# Final Report



# BART Analysis for

Jim Bridger Unit 1

Prepared For: 

# PacifiCorp

1407 West North Temple

Salt Lake City, Utah 84116



# December 2007

Prepared By:

215 South State Street, Suite 1000

Salt Lake City, Utah 84111

# Final Report



# BART Analysis for

Jim Bridger Unit 1

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 1 (hereafter referr ed to as Jim Bridger 1) . A BART analysis has

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

x 

# ), sulfur dioxide (SO 2 

# ),

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

# ). The Jim Bridger

Station consists of four 530-megawatt (MW) uni ts with a total genera ting capacity of 2,120 MW.

Because the total generating cap acity of the Jim Bridger Stat ion exceeds 750 MW, presumptive

BART limits apply to Jim Bridger 1, based on the United States Environmental Protection

Agency’s (EPA) guidelines. Best Available Retrofit Technology emissions limits must be

achieved within 5 years after the State Implemen tation Plan (SIP) is approved by the EPA. A

compliance date of 2014 was assumed for this analysis.

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

reductions in NO

x 

# , SO 2 

# , and PM 10 

# emissions rates were identified. The following technology

alternatives were investigat ed, listed below by pollutant:

• NO

x 

# emission controls:

− Low-NO

x 

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

− Rotating opposed fire air (ROFA)

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

− LNBs with selective catalytic reduction (SCR) system

• SO 2 

# emission controls:

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

− Upgrade wet sodium FGD system to achieve an SO 2 

# emission rate of 0.10 pound (lb) per

million British thermal units (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_JB1_OCT2007_FINAL.DOC ES-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 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. Th e evaluation must include:

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

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

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

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

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

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Available Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

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

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

applicability of options and their impacts)

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

• Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

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

• Step 5 – Evaluate Visibility Impacts

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

BART

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included in

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

BART implementation date.



# Coal Characteristics

The main source of coal burned at Jim Bri dger 1 will be the Bridger Underground Mine.

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

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC ES-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



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

x 

# formation. These

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

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

the higher nitrogen content and different combustion characteristics of PRB coals as compared to

those coals used at Jim Bridger 1, and has ev aluated the effect of these qualities on NO

x 

# formation and achievable emission rates.



# Recommendations

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

OFA, upgrading the existing FGD system, a nd operating the existing ESP with an SO 3 

# flue gas

conditioning system. This combination of contro l 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 the existing LNB with OFA as BART for Jim Bridger 1, based on the

projected significant reduction in NO

x 

# emissions, reasonable control costs, and the advantages of

no additional power requirements or non-air qu ality environmental impacts. Nitrogen oxide

reductions are expected to be similar to those realized at Jim Bridger 2. CH2M HILL

recommends that the unit be permitte d 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 1, 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 1, 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_JB1_OCT2007_FINAL.DOC ES-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# BART Modeling Analysis

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

from Jim Bridger 1 at Class I areas. The Class I ar eas potentially affected are located more than

50 kilometers, but less than 300 kilome ters, from the Jim Bridger Plant.

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

• 

# Bridger WA

• 

# Fitzpatrick WA

• 

# Mt. Zirkel WA

Because Jim Bridger 1 will simultaneously control NO

x 

# , SO 2 

# , and PM 10 

# emissions, four postcontrol atmospheric dispersion modeling scenar ios were developed 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 PacifiCorp’s preliminary BART selection.

• 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.

Visibility improvements for all emission control 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 Analysis 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 alternat ives is determined by generating what is called

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

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

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

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

above 0.5 dV were analyzed. This report provides a comparison of the average incremental costs

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC ES-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC ES-5 

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

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

# percentile delta-deciview ( Δ dV)

reduction.

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

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

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

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

higher costs. Scenario 3 (LNB with OFA and SCR, upgraded wet FGD, and flue gas

conditioning for enhanced ESP performance) is no t selected due to very high incremental costs,

on the basis of both a cost per day of improveme nt and cost per dV reduction. While Scenario 4

(LNB with OFA and SCR, upgraded wet FGD, a nd polishing fabric filter) provides some

potential visibility advantage over Scenario 1, the projected improvement is less than 0.5 dV,

and the projected costs are excessive. Therefore, Scenario 1 represents BART for Jim Bridger 1.



# Just-Noticeable Differences in Atmospheric Haze

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

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

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

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

expected under any of the cont rol scenarios. Thus, the resu lts indicate that even though

PacifiCorp will be spending many millions of dollars at this single unit, and over $1 billion when

considering its entire coal fleet , only minimal discernable visi bility improvements may result.

# Contents

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

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

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

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

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

3.2.1 BART NO

x 

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

3.2.2 BART SO 2 

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

3.2.3 BART PM 10 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

5.1.2 Analysis 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\JIMBRIDGER1AND2_FINALSUBMITTAL 

# iii

# CONTENTS (CONTINUED)

JMS EY102007001SLC\BART_JB1_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 Emission Rate Ranking

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 th e Bridger Class I Wilderness Area

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

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

5-4 Bridger Class I Wilderness Area Incremental Analysis Data

5-5 Fitzpatrick Class I Wilderness Area Incremental Analysis Data

5-6 Mt. Zirkel Class I Wilderness Area Incremental Analysis Data

Figures

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

3-2 Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART

NO

x 

# Limits

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

NO

x 

# Limits

3-4 First Year Control Cost for NO

x 

# Air Pollution Control Options

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

4-1 Jim Bridger Source-Specific 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 Degrees Fahrenheit

°C Degrees Celsius

BACT Best Availa ble Control Technology

BART Best Availabl e Retrofit Technology

CALDESK Program to Display Data and Results

CALMET Meteorological Data Pr eprocessing Program for CALPUFF

CALPOST Post-processing Program fo r Calculating Visibility Impacts

CALPUFF Gaussian Puff Dispersion Model

CFR Code of Federal Regulations

CO Carbon Monoxide

COHPAC Compact Hybrid Particulate Collector

dV Deciview

Δ dV Delta Deciview, Change in Deciview

EIA Energy Information Administration

ESP Electrostatic Precipitator

EPA United States Environmental Protection Agency

Fuel NO

x 

# Oxidation of Fuel-bound Nitrogen

FGC Flue Gas Conditioning

FGD Flue Gas Desulfurization

f (RH) Relative Humidity Factors

kW Kilowatt

LAER Lowest Achievable Emission Rate

lb Pound(s)

