based on AP-42, Table 1.1-6, coarse particulates are counted asa percentage of PM10. This equates to 43 percent ESP and 57 percent baghouse. PM10and PM2.5refer to particulate matter less than 10 and 2.5 micrometers, respectively,in aerodynamic diameter.(b)Based on AP-42, Table 1.1-6, fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent baghouse. PM10and PM2.5refer to particulate matter less than 10 and 2.5 micrometers, respectively, in aerodynamic diameter.Total Sulfate (SO4) (lb/hr) = H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4as SO4Stack Emissions (lb/hr) + (NH4)HSO4as SO4Stack Emissions (lb/hr)Scenarios 2, 3, and 4 were not remodeled at the lower, correct velocity of 81.24 fps due to lack oftime and the fact that theconclusions to select Scenario 1 would not have changed.

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 4.4 CALPOST

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

output specified in deciview (dV) units. Calcula tions of light extinction 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 backgr ound. The following default light extinction

coefficients for each pollutant were used:

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 

# ) 0.6

• PM fine (PM 2.5 

# ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0

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

humidity factors were used in the light extinc tion calculations to a ccount for the hygroscopic

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

Protocol (Appendix B) lists the monthly relative humidity fact ors for the Class I areas. These

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

The natural background conditions as a refere nce for determining the delta-deciview ( Δ dV)

change represented the 20 per cent best natural visibility days. The EPA BART guidance

document provided dV values for the 10 percent be st days for each Class I area, but did not

provide individual species c oncentration data for the 20 percent best days. Species

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

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

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule

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

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

for that area would be calculate d. This procedure was taken from Protocol for BART-Related

Visibility Improvement Modeling Analysis in North Dakota (North Dakota Department of

Health, 2005). The Wyoming BART Air Modeli ng Protocol (see Appendix B) did provide

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

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-10

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-11 

# TABLE 4-3



# Average Natural Levels of Aerosol Components

Jim Bridger 3

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:

Source: Table 6 of the Wyoming BART Air Modeling Protocol



# 4.5 Presentation of Modeling Results

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

for Jim Bridger 3.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Jim Bridger 3 for the base line conditions and pos t-control 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 Jim Bridger 3.