LNB Low-NO

x 

# Burner

LOI Loss on Ignition

MMBtu Million British Thermal Units

MM5 Mesoscale Meteorologi cal Model, Version 5

MW Megawatt

N 2 

# Nitrogen

NO

x 

# Nitrogen Oxide

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

OFA Over-fire Air

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 

# v

# ACRONYMS AND ABBREVIATIONS (CONTINUED)

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 

# vi 

# PM Particulate Matter

PM 10 

# Particulate Matter less than 10 Mi crometers in Aerodynamic Diameter

PM 2.5 

# Particulate Matter less than 2.5 Mi crometers in Aerodynamic Diameter

PRB Powder River Basin

ROFA Rotating Opposed Fire Air

S&L Sargent & Lundy

SCR Selective Catalytic Reduction

SIP State Implementation Plan

SNCR Selective Non-catalytic Reduction

SO 2 

# Sulfur Dioxide

SO 3 

# Sulfur Trioxide

Thermal NO

x 

# High Temperature Fixation of Atmos pheric Nitrogen in Combustion Air

TRC TRC Company, Inc.

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 Tec hnology (BART) guidelines were established as a result of

U.S. Environmental Protection Agency (EPA) re gulations intended to reduce the occurrence of

regional haze in national parks and other Class I protected air quality areas in the United States

(40 Code of Federal Regulations [CFR] Part 51) . These guidelines provide guidance for states

when determining which facilities must install addi tional controls, and the t ype of controls that

must be used. Facilities e ligible for BART installation were built between 1962 and 1977, and

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

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

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

December 15, 2006. PacifiCorp received an exte nsion from the WDEQ to submit the BART

report for Jim Bridger Unit 1 (hereafter referred to as Jim Bridger 1) by January 12, 2007. The

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

proposal and justification for BART at th e source. This revised report—submitted in

October 2007—incorporates edito rial revisions and new mode l runs since the January 2007

version.

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

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

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

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

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

of EPA’s approval of the SIP.

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

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

• The cost of the controls

• The remaining useful life of the source

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

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

such technology

This report documents the BART analysis that was performed on Jim Bridger 1 by

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

(NO

x 

# ), sulfur dioxide (SO 2 

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

diameter (PM 10 

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

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

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

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

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

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

Protocol.

JMS EY102007001SLC\BART_JB1_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 1 is a nominal 530 net MW unit located approximately

35 miles northeast of Rock Spri ngs, Wyoming. Unit 1 is equippe d with a tangentially fired,

pulverized-coal boiler with low-NO

x 

# burners (LNBs) manu factured by Combustion

Engineering. The unit was constructed with a Fl akt wire frame electrostatic precipitator (ESP).

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

three absorber towers installe d in 1990. An Emerson Ovation di stributed control system was

installed in 2006.

Jim Bridger 1 was placed in service in 1974. 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 1 of 20 years from the installation date of any new or modified

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

costs needed to allow the unit and these contro l devices at Jim Bridge r 1 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 pound per million British thermal units (lb per MMBtu) and the BART presumptive NO

x 

# limit for burning bituminous coal is 0.28 lb per MMB tu. The main sources of coal burned at

Jim Bridger 1 are the Bridger Mine and seconda rily the Black Butte Mine and Leucite Hills

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

coal in many of the parameters influencing NO

x 

# formation. These coals have higher nitrogen

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

sub-bituminous coal used in the U.S. This BA RT analysis has considered the higher nitrogen

content and the different combustion characteristic s of PRB coals, as compared to those coals

used at Jim Bridger 1, and has evaluate d the effect of these qualities on NO

x 

# formation and

achievable emission rates. Coal sources and ch aracteristics are summarized in Table 2-2. The

primary source of coal will be the Bridger Un derground Mine, and data on coal from this

source were used in the modeling analysis. For the coal analysis that is presented in Section 3,

the data from all the coal sources were used.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 2-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 2-2



# TABLE 2-1



# Unit Operation and Study Assumptions

Jim Bridger 1

General Plant Data

Site Elevation (feet above mean sea level) 6669

Stack Height (feet) 500

Stack Exit ID (feet) /Exi t Area (square feet) 24 /452.4

Stack Exit Temperature (degrees Fahrenheit) 140

Stack Exit Velocity (feet per second) 84.0

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

Latitude (degree: minute: second) 41:44:07 north

Longitude (degree: minute: second) 108:47:12 west

Annual Unit Capacity Fa ctor (percentage) 90

Net Unit Output (megawatts) 530

Net Unit Heat Rate (British thermal units (Btu) per kilowatthour)(100% load) 10,400 (as measured by fuel

throughput)

Boiler Heat Input (million Bt u (MMBtu) per hour)(100% load) 6,000 (as measured by continuous

emission monitoring)

Type of Boiler Tangentially fired

Boiler Fuel Coal

Coal Sources Bridger Mine, Black Butte Mine,

Leucite Hills Mine

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

# 9,660

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

# 0.58

Coal Ash Content (wt. %) (a) 

# 10.3

Coal Moisture Content (wt. %) (a) 

# 19.3

Coal Nitrogen Content (wt. %) (a) 

# 0.98

Current Nitrogen Oxide (NO

x 

# ) Controls Low-NO

x

# burners

NO

x 

# Emission Rate (lb/MMBtu) 0.45

Current Sulfur Dioxide (SO 2 

# ) Controls Sodium-based wet scrubber

SO 2 

# Emission Rate (lb/MMBtu) 0.267

Current PM 10 (b) 

# Controls Electrostatic Precipitator

PM 10 

# Emission Rate (lb/MMBtu) (c) 

# 0.045

NOTES:

(a) 

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

(b) 

# PM 10 

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

(c) 

# Based on maximum historic emission rate from 1999 to 2001, prior to installation of the sulfur trioxide

(SO 3 

# ) injection system.BART ANALYSIS FOR JIM BRIDGER UNIT 1TABLE 2-2Coal Sources and CharacteristicsJim Bridger 1Ultimate 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_JB1_OCT2007_FINAL.DOC2-3

# 3.0 BART Engineering Analysis

This section presents the requi red BART engineering analysis.



# 3.1 Applicability

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

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

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

implementation of BART emission controls on all BART eligible units, within 5 years after EPA

approval of the SIP.



# 3.2 BART Process

The specific steps in a BART engineering anal ysis are identified in 40 CFR 51, Appendix Y,

Section IV. The eval uation must include:

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

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

availability of options and their impacts)

• The costs of compliance with the control options

• The remaining useful life of the facility

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

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

BART

The following steps are incorporated into the BART analysis:

• Step 1 – Identify All Availabl e Retrofit Control Technologies

• Step 2 – Eliminate Technically Infeasible Options

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

− Consideration of any pollution control 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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# • Step 4 – Evaluate Impacts and Document the Results

− The costs of compliance with the control options

− The remaining useful life of the facility

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

• Step 5 – Evaluate Visibility Impacts

− The degree of visibility improvement that ma y reasonably be anticip ated from BART use

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

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

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

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

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

Separate analyses have been conducted for NO

x 

# , SO 2 

# , and PM 10 

# emissions. All costs included in

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

BART implementation date.



# 3.2.1 BART NO

x 

# Analysis

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

number of variables, including operating conditions, equipment desi gn, and coal characteristics.

Formation of NO

x



# During coal combustion, NO

x 

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

x 

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

x 

# ). During combustion, part of the

fuel-bound nitrogen is released from the coal with the volatile matte r, and part is retained in the

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

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

# ). A

smaller part of NO

x 

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

combustion air (thermal NO

x 

# ). A very small amount of NO

x 

# is called prompt NO

x 

# . Prompt NO

x 

# results from an intera ction of hydrocarbon radical s, 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 according 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 higher reactivity and lower nitrogen content. The fixed carbon to

volatile matter ratio (fuel ratio) , coal oxygen content, and rank are good relative indices of the

reactivity of a coal. Lower rank coals release more organically bound nitrogen earlier in the

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

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

nitrogen, and hence result in lower NO

x 

# emissions.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



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

low NO

x 

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

Administration (EIA), PRB coals currently represent 88 percent of total U.S. sub-bituminous

production and 73 percent of western coal pr oduction (Energy Information Administration,

2006). Most references to western coal and sub-bituminous coal infer PRB origin and

characteristics. Emissions standards differe ntiating between bitumi nous and sub-bituminous

coals are presumed to use PRB coal as the basi s for the sub-bituminous standards, due to its

dominant market presence a nd 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 1 as sub-bituminous rather than

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

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

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

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

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

surface area of the particle. Thus, with the application of heat, a gglomerating coals would tend to

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

more porous with combustion. As shown in Figur e 3-1, the increased porosity provides more

particle surface area, re sulting in more favorable combusti on 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 coal s is considered non-agglomerating, they either

do not exhibit those properties of non-agglomer ating 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 during combustion of the Bridger blends of coals.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# FIGURE 3-1



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

Jim Bridger 1



# 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 co al from Twentymile, which is a representative

western bituminous coal.

TABLE 3-1



# Coal Characteristics Comparison

Jim Bridger 1

Parameter Typical

Powder

River

Basin Bridger

Mine Black

Butte Leucite

Hills Twentymile

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

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

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# As shown in Table 3-1, although Bridger, Black Butte, and Leucite Hills are classified as

sub-bituminous, they all exhibit higher nitrogen content and lo wer oxygen content than the PRB

coal. The higher nitrogen content is an indication 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 LNBs and

over-fire air (OFA). Th ese characteristics indicate that higher NO

x 

# formation is likely with coal

from the Bridger, Black Butte, and Leucite Hills mi nes, rather than with PRB coal. The Bridger,

Black Butte, and Leucite Hills coals all contain qu ality characteristics that fall between a typical

PRB coal and Twentymile. Twentymile is a cl early 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 1, and i ndicates the average NO

x 

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

the same blend of coals as Jim Bridger 1, 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 1 would likely result in

performance and NO

x 

# emission rates comparable to those at Jim Bridger 2.

Figures 3-2 and 3-3 both demonstrate that for the Jim Bridger units with the TFS2000 low NO

x 

# emission system installed and burning a combina tion of the Bridger, Black Butte, and Leucite

Hill coals, the likely NO

x 

# emission rate will be closer to th e 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 these factors are consistent with th e observed sustainable

rate of 0.24 lb per MMBtu.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-5

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# FIGURE 3-2



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

x 

# Limits

Jim Bridger 1

PRB Subbituminous Bridger Blend

Jim Bridger 2 Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

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



# Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu



# FIGURE 3-3



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

x 

# Limits

Jim Bridger 1

PRB Subbituminous Twentymile Bituminous Bridger Blend

Jim Bridger 2

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

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



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



# JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



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

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

operational adjustments or changes to equipment. 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 pe rformance issues that are very

sensitive to both coal quality a nd combustion conditions, such as NO

x 

# formation. There is

significant variability in the quality of coals burne d at Jim Bridger 1. In a ddition to burning coal

from Black Butte and Leucite Hills, Jim Bridge r 1 burns coal supplied from the Bridger Mine

consisting of three sources: unde rground, surface, and hi ghwall operations. Each of these coal

sources has different quality char acteristics, 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 considerations that illustrate the co mplexity 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, burne rs, and pulverizers. If a performance requirement,

such as NO

x 

# emission limits, is subsequently changed, conflicts with other performance issues

can result.

Jim Bridger 1 is located at an altitude of 6,669 feet above sea level. At this elevation,

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

of 14.7 pounds per square inch. This lower pres sure means that less oxygen is available for

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

for efficient combustion, larger volumes of ai r are required. When ad justing air flows and

distribution to lower NO

x 

# using LNBs and OFA, original boile r design restrictions again limit the

modifications that can be made and still ach ieve satisfactory combustion performance.

Another significant factor in controlling NO

x 

# emissions is the fineness of the coal entering the

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

particles promote release of volatil es and assist char burnout due to more surface area exposed to

air. Nitrogen oxide reduction with high volatile co als is improved with greater fineness and with

proper air staging. The lower rank sub-bituminous co als such as PRB coals are quite friable and

easy to grind. Coals with lower Hardgrove Grinda bility Index values, such as those used at

Jim Bridger 1, are more difficult to grind and can cont ribute to higher NO

x 

# levels. In addition,

coal fineness can deteriorate ov er time periods between pulveri zer 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 1, the more applicable presumptive BART

limit is 0.28 lb per MMBtu. The BART analysis for NO

x 

# emissions from Jim Bridger 1 is further

described below.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 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 1, including those control t echnologies identified as Best

Available Control Technology (BACT) or lo west achievable emission rate (LAER) by

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

reviewed in an effort to identify potentia lly applicable emission control technologies.