Baseline (and post-control) 98 th 

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

WA, Fitzpatrick WA, and Mt. Zirkel WA. The 98 th 

# percentile results for each Class I area are

presented in Table 4-4.BART ANALYSIS FOR JIM BRIDGER UNIT 3TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I AreasJim Bridger 3ModelingResultsScenarioTotal First YearAnnualized CostClass IWilderness AreaHighest Changein Deciview(ΔdV)98thPercentile(ΔdV)Number (No.)of Days Above0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove0.5 dVIncrementalCost per dVReductionIncremental Costper Reduction inNo. of Days Above0.5 dV2001Bridger2.5060.74115----Fitzpatrick2.1780.4187----Baseline: current operation with wet Flue Gas Desulfurization(FGD), Electrostatic Precipitator (ESP)Mt. Zirkel1.9451.22627----$3,387,923Bridger1.3660.3867$9,543,444$423,490$3,387,923Fitzpatrick1.3860.2233$17,373,962$846,981Scenario 1: Low-NOxBurners (LNBs) with Over Fire Air (OFA),upgrade wet FGD, Flue Gas Conditioning (FGC) for enhancedESP performance$3,387,923Mt. Zirkel1.1680.73316$6,872,054$307,993$9,726,040Bridger1.3930.3766$26,646,685$1,080,671$633,811,750$6,338,118$9,726,040Fitzpatrick1.1820.2143$47,676,667$2,431,510$704,235,278NAScenario 2: LNB with OFA, upgrade wet FGD, polishing fabricfilter$9,726,040Mt. Zirkel1.1020.67715$17,715,920$810,503$113,180,670$6,338,118$18,074,111Bridger0.8750.2793$39,121,453$1,506,176$86,062,591$2,782,690$18,074,111Fitzpatrick0.6810.1281$62,324,522$3,012,352$97,070,597$4,174,036Scenario 3: LNB with OFA and Selective Catalytic Reduction(SCR), upgrade wet FGD, FGC for enhanced ESP performance$18,074,111Mt. Zirkel0.7580.4515$23,321,434$821,551$36,938,369$834,807$24,412,229Bridger0.8370.2683$51,611,478$2,034,352$576,192,500NA$24,412,229Fitzpatrick0.660.1261$83,603,524$4,068,705$3,169,058,751NAScenario 4: LNB with OFA and SCR, upgrade wet FGD,polishing fabric filter$24,412,229Mt. Zirkel0.7310.4372$30,940,721$976,489$452,722,679$2,112,7062002Bridger4.1031.44727----Fitzpatrick1.9060.71311----Baseline: current operation with wet FGD, ESPMt. Zirkel2.8011.49834----$3,387,923Bridger2.4470.85414$5,713,191$260,609$3,387,923Fitzpatrick1.0740.3774$10,083,103$483,989Scenario 1: LNB with OFA, upgrade wet FGD, FGC forenhanced ESP performance$3,387,923Mt. Zirkel1.5410.81513$4,960,355$161,330$9,726,040Bridger2.3180.78213$14,625,624$694,717$88,029,410$6,338,118$9,726,040Fitzpatrick1.0050.3496$26,719,890$1,945,208$226,361,339NAScenario 2: LNB with OFA, upgrade wet FGD, polishing fabricfilter$9,726,040Mt. Zirkel1.4840.77813$13,508,389$463,145$171,300,473NA$18,074,111Bridger1.3160.5099$19,268,775$1,004,117$30,579,016$2,087,018$18,074,111Fitzpatrick0.5510.2261$37,113,165$1,807,411$67,870,499$1,669,614Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGCfor enhanced ESP performance$18,074,111Mt. Zirkel0.8820.4734$17,633,279$602,470$27,370,726$927,563$24,412,229Bridger1.2900.4987$25,724,161$1,220,611$576,192,500$3,169,059$24,412,229Fitzpatrick0.5410.2221$49,719,407$2,441,223$1,584,529,376NAScenario 4: LNB with OFA and SCR, upgrade wet FGD,polishing fabric filter$24,412,229Mt. Zirkel0.8600.4644$23,609,506$813,741$704,235,278NAJMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC4-12BART ANALYSIS FOR JIM BRIDGER UNIT 3JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC4-13TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I AreasJim Bridger 3ModelingResultsScenarioTotal First YearAnnualized CostClass IWilderness AreaHighest Changein Deciview(ΔdV)98thPercentile(ΔdV)Number (No.)of Days Above0.5 dVCost per dVReductionCost per Reductionin No. of DaysAbove0.5 dVIncrementalCost per dVReductionIncremental Costper Reduction inNo. of Days Above0.5 dV2003Bridger1.7030.75916----Fitzpatrick1.9430.3787----Baseline: current operation with wet FGD, ESPMt. Zirkel1.9521.22835----$3,387,923Bridger0.9830.4145$9,820,065$307,993$3,387,923Fitzpatrick1.1050.1922$18,214,637$677,585Scenario 1: LNB with OFA, upgrade wet FGD, FGC forenhanced ESP performance$3,387,923Mt. Zirkel1.0410.73416$18,117,233$178,312$9,726,040Bridger0.9830.4105$27,868,310$884,185$1,584,529,376NA$9,726,040Fitzpatrick1.0880.1882$51,189,684$1,945,208$1,584,529,376NAScenario 2: LNB with OFA, upgrade wet FGD, polishing fabricfilter$9,726,040Mt. Zirkel1.0530.68615$17,944,723$486,302$132,044,115$6,338,118$18,074,111Bridger0.8520.2583$36,076,071$1,390,316$54,921,522$4,174,036$18,074,111Fitzpatrick0.6820.1182$69,515,813$3,614,822$119,258,162NAScenario 3: LNB with OFA and SCR, upgrade wet FGD, FGCfor enhanced ESP performance$18,074,111Mt. Zirkel0.6660.4325$22,706,170$602,470$32,866,423$834,807$24,412,229Bridger0.8080.2483$47,773,442$1,877,864$633,811,750NA$24,412,229Fitzpatrick0.6630.1152$92,822,163$4,882,446$2,112,705,834NAScenario 4: LNB with OFA and SCR, upgrade wet FGD,polishing fabric filter$24,412,229Mt. Zirkel0.6330.425$30,213,155$813,741$528,176,459NA3-year AveragesBridger0.98219.3Fitzpatrick0.5038.3Baseline: Current Operation with wet FGD, ESPMt. Zirkel1.31732.0$3,387,923Bridger0.5518.7$7,860,609$317,618$3,387,923Fitzpatrick0.2643.0$14,175,408$635,235Scenario 1: LNB with OFA, upgrade wet FGD, FGC forenhanced ESP performance$3,387,923Mt. Zirkel0.76115.0$6,086,088$199,290$9,726,040Bridger0.5238.0$21,158,898$858,180$221,097,122$9,507,176$9,726,040Fitzpatrick0.2503.7$38,493,562$2,084,151$463,764,695NAScenario 2: LNB with OFA, upgrade wet FGD, polishing fabricfilter$9,726,040Mt. Zirkel0.71414.3$16,111,607$550,531$134,853,564$9,507,176$18,074,111Bridger0.3495.0$28,523,059$1,260,985$47,977,422$2,782,690$18,074,111Fitzpatrick0.1571.3$52,287,690$2,582,016$89,764,208$3,577,745Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGCfor enhanced ESP performance$18,074,111Mt. Zirkel0.4524.7$20,886,878$661,248$31,903,457$863,594$24,412,229Bridger0.3384.3$37,887,577$1,627,482$594,198,516$9,507,176$24,412,229Fitzpatrick0.1541.3$70,015,953$3,487,461$2,112,705,834NAScenario 4: LNB with OFA and SCR, upgrade wet FGD,polishing fabric filter$24,412,229Mt. Zirkel0.4403.7$27,836,065$861,608$543,267,215$6,338,118NOTES:Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001:= $3,387,923 / (0.8968 - 0.492) = $8,845,751Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001:= $3,387,923 / (20 -7) = $260,609

# 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 3, the pr eliminary recommended BART controls for NO

x 

# , SO 2 

# , and PM are as follows:

• 

# New LNBs and modifications to the OFA system for NO

x 

# control

• 

# Upgrade wet sodium FGD for SO 2 

# control

• 

# Add flue gas conditioning upstream of existing ESPs for PM control

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

described in Section 4. Visibility improveme nts for all emission control scenarios were

analyzed, and the results are compared below, utilizing a least-cost envelope, as outlined in

the New Source Review Workshop Manual (EPA, 1990).The purpose of this analysis is to use

an objective, EPA-approved methodology to eval uate and make the final recommendation of

BART control technology.



# 5.1 Least-cost Envelope Analysis

For the control scenarios modeled in Sec tion 4, Tables 5-1 through 5-3 list the total

annualized cost, cost per dV reduction, and cost per reduction in number of days above

0.5 dV for each of the three Class I areas. A co mparison of the incremental 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 Review Workshop Manual , the EPA states that:

“Incremental cost-effectiveness comparisons should focus on annualized cost and emission

reduction differences between domin ant alternatives. Dominant set of control alternatives are

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

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

alternatives identified in the BACT analysis...”