Jim Bridger 1 NO

x 

# emissions 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 1, 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 regulator y presumptive limit (used as a guide) of 0.28 lb per MMBtu of

NO

x 

# . Jim Bridger 1 has an uncontrolled NO

x 

# emission rate of 0.45 lb per MMBtu.

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

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

Study). Updated cost estimates for SCR a nd SNCR were used (Sargent and 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 ammoni a, 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. Nitrogen oxide re ductions of up to 60 percent have been

achieved, although 15 to 30 percent is more real istic for most applications. Selective noncatalytic reduction is typically applied on sma ller units. Adequate reag ent distribution 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.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 3-2



# NO

x 

# Control Technology Emission Rate Ranking

Jim Bridger 1

Technology Projected Emission Rate

(pounds per million

British thermal units)

Presumptive Best Available Retrof it Technology (BART) Limit 0.28

Low-NO

x

# Burners (LNBs) with Over-fire Air (OFA) 0.24

Rotating Opposed Fire Air (ROFA) 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 porti ons of this BART analysis, may

be technically feasible and provide expected 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, emission rate values obtained in such preliminary proposals must be

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

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

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

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

x 

# with LNBs is to stage the

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

combustion is not diverted to combine with nitrogen and form NO

x 

# . Fuel-rich conditions favor

the conversion of fuel nitrogen to N 2 

# instead of NO

x 

# . Additional air (or OFA) is then introduced

downstream in a lower temperatur e zone to burn out the char.

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

LNB retrofits to units configured with tangentia l-firing such as Jim Bridger 1, it is generally

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

burners and reduces burner zone heat flux. Thes e modifications usually require boile r waterwall

tube replacement.

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

boiler vendors—indicates that new LNB and OFA re trofit at Jim Bridger 1 would result in an

expected NO

x 

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

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

rate can be sustained as an average between overh auls. This emission rate represents a significant

reduction from the current NO

x 

# emission rate, and is below th e more applicable presumptive

NO

x 

# emission rate of 0.28 lb per MMBtu.

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

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

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# more effectively for the combustion process. In addition, the swirling action reduces the

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

mixed more effectively.” A typical ROFA instal lation will 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 Hp fans

for Jim Bridger 1.

Mobotec expects 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 a dded to the expected rate due to Mobotec’s

limited ROFA experience with western sub- bituminous coals. Under the Mobotec proposal,

primarily based on ROFA equipment, the opera tion of existing LNB and OFA ports will be

analyzed. While a typical installation does not require modification to the existing LNB system,

and the existing OFA ports are not used, result s of computational fluid dynamics modeling will

determine the quantity and locat ion of new ROFA ports. The M obotec proposal includes bent

tube assemblies for OFA port installation. Mobo tec does not provide in stallation services,

because they believe that the Owner can more cost effectively contract for these services.

However, they do provide one onsite constructio n supervisor during in stallation and startup.

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

x 

# reductions

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

urea—is injected into the fu rnace within a temperature rang e of 1,600°F to 2,100°F, where it

reduces NO

x 

# to nitrogen and water. Nitrogen oxide re ductions of up to 60 percent have been

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

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

x 

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

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

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

downstream. The ammonia may render fly ash unsaleable , react with sulfur to foul heat exchange

surfaces, and/or create a visible st ack 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 reagen t consumption. To reduce reagent costs, S&L has

assumed that combustion modifications includ ing LNBs and advanced OFA are capable of

achieving a projected NO

x 

# emission rate of 0.24 lb per MMBtu

. A further reduction of 15 percent

in NO

x 

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

SCR. SCR works on the same chemical principle as SNCR but SCR uses a catalyst to promote

the chemical reaction. Ammonia is injected in to the flue-gas stream , where it reduces NO

x 

# to

nitrogen and water. Unlike the high temperatur es required for SNCR, in SCR the reaction takes

place on the surface of a vanadi um/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 the

catalyst is located downstream from the boiler ec onomizer and upstream of the air heater and any

particulate control equipment. In this location, the SCR is exposed to the full concentration of fly

ash in the flue gas that is leaving the boile r. The high-dust configuration is assumed for

Jim Bridger 1. In a full-scale SCR, the flue ducts are routed to a separate large reactor containing

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-10

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 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 fl ue gas flow velocity and increase flue gas

residence time. Due to the highe r removal rate, a full-scale S CR was used as the basis for

analysis at Jim Bridger 1.

Sargent and Lundy prepared the design conditions and cost estimates for SCR at Jim Bridger 1.

As with SNCR, it is generally more cost effective to reduce NO

x 

# emission levels as much as

possible through combustion modifications, in or der to minimize the catalyst surface area and

ammonia requirements of the SCR. The S&L desi gn basis 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 1.

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. This variance can be attributed to 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.

• Review and evaluate unit physical and operationa l characteristics and restrictions. The fewer

variations there are in operations, coal supply, etc., the mo re 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 consider ation of energy, environmental, and economic impacts associated

with each control technology. The re maining 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 efficien cy or forced draft fan power usage. Therefore,

these technologies will not have energy impacts.

The Mobotec ROFA system requires installati on and operation of two 4,000 to 4,300 horsepower

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

530 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 catalyst, which is typically a 6- to 8-inch water gage

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-11

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-12 

# increase. Total additional power requirements for SCR installation at Jim Bridger 1 are estimated

at approximately 3,280 kW, based on the S&L Study.

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

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

or lower than prior levels for the ROFA system.

The installation of SNCR and SCR could impact the saleability and disposal of fly ash due to

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

visibility improvements. Other environmenta l impacts involve the storage of ammonia,

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

plant site.

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

to CH2M HILL by PacifiCorp, developed using S&L’s internal proprietary database, and

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

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

system was obtained from Mobotec.

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 the first year contro l costs are shown in

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

TABLE 3-3



# NO

x 

# Control Cost Comparison

Jim Bridger 1

Factor Low-NO

x 

# Burners

(LNBs) with

Over-fire Air

(OFA) Rotating

Opposed Fire

Air (ROFA) LNB with

OFA and

Selective

Non-catalytic

Reduction

(SNCR) LNB with OFA

and Selective

Catalytic

Reduction

(SCR)

Total Installed Capital Costs $8.7 million $20.5 million 22.1 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) 0 6.4 0.5 3.3

Annual Power Usage

(1,000 megawatt-hours per year) 0 50.6 4.2 25.8

Nitrogen Oxide (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

First Year Average Control Cost

(dollars per ton [$/Ton] of NO

x

# Removed) $181/ton $843/ton $613/ton $1,736/ton

Incremental Control Cost

($/Ton of NO

x 

# Removed) $181/ton $7,797/ton $2, 885/ton $3,894/tonBART ANALYSIS FOR JIM BRIDGER UNIT 1FIGURE 3-4First Year Control Cost for NOxAir Pollution Control OptionsJim Bridger 101,0002,0003,0004,0005,0006,0007,0008,0009,000LNB 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_JB1_OCT2007_FINAL.DOC3-13

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# Preliminary BART Selection. PacifiCorp selects LNBs with OFA as BART for Jim Bridger 1

based on its signifi cant reduction in NO

x 

# emissions, reasonable control cost, and no additional

power requirements or environmental impact s. This scenario 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 bituminous coal presumptive limit of 0.28 lb per MMBtu and the

0.15 lb per MMBtu limit for sub-bituminous coal, wh ich, as discussed in the section on coal

quality, is appropriate for this unit.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.



# 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 1 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 1; th is 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 1 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.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-14

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 3-4



# SO 2 

# Control Technology Emission Rates

Jim Bridger 1

Technology Projected Emission Rate

(pounds per million British

thermal units)

Presumptive Best Available Retrof it Technology (BART) 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.

The wet sodium FGD system at Jim Bridger 1 currently achie ves approximately 78 percent

SO 2 

# removal to achieve an SO 2 

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

existing wet FGD system is projected to achieve an SO 2 

# outlet emission rate of 0.20 lb per

MMBtu (83.3 percent SO 2 

# removal). Optimization would be accomplished by partially closing

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

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

scaling problems.

Upgrading the wet FGD system would achieve an SO 2 

# outlet emission rate of 0.10 lb per

MMBtu (91.7 percent SO 2 

# removal). Upgrading the system would involve closing the bypass

damper to eliminate the 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 and drains for

wet operation, and using a refined soda ash reagent. It is considered to be technically infeasible

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

# removal (0.06 lb per MMBtu) on a

continuous basis since this high le vel of removal must be incorpor ated into the original design

of the scrubber.

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

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

MMBtu of SO 2 

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

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

of 0.10 lb per MMBtu (91.7 percent SO 2 

# removal), which would meet the presumptive limit of

0.15 lb per MMBtu of SO 2 

# for Jim Bridger 1.

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-15

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 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 1. 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 per MMBtu of SO 2 

# , and is eliminated from further analysis.

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 1 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 1 would

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

# limit of 0.15 lb per

MMBtu.

Step 4: Evaluate Impacts and Document the Results

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

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

considered during the evaluation.

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

530 kW of power.

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

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

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

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

# removed for the upgraded wet

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

Appendix A.

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

system as BART for Jim Bridger 1, based on significant reduction in SO 2 

# emissions (meeting

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

minimal additional power requirements and environmental impacts.

Step 5: Evaluate Visibility Impacts

Please see Section 4, BART Modeling Analysis.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-16

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 3-5



# SO 2 

# Control Cost Comparison (Incremental to Existing FGD System)

Jim Bridger 1

Factor Upgraded Wet 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) 0.5

Additional Annual Power Usage

(1,000 megawatt-hours per year) 4.2

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



# 3.2.3 BART PM 10



# Analysis

Jim Bridger 1 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 1 has

controlled PM 10 

# emissions to levels below 0.045 lb per MMBtu.

The BART analysis for PM 10 

# emissions at Jim Bridger 1 is described below. For the modeling

analysis in Section 4, PM 10 

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

# includes particulate

matter less than 2.5 micrometers in aerodynamic diameter (PM 2.5 

# ) as a subset.

Step 1: Identify All Availabl e Retrofit Control Technologies

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.

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

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

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-17

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# Step 2: Eliminate Technically Infeasible Options

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

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

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

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

# ), will

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

collect the ash more effectively. Flue gas conditioning systems can account for large

improvements in collection efficiency for small ESPs. Therefore, the technology is retained as

technically feasible.

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

at Jim Bridger 1. 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). This technol ogy is retained as te chnically feasible.

Step 3: Evaluate Control Effectiven ess of Remaining Control Technologies

The existing ESP at Jim Bridge r 1 is achieving a controlled PM emission rate of 0.045 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.

The PM 10 

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

TABLE 3-6



# PM 10



# Control Technology Emission Rates

Jim Bridger 1

Control Technology Short-Term Expected PM 10 (a) 

# Emission Rate

(pounds per million Br itish 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.

A COHPAC fabric filter at Jim Bridger 1 would require a pproximately 3.4 MW of power,

equating to an annual power usage of approximately 26.7 million kW hours.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-18

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 3-19 

# 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 either

a COHPAC polishing fabric filter or FGC system.

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

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

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

TABLE 3-7



# PM 10



# Control Cost Comparison (Incremental to Existing ESP)

Jim Bridger 1

Factor Flue Gas

Conditioning Polishing Fabric Filter

Total Installed Capital Costs $0 $48.4 million

Total First Year Fixed and Variable Operation and

Maintenance Costs $0.2 million $1.8 million

Total First Year Annualized Cost $0.2 million $6.4 million

Additional Power Consumption (megawatts) 0.05 3.4

Additional Annual Power Usage

(1,000 megawatt-hours per year) 0.4 26.7

Incremental Particulate Matter (PM) Design Control

Efficiency 33.3% 66.7%

Incremental Tons PM Removed per Year 355 710

First Year Average Control Cost

(dollars per ton [$/Ton] of PM Removed) 495 8,973

Incremental Control Cost

($/Ton of PM Removed) 495 17,452



# Preliminary BART Selection. PacifiCorp selects FGC as BART for Jim Bridger 1 based on its

significant reduction in PM emissions, reasona ble control cost, minimum 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 1FIGURE 3-5First Year Control Cost for PM Air Pollution Control OptionsJim Bridger 102,0004,0006,0008,00010,00012,00014,00016,00018,00020,000Flue Gas ConditioningFabric FilterAir Pollution Control Option

Control Cost ($/Ton PM Removed)First Year Average Control CostFirst Year Incremental Control CostJMS EY102007001SLC\BART_JB1_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 1 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 1 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 1 f acility and allow for a 50-kilometer buffer around

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

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

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

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

WDEQ-AQD BART Modeling Protocol, a copy of which is included in this report 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_JB1_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 1



# 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 1

CALMET Input Parameter Value

CALMET Input Group 2

Map projection (PMAP) Lambert Conformal

Grid spacing (DGRIDKM) 4

Number vertical layers (NZ) 10

Top of lowest layer (m) 20

Top of highest layer (m) 3500

CALMET Input Group 4

Observation mode (NOOBS) 0

CALMET Input Group 5

Prog. Wind data (IPROG) 14

(RMAX1) 30

(RMAX2) 50

Terrain influence (TERRAD) 15

(R1) 5

(R2) 25

CALMET Input Group 6

Max mixing ht (ZIMAX) 3500



# 4.2.2 CALMET Input Data

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

WDEQ-AQD provided 12-kilomete r resolution Mesoscale Meteor ological Model, Version 5

(MM5) meteorological data fields that covered the entire mode ling domain for each study year.