An analysis of incremental cost effectiv eness has been conducted. This analysis was

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

order of annualized total costs, as shown in Tables 5-1 through 5- 3. The incremental 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 opti on scenarios is plotted

for each analysis. Figures 5-1 through 5-6 pres ent the 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

impacted by the operation of Jim Bridger 3.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



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

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

should only be conducted for control options th at 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 curvilinear line connecting th em. Scenario 2 is an inferior

option and should not be considered in the de rivation of incremental cost effectiveness.

Scenario 2 represents inferior controls, becau se Scenario 1 provides approximately the same

amount of visibility impact re duction for less cost than Scen ario 2. The incremental cost

effectiveness is determined by the difference in total annual costs be tween two contiguous

scenarios, divided by the difference in emissions reduction.

TABLE 5-1



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

Jim Bridger 3

Scenario Controls 98 th



# Percentile

Deciview

(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 Flue Gas

Desulfurization (FGD),

Electrostatic

Precipitator (ESP) 0.00 0.0 0.0 0.0 0.0

1 Low-NO

x

# Burners

(LNBs) with Over Fire

Air (OFA), upgraded

wet FGD system, flue

Gas Conditioning

(FGC) for enhanced

ESP performance 0.43 10.7 3.4 7.9 0.3

2 LNB with OFA,

upgraded wet FGD

system, and new

polishing fabric filter 0.46 11.3 9.7 21.2 0.9

3 LNB with OFA and

Selective Catalytic

Reduction (SCR),

upgraded wet FGD

system, FGC for

enhanced ESP

performance 0.63 14.3 18.1 28.5 1.3

4 LNB with OFA and

SCR, upgraded wet

FGD system, new

polishing fabric filter 0.64 15.0 24.4 37.9 1.6

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# TABLE 5-2



# Control Scenario Results for the Fitzpatrick Class I Wilderness Area

Jim Bridger 3

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 Flue Gas

Desulfurization (FGD),

Electrostatic

Precipitator (ESP) 0.00 0.0 0.0 0.0 0.0

1 Low-NO

x

# Burners

(LNBs) with Over Fire

Air (OFA), upgraded

wet FGD system, flue

Gas Conditioning

(FGC) for enhanced

ESP performance 0.24 5.3 3.4 14.2 0.6

2 LNB with OFA,

upgraded wet FGD

system, and new

polishing fabric filter 0.25 4.7 9.7 38.5 2.1

3 LNB with OFA and

Selective Catalytic

Reduction (SCR),,

upgraded wet FGD

system, FGC for

enhanced ESP

performance 0.35 7.0 18.1 52.3 2.6

4 LNB with OFA and

SCR, upgraded wet

FGD system, new

polishing fabric filter 0.35 7.0 24.4 70.0 3.5

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# TABLE 5-3



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

Jim Bridger 3

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 Flue Gas

Desulfurization (FGD),

Electrostatic

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

1 Low-NO

x 

# Burners

(LNBs) with Over Fire

Air (OFA), upgraded

wet FGD system, flue

Gas Conditioning

(FGC) for enhanced

ESP performance 0.56 17.0 $3.4 $6.1 $0.2

2 LNB with OFA,

upgraded wet FGD

system, and new

polishing fabric filter 0.60 17.7 $9.7 $16.1 $0.6

3 LNB with OFA and

Selective Catalytic

Reduction (SCR),

upgraded wet FGD

system, FGC for

enhanced ESP

performance 0.87 27.3 $18. 1 $20.9 $0.7

4 LNB with OFA and

SCR, upgraded wet

FGD system, new

polishing fabric filter 0.88 28.3 $24. 4 $27.8 $0.9

TABLE 5-4



# Bridger Class I Wilderness Area Incremental Analysis Data

Jim Bridger 3

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 10.7 0.43 $0.32 $7.9

Scenario 1 and Scenario 2 0.7 0.03 $9.5 $221.1

Scenario 1 and Scenario 3 3.7 0.20 $4.0 $72.5

Scenario 1 and Scenario 4 4.3 0.21 $4.9 $98.6

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# TABLE 5-5



# Fitzpatrick Class I Wilderness Area Incremental Analysis Data

Jim Bridger 3

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days)) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 5.3 0.24 $0.64 $14.2

Scenario 1 and Scenario 2 NA 0.01 NA $463.8

Scenario 1 and Scenario 3 1.7 0.11 $8.8 $137.7

Scenario 1 and Scenario 4 1.7 0.11 $12.6 $191.7

TABLE 5-6



# Mt. Zirkel Class I Wilderness Area Incremental Analysis Data

Jim Bridger 3

Options Compared Incremental

Reduction in

Days Above

0.5 Deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 17.0 0.56 $0.20 $6.09

Scenario 1 and Scenario 2 0.7 0.05 $9.5 $134.9

Scenario 1 and Scenario 3 10.3 0.31 $1.4 $47.6

Scenario 1 and Scenario 4 11.3 0.32 $1.9 $65.6

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# FIGURE 5-1



# Least-cost Envelope Bridger Class I WA Days Reduction

Jim Bridger 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

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

0 2 4 6 81 0 1 2 1 4



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



# 1 6



# FIGURE 5-2



# Least-cost Envelope Bridger Class I WA 98 th



# Percentile Reduction

Jim Bridger 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

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

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70



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



# JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick Class I WA Days Reduction

Jim Bridger 3

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

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

01234567



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



# 8



# FIGURE 5-4



# Least-cost Envelope Fitzpatrick Class I WA 98 th



# Percentile Reduction

Jim Bridger 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0.00 0.05 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_JB3_OCT2007_FINAL.DOC 5-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# FIGURE 5-5