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

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

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

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-4 

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

wind field.

Surface data for 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 I USGS

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

properties such as albedo, Bowen ratio, roughne ss length, and leaf area index were computed

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

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

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

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

fixed-length, TD-3240 format were obtained fo r the modeling domain. The list of available

stations that have collected complete data varies by year, but CH2M HILL processed all

available stations/data within the domain for each year. Precipitation data were prepared with

the PXTRACT/PMERGE processors in preparation for use within CALMET.

Upper-air data were prepared for the CALM ET model with the READ62 preprocessor for the

following stations:

• Denver, Colorado

• Salt Lake City, Utah

• Riverton, Wyoming

• Rapid City, South Dakota

Figure 4-2 shows the locations of surface and upper air stations within the MM5 modeling

domain.



# 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).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 1



# 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 1.



# 4.3.1 Background Ozone and Ammonia

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

calculation of SO 2 

# and NO

x 

# transformation with the MESOPUFF II chemical transformation

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

the modeling domain for 2001, 2002, and 2003:

• Rocky Mountain National Park, Colorado

• Craters of the Moon National Park, Idaho

• Highland, Utah

• Thunder Basin National Grasslands, Wyoming

• Yellowstone National Park, Wyoming

• Centennial, Wyoming

• Pinedale, Wyoming

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

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

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



# 4.3.2 Stack Parameters

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

current permit for Jim Bridger 1. 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.



# 4.3.3 Emission Rates

Pre-control emission rates for Jim Bridger 1 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 repr esentative. Allowable short-term (24-hour or shorter period)

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-7 

# emissions or short-term emission limits were used if continuous em ission monitoring data

were not available.

Emissions were modeled for the following pollutants:

• 

# SO 2



# • 

# NO

x



# • 

# Coarse particulate (PM 2.5 

# <diameter<PM 10 

# )

• 

# Fine particulate (diameter<PM 2.5 

# )

• 

# Sulfates

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

consideration. Modeled pollutants were the same as those listed for the 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 ba sed 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 and 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 solution will include a combination of control technologies for NO

x 

# , SO 2 

# , and PM.

Table 4-2 presents the stack parameters and emi ssion rates used for the Jim Bridger 1 analysis

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

protocol, elemental carbon stack emissions and organic aerosol emissi ons were not modeled.TABLE 4-2BART Model Input DataJim Bridger 1BaselinePost-control Scenario 1Post-control Scenario2 Post-control Scenario 3 Post-control Scenario 4Current Operations withWet Flue GasDesulfurization (FGD) andElectrostatic Precipitator(ESP)Low-NOxBurner (LNB) with Over-fireAir (OFA), Upgrade Wet FGD, and FlueGas Conditioning (FGC) for EnhancedESP PerformanceLNB with OFA, Upgrade WetFGD, New Fabric FilterLNB with OFA and SelectiveCatalytic Reduction (SCR),Upgrade Wet FGD, and FGCfor Enhanced ESPPerformanceLNB with OFA and SCR,Upgrade Wet FGD, NewFabric FilterSulfur Dioxide (SO2) StackEmissions pounds per hour (lb/hr)1,602600600600600Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 2,7001,4401,440420420PM10Stack Emissions (lb/hr)270 180 90.0 180 90.0Coarse Particulate (PM2.5<diameter<PM10) Stack Emissions (lb/hr)(a)116 77.4 51.3 77.4 51.3Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b)154 103 38.710338.7Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 55.2 55.2 55.2 94.8 94.8H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) 54.1 54.1 54.1 92.9 92.9Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr)7.027.02(NH4)2SO4as SO4Stack Emissions (lb/hr)5.105.10(NH4)HSO4Stack Emissions (lb/hr)12.212.2(NH4)HSO4as SO4Stack Emissions (lb/hr)10.210.2Total 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)333322333333333Stack Exit Velocity (meters per second)(c)25.624.727.427.427.4NOTES:(a)Based on AP-42, Table 1.1-6, the coarse particulates are countedas a percentage of PM10. This equates to 43 percent ESP and 57 percent Baghouse. PM10and PM2.5refer to particulate matter less than 10 and 2.5micrometers, respectively, in aerodynamicdiameter.(b)Based on AP-42, Table 1.1-6, the fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent Baghouse.(c)Scenarios 2, 3, and 4 were not remodeled atthe lower, correct velocity of 81.24 feet per second due to lack of time and the fact that the conclusions to select Scenario 1 would not have changed.Total Sulfate (SO4) (lb/hr) = H2SO4as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4as SO4Stack Emissions (lb/hr) + (NH4)HSO4as SO4Stack Emissions (lb/hr)

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 4.3.5 Modeling Process

The CALPUFF modeling for the control technology options for Jim Bridger 1 followed this

sequence:

• 

# Model pre-control (baseline) emissions

• 

# Model preferred post-control scenario (if applicable)

• 

# Determine degree of visibility improvement

• 

# Model other control scenarios

• 

# Determine degree of visibility improvement

• 

# Factor visibility results into the BART five-step evaluation



# 4.3.6 Receptor Grids

Discrete receptors for the CALPUFF modeling we re placed at uniform receptor spacing along

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

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

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

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

locations.



# 4.4 CALPOST

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

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

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

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

pollutant, as shown below, were used:

• 

# Ammonium sulfate 3.0

• 

# Ammonium nitrate 3.0

• 

# PM coarse (PM 10 

# ) 0.6

• 

# PM fine (PM 2.5 

# ) 1.0

• 

# Organic carbon 4.0

• 

# Elemental carbon 10.0

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

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

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

Air Modeling Protocol (Appe ndix B) lists the monthly f (RH) factors for the Class I areas.