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

Jim Bridger 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0 5 10 15 20 25 30



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



# FIGURE 5-6



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



# Percentile Reduction

Jim Bridger 3

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00



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



# JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 3



# 5.1.2 Analysis Results

Results of the least-co st Analysis, shown in Tables 5-1 through 5-6 and Figures 5-1 through

5-6 on the preceding pages, confirm the selectio n of Scenario 1, based on incremental cost

and visibility improvements. Scenario 2 is elim inated because it is to the left of the curve

formed by the “dominant” control alternative scenarios, which indicates a scenario with

lower improvement and/or higher costs. Scen ario 3 is not select ed due to very high

incremental costs for both a cost per day of improvement and a cost per dV reduction. While

Scenario 4 provides some potential visibili ty advantage over Scenario 1, the projected

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

Analysis of the results for the Jim Bridger Cla ss I WA in Tables 5-1 and 5-4 and Figures 5-1

and 5-2 illustrates these conclu sions. The greatest reduction in 98 th 

# percentile dV and number of

days above 0.5 dV is between the Baseline and Scenario 1. The incremen tal cost-effectiveness

for Scenario 1—compared to the Baseline for th e Bridger WA, for example—is reasonable at

$320,000 per day and $7.9 million/dV. However, the incremental cost effectiveness for

Scenario 3 compared to Scenario 1, again for the Bridger WA, is excessive at $4.0 million per

day and $72.5 million per dV. The same conclu sions are reached for each of the three

wilderness areas studied. Therefore, Scenar io 1 represents BART for Jim Bridger 3.



# 5.2 Recommendations

5.2.1 NO

x 

# Emission Control

The BART presumptive NO

x 

# limit assigned by EPA for tange ntially-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 mo re closely aligned with bituminous coals, and

have been assigned a presumptive BART NO

x 

# limit of 0.28 lb per MMBtu.

CH2M HILL recommends LNB with OFA as BART for Jim Bridger 3, based on the

projected significant reduction in NO

x 

# emissions, reasonable control costs, and the

advantages of no additional power requirement s or non-air quality environmental impacts.

NO

x 

# reductions are expected to be similar to those realized at Ji m 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 3, based on the significant reduction in SO 2 

# emissions, reasonable control costs,

and the advantages of both minimal additio nal power requirements and 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 3, 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.

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 3

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-10 

# 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 im provements at the Class I areas studied would

be expected under any of the s cenarios. Thus the results i ndicate that even though many

millions of dollars will be spent, only mini mal if any visibility improvements may result.

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

in various forms (fog, clouds, snow, or rain) or other naturally caused aerosols may obscure

the atmosphere and reduce visibility. Duri ng the period of 2001 through 2003, there were

several mega-wildfires that lasted for many days, with a significant impact on background

visibility in these Class I ar eas. If natural obscuration lesse ns the achievable reduction on

visibility impacts modeled for BART controls at the Jim Bridger 3 facility, the overall effect

would be to increase the co sts per dV reduction that are presented in this report.

# 6.0 References

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

Technology Determinations; Final Rule. July 6, 2005.

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

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

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

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

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

and Nonattainment Area Permitting . Draft. October 1990.

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_JB3_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios5Index 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 N/A $ 3,387,923 N/AN/AN/A N/A $ 3,387,923 N/AN/A N/A $ 3,387,923 N/AN/AN/AN/A N/A $ 9,726,040 N/AN/A N/A $ 9,726,040 N/AN/AN/A N/A $ 9,726,040 N/A N/AN/A N/A $ 18,074,111 N/A N/AN/A N/A $ 18,074,111 N/A N/AN/A N/A $ 18,074,111 N/AN/A N/A $ 24,412,229 N/AN/A N/A $ 24,412,229 N/AN/A N/A $ 24,412,229 N/AScenario 4 - N/AJim Bridger Unit 3Scenario 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 StackScenario 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 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,ESPBaseline - Current Operation withESPBaseline - Current Operation withESPBaseline - Current Operation with WetFGD and ESPNTN Unit 1 NTN Unit 2 NTN Unit 3NaughtonScenario 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 FilterScenario 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, ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPJB Unit 1 JB Unit 2 JB Unit 3 JB Unit 4Jim 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 ScrubberScenario 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 FilterEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYJim Bridger Unit 3Boiler Design: Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRUpgraded WetFGDFlue GasConditioningFabric FilterCase1 2 3 4 5 8 9 10NOx Emission Control SystemLNCFS-1 &Windbox Mods. LNB w/OFA ROFALNB w/OFA &SNCRLNB w/OFA &SCRLNCFS-1 & WindboxMods.LNCFS-1 & WindboxMods.LNCFS-1 & WindboxMods.SO2 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 ($)0 8,700,001 20,528,122 21,973,632 129,575,495 12,999,900 0 48,386,333FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 0 0 0Maintenance Material ($) 0 28,000 42,000 122,000 190,000 25,550 0 51,099Maintenance Labor ($) 0 42,000 63,000 183,000 285,000 17,033 10,000 76,649Administrative Labor ($) 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST0 70,000 105,000 305,000 475,000 42,583 10,000 127,749Makeup Water Cost 0 0 0 0 0 29,927 0 0Reagent Cost 0 0 0 1,005,811 912,848 533,206 145,854 0SCR Catalyst / FF Bag Cost 0 0 0 0 600,000 0 0 294,008Waste Disposal Cost 0 0 0 0 0 442,958 0 0Electric Power Cost 0 0 2,528,012 204,984 1,269,718 204,984 19,710 1,313,474TOTAL VARIABLE O&M COST0 0 2,528,012 1,210,7952,782,5661,211,075165,5641,607,482TOTAL FIRST YEAR O&M COST 0 70,000 2,633,012 1,515,795 3,257,566 1,253,658 175,564 1,735,231FIRST YEAR DEBT SERVICE ($)0 827,612 1,952,796 2,090,304 12,326,235 1,236,652 0 4,602,887TOTAL FIRST YEAR COST ($)0 897,612 4,585,808 3,606,099 15,583,801 2,490,310 175,564 6,338,118Power Consumption (MW)0.0 0.0 6.4 0.5 3.2 0.5 0.1 3.3Annual Power Usage (Million kW-Hr/Yr)0.0 0.0 50.6 4.1 25.4 4.1 0.4 26.3CONTROL COST ($/Ton Removed)NOx Removal Rate (%)0.0%46.7%51.1%55.6%84.4%0.0%0.0%0.0%NOx Removed (Tons/Yr) 0 4,967 5,440 5,913 8,987 0 0 0First Year Average Control Cost ($/Ton NOx Rem.)0 181 843 610 1,73400 0Incremental Control Cost ($/Ton NOx Removed)0 181 7,797 2,863 3,896 0 0 02-1 3-2 4-2 5-4SO2 Removal Rate (%)77.8%0.0%0.0%0.0%0.0%62.5%0.0%0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 3,950 0 0First Year Average Control Cost ($/Ton SO2 Rem.)0 0 0 0 0 631 0 0Incremental Control Cost ($/Ton SO2 Removed)Base 0 0 0 0 631 0 08-1PM Removal Rate (%)99.33%0.00%0.00%0.00%0.00%0.00%47.37%73.68%PM Removed (Tons/Yr) 0 0 0 0 0 0 639 993First Year Average Control Cost ($/Ton PM Rem.)0 0 0 0 0 0 275 6,381Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 275 17,3719-1 10-9PRESENT WORTH COST ($)0 9,555,250 52,697,883 40,493,391 169,375,961 28,316,912 2,145,015 69,587,130PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls1 of 1INPUT CALCULATIONSJim Bridger Unit 3Boiler Design:Tangential-Fired PCLNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& SCRUpgraded WetFGDFlue GasConditioningFabric FilterCase1 2 3 4 5 8 9 10NOx Emission Control SystemLNCFS-1 &Windbox Mods. LNB w/OFA ROFALNB w/OFA &SNCR LNB w/OFA & SCRLNCFS-1 & WindboxMods.LNCFS-1 &Windbox Mods.LNCFS-1 & WindboxMods.SO2 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)2,700 2,700 2,700 2,700 2,700 2,700 2,700 2,700(Lb/MMBtu)0.450.45 0.45 0.45 0.45 0.45 0.45 0.45(Lb Moles/Hr)89.96 89.96 89.96 89.96 89.96 89.96 89.96 89.96(Tons/Yr)10,643 10,643 10,643 10,643 10,643 10,643 10,643 10,643NOx Removal Rate (%)0.0%46.7%51.1%55.6%84.4%0%0.0%0%(Lb/Hr)0 1,260 1,380 1,500 2,280 0 0 0(Lb Moles/Hr)0.00 41.98 45.98 49.98 75.97 0.00 0.00 0.00(Ton/Yr)0 4,967 5,440 5,913 8,987 0 0 0NOx Emission Rate (Lb/Hr)2,700 1,440 1,320 1,200 420 2,700 2,700 2,700(Lb/MMBtu)0.450.24 0.22 0.20 0.070.45 0.45 0.45(Ton/Yr)10,643 5,676 5,203 4,730 1,656 10,643 10,643 10,643Uncontrolled Fly Ash (Lb/Hr)51,177 342 342 342 342 342 342 342(Lb/MMBtu)8.530 0.057 0.057 0.057 0.057 0.057 0.057 0.057(Lb Moles/Hr)1,705.3 11.4 11.4 11.4 11.4 11.4 11.4 11.4(Tons/Yr)201,739 1,348 1,348 1,348 1,348 1,348 1,348 1,348Fly Ash Removal Rate (%)99.33%0.00%0.00%0.00%0.00%0.00%47.37%73.68%(Lb/Hr)50,835 0 0 0 0 0 162 252(Ton/Yr)200,391 0 0 0 0 0 639 993Fly Ash Emission Rate (Lb/Hr)342 342 342 342 342 342 180 90(Lb/MMBtu)0.0570.057 0.057 0.057 0.057 0.0570.030 0.015(Ton/Yr)1,348 1,348 1,348 1,348 1,348 1,348 