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

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

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

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

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

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

by scaling back the annual average species concentrations give n in Table 2-1 of Guidance for

Estimating Natural Visibility Conditi ons Under the Regional Haze Rule (EPA, 2003). A

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-10 

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

Guidance table annual concentrations, the 20 perc ent best days dV value for that area would

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

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

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

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

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

TABLE 4-3



# Average Natural Levels of Aerosol Components

Jim Bridger 1

Aerosol Component Average Natural Concentration

(micrograms per cubic meter)

for Mt. Zirkel Class I

Wilderness Area Average Natural Concentration

(micrograms per cubic meter)

for Fitzpatrick and Bridger Class I

Wilderness Areas

Ammonium Sulfate 0.046 0.045

Ammonium Nitrate 0.038 0.038

Organic Carbon 0.179 0.178

Elemental Carbon 0.008 0.008

Soil 0.190 0.189

Coarse Mass 1.141 1.136

NOTES:

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



# 4.5 Presentation of Modeling Results

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

for Jim Bridger 1.



# 4.5.1 Visibility Changes for Baseline vs. Preferred Scenario

CH2M HILL modeled Jim Bridger 1 for the base line and the post-control scenarios. The postcontrol scenario include d emission rates for SO 2 

# , NO

x 

# , and PM 10 

# that would be achieved if

BART state-of-the-art technol ogy were installed on Unit 1.

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 1TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasJim Bridger 1ModelingResultsScenarioTotal First YearAnnualized CostClass I AreaHighest DeltaDeciview (ΔdV)98thPercentile(ΔdV)Number(No.) ofDaysAbove0.5 dVCost per dVReductionCost perReduction inNo. of DaysAbove0.5 dVIncrementalCost per dVReductionIncrementalCost perReductionin No. ofDaysAbove0.5 dV2001Bridger WA2.5040.74614----Fitzpatrick WA2.1770.4187----Baseline: Current Operation with Wet FlueGas Desulfurization (FGD), ElectrostaticPrecipitator (ESP)Mt. Zirkel WA1.9661.23627----$3,392,440BridgerWA1.3640.3847$9,371,381$484,634$3,392,440FitzpatrickWA1.3690.2213$17,220,508$848,110Scenario 1: Low-NOxBurners (LNBs) with Over-fire Air (OFA), upgrade wet FGD, Flue GasConditioning (FGC) for enhanced ESP performance$3,392,440Mt. Zirkel WA1.1670.73616$6,784,880$308,404$9,759,059BridgerWA1.3930.3726$26,093,741$1,219,882$530,551,575$6,366,619$9,759,059FitzpatrickWA1.1710.2113$47,145,212$2,439,765$636,661,890n/aScenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter$9,759,059Mt. Zirkel WA1.0990.67615$17,426,891$813,255$106,110,315$6,366,619$18,093,916BridgerWA0.8760.2793$38,745,002$1,644,901$89,622,116$2,778,286$18,093,916FitzpatrickWA0.6750.1271$62,178,405$3,015,653$99,224,485$4,167,428Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR), upgrade wet FGD, FGCfor enhanced ESP performance$18,093,916Mt. Zirkel WA0.7560.4535$23,108,449$822,451$37,376,039$833,486$24,460,535BridgerWA0.8380.2683$51,172,667$2,223,685$578,783,537n/a$24,460,535FitzpatrickWA0.6540.1251n/a$4,076,756$3,183,309,451n/aScenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter$24,460,535Mt. Zirkel WA0.7290.4362$30,575,668$978,421$374,506,994$2,122,2062002Bridger WA4.1041.44826----Fitzpatrick WA1.8940.70411----Baseline: Current Operation with Wet FGD, ESPMt. Zirkel WA2.8011.49634----$3,392,440Bridger WA2.4540.84514$5,625,937$282,703$3,392,440FitzpatrickWA1.0780.3785$10,406,258$565,407Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance$3,392,440Mt. Zirkel WA1.5440.81613$4,988,882$161,545$9,759,059Bridger WA2.3260.78013$14,609,370$750,697$97,947,983$6,366,619$9,759,059FitzpatrickWA1.0020.3476$27,336,300$1,951,812$205,374,803n/aScenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter$9,759,059Mt. Zirkel WA1.4960.77713$13,573,100$464,717$163,246,639n/a$18,093,916Bridger WA1.3210.5199$19,476,766$1,064,348$31,934,317$2,083,714$18,093,916FitzpatrickWA0.5490.2261$37,853,380$1,809,392$68,883,114$1,666,971Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance$18,093,916Mt. Zirkel WA0.8870.4734$17,687,112$603,131$27,417,292$926,095$24,460,535Bridger WA1.2950.5008$25,802,252$1,358,919$335,085,205$6,366,619$24,460,535FitzpatrickWA0.5390.2231$50,853,502$2,446,053$2,122,206,301n/aScenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter$24,460,535Mt. Zirkel WA0.8690.4654$23,725,058$815,351$795,827,363n/aJMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC4-11BART ANALYSIS FOR JIM BRIDGER UNIT 1JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC4-12TABLE 4-4Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I AreasJim Bridger 1ModelingResultsScenarioTotal First YearAnnualized CostClass I AreaHighest DeltaDeciview (ΔdV)98thPercentile(ΔdV)Number(No.) ofDaysAbove0.5 dVCost per dVReductionCost perReduction inNo. of DaysAbove0.5 dVIncrementalCost per dVReductionIncrementalCost perReductionin No. ofDaysAbove0.5 dV2003Bridger WA1.7060.761 16 ----Fitzpatrick WA1.9330.373 7----Baseline: Current Operation with wet FGD, ESPMt. Zirkel WA1.9581.232 35 ----$3,392,440Bridger WA0.9970.411 5 $9,692,686$308,404$3,392,440 FitzpatrickWA 1.112 0.199 2 $19,496,782 $678,488Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance$3,392,440Mt. Zirkel WA1.0420.736 16 $17,854,948 $178,549$9,759,059Bridger WA0.9850.408 5 $27,646,059 $887,187 $2,122,206,301 n/a$9,759,059 FitzpatrickWA1.087 0.186 2 $52,187,481 $1,951,812 $489,739,916 n/aScenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter$9,759,059Mt. Zirkel WA1.0570.686 15 $17,873,734 $487,953 $127,332,378 $6,366,619$18,093,916Bridger WA0.8530.258 3 $35,971,999$1,391,840 $55,565,712 $4,167,428$18,093,916 FitzpatrickWA0.681 0.118 2 $70,956,532 $3,618,783 $122,571,423 n/aScenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance$18,093,916Mt. Zirkel WA0.6690.433 5$22,645,702 $603,131$32,944,098 $833,486$24,460,535Bridger WA0.8100.248 3 $47,681,354 $1,881,580 $636,661,890 n/a$24,460,535 FitzpatrickWA0.662 0.114 2 $94,442,219 $4,892,107 $1,591,654,726 n/aScenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter$24,460,535Mt. Zirkel WA0.6360.422 5$30,198,191 $815,351$578,783,537 n/a3-year AveragesBridger WA0.985 18.7Fitzpatrick WA0.498 8.3Baseline: Current Operation with wet FGD, ESPMt. Zirkel WA1.321 32.0$3,392,440Bridger WA0.5478.7 $7,739,407 $339,244$3,392,440Fitzpatrick WA0.2663.3 $14,601,607 $678,488Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance$3,392,440Mt. Zirkel WA0.763 15.0 $6,072,387 $199,555$9,759,059Bridger WA0.520 8.0 $20,987,224 $914,912 $238,748,209 $9,549,928$9,759,059Fitzpatrick WA0.248 3.7$38,984,257 $2,091,227 $353,701,050 n/aScenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter$9,759,059Mt. Zirkel WA0.713 14.3 $16,042,289 $552,400 $128,186,958 $9,549,928$18,093,916Bridger WA0.352 5.0 $28,584,385 $1,323,945 $49,612,243 $2,778,286$18,093,916Fitzpatrick WA0.157 1.3 $53,009,519 $2,584,845 $91,591,833 $3,572,081Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance$18,093,916Mt. Zirkel WA0.453 4.7$20,837,523 $661,973$32,057,141 $862,227$24,460,535 BridgerWA 0.339 4.7 $37,845,077$1,747,181 $477,496,418 $19,099,857$24,460,535 FitzpatrickWA 0.154 1.3 $71,037,371 $3,494,362$2,122,206,301 n/aScenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter$24,460,535Mt. Zirkel WA0.441 3.7 $27,785,537 $863,313 $530,551,575 $6,366,619NOTES:Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $3,392,440 / (0.7964 - 0.427) = $9,193,605Sample Calculations: Cost per Reduction in No. of DaysExceeding 0.5 dV for 2001: = $3,392,440 / (20 - 7) = $260,957