710 355ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls1 of 2LNB w/OFA ROFALNB w/OFA& SNCRLNB w/OFA& 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)08,700,001 20,528,122 21,973,632 129,575,49500 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 ($2006)0 8,700,001 20,528,122 21,973,632 129,575,49512,999,900 0 48,386,333NOx Emission Control System ($/kW)0 16 39 41 244 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 ($/kW)0 16 39 41 244 25 0 91Total Fixed Operating & Maintenance CostsOperating Labor ($)00000 0 0 0Maintenance Material ($)0 28,000 42,000 122,000 190,000 25,550 0 51,099Maintenance Labor ($)0 42,000 63,000 183,000 285,000 17,033 10,000 76,649Administrative Labor ($)00000 0 0 0Total Fixed O&M Cost ($)0 70,000 105,000 305,000 475,000 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 52 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 29,927 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 0 690 579 1,6911000First Year Reagent Cost ($)0 0 0 1,005,811 912,848 533,206 145,854 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000200 0 0 2,827SCR Catalyst ($/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 0 600,000 0 0 294,008Annual 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%0.63%(MW)0.00 0.00 6.41 0.52 3.22 0.52 0.05 3.33Unit 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 2,528,012 204,984 1,269,718 204,984 19,710 1,313,474Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.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%Index No. Name of Unit | Case --->NOx Control SO2 Control PM ControlCoal QualityUnit DesignCurrent Emission Control SystemsIndex No. Name of UnitEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.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--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) SO2 Control Emission Rates (Lb/MMBtu)Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.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 NH31.001602.42Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.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$$ -82Lime1.02-1.75Index No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsVariable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur67 -0.0510 Wyodak Unit 1-$ -$ 10,000$--Elemental Sulfur63-0.05Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak Unit 1-$ 48,666$ 72,999$$ --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 $ 20,106,000NOx Control SO2 Control PM ControlIndex No. Name of Unit | Case --->Index No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsIndex No. Name of UnitAnnual Fixed O&M Costs Variable Operating RequirementsEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls5 of 5CAPITAL COSTJim Bridger Unit 3CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control SystemCAPITAL COST COMPONENTFactor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source CostLNB w/OFA or ROFALNB w/OFA ROFA LNB w/OFA LNB w/OFAMajor Materials Design and SupplyVendor $2,981,982Vendor $6,056,955Vendor $2,981,982Vendor $2,981,982Vendor $0Vendor $0Vendor $0Vendor $0Vendor $0Construction85.3%$2,544,63885.3%$5,168,62885.3%$2,544,63885.3%$2,544,63885.3%$085.3%$085.3%$085.3%$085.3%$0Balance of Plant51.7%$1,541,45151.7%$3,130,97051.7%$1,541,45151.7%$1,541,45151.7%$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%$395,06313.2%$802,44613.2%$395,06313.2%$395,06313.2%$013.2%$013.2%$013.2%$013.2%$0Surcharge16.4%$489,80516.4%$994,88416.4%$489,80516.4%$489,80516.4%$016.4%$016.4%$016.4%$016.4%$0AFUDC12.2%$364,35212.2%$740,06712.2%$364,35212.2%$364,35212.2%$012.2%$012.2%$012.2%$012.2%$0Subtotal $8,317,291 $18,711,036$8,317,291 $8,317,291 $0 $0 $0 $0 $0Contingency12.8%$382,70930.0%$1,817,08712.8%$382,70912.8%$382,70912.8%$012.8%$012.8%$012.8%$012.8%$0Total Capital Cost for LNB w/OFA or ROFA $8,700,001 $20,528,122 $8,700,001 $8,700,001 $0 $0 $0 $0 $0SNCR or SCRSNCR SCRMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $9,419,000 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%$1,883,80020.0%$16,184,60020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$526,8055.6%$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%$103,7971.1%$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%$264,3912.8%$2,271,5092.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$1,075,83811.4%$9,243,02511.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $13,273,632 $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 $48,386,333PM ControlFlue Gas ConditioningNOx Control45 76293LNB w/OFA & SNCRWet FGDESP ESPLNB w/OFA & SCRWet FGDESPLNCFS-1 & Windbox Mods.N/AESPParameterLNB w/OFA ROFA LNB w/OFA & SCRUpgraded Wet FGDESPLNB w/OFAWet FGDESP ESPROFAWet FGDLNCFS-1 & Windbox Mods.N/AN/AN/ALNB w/OFA & SNCRSO2 ControlUpgraded Wet FGDFabric Filter8LNCFS-1 & Windbox Mods.Fabric Filter10LNCFS-1 & Windbox Mods.Wet FGDLNCFS-1 & Windbox Mods.Wet FGDFlue Gas ConditioningEY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls1 of 1Jim Bridger Unit 3LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 70,000------827,612897,6121812 2015 71,400------827,612899,0121813 2016 72,828------827,612900,4401814 2017 74,285------827,612901,8971825 2018 75,770------827,612903,3821826 2019 77,286------827,612904,8981827 2020 78,831------827,612906,4431838 2021 80,408------827,612908,0201839 2022 82,016------827,612909,62818310 2023 83,656------827,612911,26918311 2024 85,330------827,612912,94218412 2025 87,036------827,612914,64818413 2026 88,777------827,612916,38918514 2027 90,552------827,612918,16518515 2028 92,364------827,612919,97618516 2029 94,211------827,612921,82318617 2030 96,095------827,612923,70718618 2031 98,017------827,612925,62918619 2032 99,977------827,612927,58918720 2033 101,977------827,612929,589187Present Worth855,250------8,700,0019,555,25096(% of PW)9.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 91.0% 100.0%Jim Bridger Unit 3ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 105,000----2,528,0122,528,0121,952,7964,585,8088432 2015 107,100----2,578,5732,578,5731,952,7964,638,4688533 2016 109,242----2,630,1442,630,1441,952,7964,692,1828634 2017 111,427----2,682,7472,682,7471,952,7964,746,9708735 2018 113,655----2,736,4022,736,4021,952,7964,802,8538836 2019 115,928----2,791,1302,791,1301,952,7964,859,8548937 2020 118,247----2,846,9532,846,9531,952,7964,917,9959048 2021 120,612----2,903,8922,903,8921,952,7964,977,2999159 2022 123,024----2,961,9702,961,9701,952,7965,037,78992610 2023 125,485----3,021,2093,021,2091,952,7965,099,48993711 2024 127,994----3,081,6333,081,6331,952,7965,162,42394912 2025 130,554----3,143,2663,143,2661,952,7965,226,61696113 2026 133,165----3,206,1313,206,1311,952,7965,292,09297314 2027 135,829----3,270,2543,270,2541,952,7965,358,87898515 2028 138,545----3,335,6593,335,6591,952,7965,427,00099816 2029 141,316----3,402,3723,402,3721,952,7965,496,4841,01017 2030 144,142----3,470,4193,470,4191,952,7965,567,3581,02318 2031 147,025----3,539,8283,539,8281,952,7965,639,6491,03719 2032 149,966----3,610,6243,610,6241,952,7965,713,3861,05020 2033 152,965----3,682,8373,682,8371,952,7965,788,5981,064Present Worth1,282,875----30,886,88630,886,88620,528,12252,697,883484(% of PW)2.4% 0.0% 0.0% 0.0% 0.0% 58.6% 58.6% 39.0% 100.0%EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls1 of 4Jim Bridger Unit 3LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 305,000-1,005,811--204,9841,210,7952,090,3043,606,0996102 2015 311,100-1,025,927--209,0841,235,0112,090,3043,636,4156153 2016 317,322-1,046,446--213,2651,259,7112,090,3043,667,3376204 2017 323,668-1,067,375--217,5311,284,9052,090,3043,698,8776265 2018 330,142-1,088,722--221,8811,310,6032,090,3043,731,0496316 2019 336,745-1,110,496--226,3191,336,8152,090,3043,763,8646377 2020 343,480-1,132,706--230,8451,363,5522,090,3043,797,3356428 2021 350,349-1,155,361--235,4621,390,8232,090,3043,831,4766489 2022 357,356-1,178,468--240,1711,418,6392,090,3043,866,29965410 2023 364,503-1,202,037--244,9751,447,0122,090,3043,901,81966011 2024 371,793-1,226,078--249,8741,475,9522,090,3043,938,04966612 2025 379,229-1,250,599--254,8721,505,4712,090,3043,975,00467213 2026 386,814-1,275,611--259,9691,535,5812,090,3044,012,69867914 2027 394,550-1,301,124--265,1691,566,2922,090,3044,051,14668515 2028 402,441-1,327,146--270,4721,597,6182,090,3044,090,36369216 2029 410,490-1,353,689--275,8811,629,5702,090,3044,130,36469917 2030 418,700-1,380,763--281,3991,662,1622,090,3044,171,16570518 2031 427,074-1,408,378--287,0271,695,4052,090,3044,212,78371319 2032 435,615-1,436,546--292,7681,729,3132,090,3044,255,23272020 2033 444,327-1,465,276--298,6231,763,8992,090,3044,298,531727Present Worth3,726,445-12,288,849--2,504,46414,793,31421,973,63240,493,391342(% of PW)9.2% 0.0% 30.3% 0.0% 0.0% 6.2% 36.5% 54.3% 100.0%Jim Bridger Unit 3LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 475,000-912,848600,000-1,269,7182,782,56612,326,23515,583,8011,7342 2015 484,500-931,105612,000-1,295,1132,838,21812,326,23515,648,9521,7413 2016 494,190-949,727624,240-1,321,0152,894,98212,326,23515,715,4071,7494 2017 504,074-968,722636,725-1,347,4352,952,88212,326,23515,783,1901,7565 2018 514,155-988,096649,459-1,374,3843,011,93912,326,23515,852,3291,7646 2019 524,438-1,007,858662,448-1,401,8713,072,17812,326,23515,922,8511,7727 2020 534,927-1,028,015675,697-1,429,9093,133,62212,326,23515,994,7831,7808 2021 545,626-1,048,575689,211-1,458,5073,196,29412,326,23516,068,1541,7889 2022 556,538-1,069,547702,996-1,487,6773,260,22012,326,23516,142,9931,79610 2023 567,669-1,090,938717,056-1,517,4313,325,42412,326,23516,219,3281,80511 2024 579,022-1,112,757731,397-1,547,7793,391,93312,326,23516,297,1901,81312 2025 590,603-1,135,012746,025-1,578,7353,459,77112,326,23516,376,6091,82213 2026 602,415-1,157,712760,945-1,610,3103,528,96712,326,23516,457,6161,83114 2027 614,463-1,180,866776,164-1,642,5163,599,54612,326,23516,540,2441,84015 2028 626,752-1,204,484791,687-1,675,3663,671,53712,326,23516,624,5241,85016 2029 639,287-1,228,573807,521-1,708,8743,744,96812,326,23516,710,4901,85917 2030 652,073-1,253,145823,671-1,743,0513,819,86712,326,23516,798,1751,86918 2031 665,115-1,278,208840,145-1,777,9123,896,26412,326,23516,887,6141,87919 2032 678,417-1,303,772856,948-1,813,4703,974,19012,326,23516,978,8421,88920 2033 691,985-1,329,847874,087-1,849,7404,053,67412,326,23517,071,8941,900Present Worth5,803,480-11,153,0437,330,712-15,513,23133,996,986129,575,495169,375,961942(% of PW)3.4% 0.0% 6.6% 4.3% 0.0% 9.2% 20.1% 76.5% 100.0%EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls2 of 4Jim Bridger Unit 3Upgraded Wet FGDYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 42,58329,927533,206-442,958204,9841,211,0751,236,6522,490,3106312 2015 43,43530,526543,870-451,818209,0841,235,2971,236,6522,515,3846373 2016 44,30331,136554,747-460,854213,2651,260,0031,236,6522,540,9586434 2017 45,18931,759565,842-470,071217,5311,285,2031,236,6522,567,0446505 2018 46,09332,394577,159-479,472221,8811,310,9071,236,6522,593,6526576 2019 47,01533,042588,702-489,062226,3191,337,1251,236,6522,620,7926647 2020 47,95533,703600,476-498,843230,8451,363,8681,236,6522,648,4756718 2021 48,91434,377612,486-508,820235,4621,391,1451,236,6522,676,7116789 2022 49,89335,065624,735-518,996240,1711,418,9681,236,6522,705,51368510 2023 50,89035,766637,230-529,376244,9751,447,3471,236,6522,734,89069211 2024 51,90836,481649,975-539,964249,8741,476,2941,236,6522,764,85570012 2025 52,94637,211662,974-550,763254,8721,505,8201,236,6522,795,41970813 2026 54,00537,955676,234-561,778259,9691,535,9361,236,6522,826,59471614 2027 55,08538,714689,758-573,014265,1691,566,6551,236,6522,858,39372415 2028 56,18739,488703,554-584,474270,4721,597,9881,236,6522,890,82873216 2029 57,31140,278717,625-596,164275,8811,629,9481,236,6522,923,91174017 2030 58,45741,084731,977-608,087281,3991,662,5471,236,6522,957,65674918 2031 59,62641,905746,617-620,249287,0271,695,7981,236,6522,992,07675819 2032 60,81942,744761,549-632,654292,7681,729,7141,236,6523,027,18576620 2033 62,03543,598776,780-645,307298,6231,764,3081,236,6523,062,995776Present Worth520,271365,6486,514,628-5,412,0002,504,46414,796,74112,999,90028,316,912358(% of PW)1.8% 1.3% 23.0% 0.0% 19.1% 8.8% 52.3% 45.9% 100.0%Jim Bridger Unit 3Flue Gas ConditioningYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 10,000-145,854--19,710165,564-175,5642752 2015 10,200-148,771--20,104168,875-179,0752803 2016 10,404-151,747--20,506172,253-182,6572864 2017 10,612-154,781--20,916175,698-186,3102925 2018 10,824-157,877--21,335179,212-190,0362986 2019 11,041-161,035--21,761182,796-193,8373047 2020 11,262-164,255--22,197186,452-197,7143108 2021 11,487-167,540--22,641190,181-201,6683169 2022 11,717-170,891--23,093193,985-205,70132210 2023 11,951-174,309--23,555197,864-209,81532911 2024 12,190-177,795--24,026201,822-214,01233512 2025 12,434-181,351--24,507205,858-218,29234213 2026 12,682-184,978--24,997209,975-222,65834914 2027 12,936-188,678--25,497214,175-227,11135615 2028 13,195-192,451--26,007218,458-231,65336316 2029 13,459-196,300--26,527222,827-236,28637017 2030 13,728-200,226--27,058227,284-241,01237718 2031 14,002-204,231--27,599231,830-245,83238519 2032 14,282-208,315--28,151236,466-250,74939320 2033 14,568-212,482--28,714241,195-255,764401Present Worth122,179-1,782,023--240,8142,022,837-2,145,015168(% of PW)5.7% 0.0% 83.1% 0.0% 0.0% 11.2% 94.3% 0.0% 100.0%EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls3 of 4Jim Bridger Unit 3Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 127,749--294,008-1,313,4741,607,4824,602,8876,338,1186,3812 2015 130,304--299,888-1,339,7441,639,6324,602,8876,372,8226,4163 2016 132,910--305,886-1,366,5391,672,4254,602,8876,408,2216,4514 2017 135,568--312,004-1,393,8701,705,8734,602,8876,444,3286,4885 2018 138,279--318,244-1,421,7471,739,9914,602,8876,481,1566,5256 2019 141,045--324,609-1,450,1821,774,7904,602,8876,518,7226,5637 2020 143,866--331,101-1,479,1861,810,2864,602,8876,557,0386,6018 2021 146,743--337,723-1,508,7691,846,4924,602,8876,596,1216,6409 2022 149,678--344,477-1,538,9451,883,4224,602,8876,635,9866,68110 2023 152,671--351,367-1,569,7231,921,0904,602,8876,676,6486,72211 2024 155,725--358,394-1,601,1181,959,5124,602,8876,718,1236,76312 2025 158,839--365,562-1,633,1401,998,7024,602,8876,760,4286,80613 2026 162,016--372,873-1,665,8032,038,6764,602,8876,803,5796,84914 2027 165,256--380,331-1,699,1192,079,4504,602,8876,847,5936,89415 2028 168,562--387,937-1,733,1022,121,0394,602,8876,892,4876,93916 2029 171,933--395,696-1,767,7642,163,4604,602,8876,938,2796,98517 2030 175,371--403,610-1,803,1192,206,7294,602,8876,984,9877,03218 2031 178,879--411,682-1,839,1812,250,8634,602,8877,032,6297,08019 2032 182,456--419,916-1,875,9652,295,8814,602,8877,081,2247,12920 2033 186,106--428,314-1,913,4842,341,7984,602,8877,130,7907,179Present Worth1,560,813--3,592,147-16,047,83819,639,98448,386,33369,587,1303,503(% of PW)2.2% 0.0% 0.0% 5.2% 0.0% 23.1% 28.2% 69.5% 100.0%EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls4 of 4EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 1 of 1First Year Cost for Air Pollution Control Options02,000,0004,000,0006,000,0008,000,00010,000,00012,000,00014,000,00016,000,00018,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRUpgraded WetFGDFlue GasConditioningFabric FilterAir Pollution Control Option

First Year Cost ($)EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 1 of 1Present Worth Cost for Air Pollution Control Options020,000,00040,000,00060,000,00080,000,000100,000,000120,000,000140,000,000160,000,000180,000,000LNB w/OFA ROFA LNB w/OFA &SNCRLNB w/OFA &SCRUpgraded WetFGDFlue GasConditioningFabric FilterAir Pollution Control Options

Present Worth Cost Over Year Plant Life ($)

# APPENDIX B



# 2006 Wyoming BART Protocol