# 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 1, 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, hereafter referred to as the NSR

Manual).



# 5.1 Least-cost Envelope Analysis

The total annualized cost, cost per dV reduction, and cost per reduction in number of days

above 0.5 dV for the scenarios modeled in Sect ion 4 to determine the impact on the three

Class I areas are listed in Tables 5-1 thr ough 5-3. A comparison of the incremental costs

between relevant scenarios is shown in Tables 5-4 through 5-6. The total annualized cost

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

# percentile Δ dV

reduction are shown in Figures 5-1 to 5-6 for the three Class I areas.



# 5.1.1 Analysis Methodology

On page B-41 of the NSR Manual, EPA stat es that “Incremental cost-effectiveness

comparisons should focus on annualized cost and emission reduction differences between

dominant alternatives. Dominant set of cont rol alternatives are determined by generating

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

annualized costs for a total emissions reductions fo r all control al ternatives 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 costeffectiveness 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 1.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-1

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



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

number of days above 0.5 dV. 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 an inferior control, because Scenario 1 provides approximately the

same amount of visibility impact reduction fo r less cost than Scenar io 2. The incremental

cost effectiveness is determined by the di fference in total annual costs between 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 1

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),

and Electrostatic

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

1 Low-NO

x

# Burners (LNBs)

with Over-fire Air (OFA),

Upgrade Wet FGD, and

Flue Gas Conditioning

(FGC) for Enhanced ESP

Performance 0.44 10.0 $3.4 $7.7 $0.3

2 LNB with OFA, Upgrade

Wet FGD, New Fabric

Filter 0.47 10.7 $9.8 $21.0 $0.9

3 LNB with OFA and

Selective Catalytic

Reduction (SCR),

Upgrade Wet FGD, and

FGC for Enhanced ESP

Performance 0.63 13.7 $18. 1 $28.6 $1.3

4 LNB with OFA and SCR,

Upgrade Wet FGD, New

Fabric Filter 0.65 14.0 $24. 5 $37.8 $1.7

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-2

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 5-2



# Control Scenario Results for the Fitzpatrick Class I Wilderness Area

Jim Bridger 1

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) and Electrostatic

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

1 Low-NO

x

# Burner (LNB) with

Over-fire Air (OFA),

Upgrade Wet FGD, and

Flue Gas Conditioning

(FGC) for Enhanced ESP

Performance 0.23 5.0 $3.4 $14.6 $0.7

2 LNB with OFA, Upgrade

Wet FGD, New Fabric Filter 0.25 4.7 $9.8 $39.0 $2.1

3 LNB with OFA and

Selective Catalytic

Reduction (SCR), Upgrade

Wet FGD, and FGC for

Enhanced ESP

Performance 0.34 7.0 $18.1 $53.0 $2.6

4 LNB with OFA and SCR,

Wet FGD, Fabric Filter 0.34 7.0 $24.5 $71.0 $3.5

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-3

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 5-3



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

Jim Bridger 1

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) and Electrostatic

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

1 Low-NO

x

# Burner (LNB) with

Over-fire Air (OFA),

Upgrade Wet FGD, and

Flue Gas Conditioning

(FGC) for Enhanced ESP

Performance 0.56 17.0 $3.4 $6.1 $0.2

2 LNB with OFA, Upgrade

Wet FGD, New Fabric Filter 0.61 17.7 $9.8 $16.0 $0.6

3 LNB with OFA and

Selective Catalytic

Reduction (SCR), Upgrade

Wet FGD, and FGC for

Enhanced ESP

Performance 0.87 27.3 $18. 1 $20.8 $0.7

4 LNB with OFA and SCR,

Upgrade Wet FGD, New

Fabric Filter 0.88 28.3 $24. 5 $27.8 $0.9

TABLE 5-4



# Bridger Class I Wilderness Area Incremental Analysis Data

Jim Bridger 1

Options Compared Incremental

Reduction in

Days Above

0.5 deciview

(dV) (Days) Incremental dV

Reductions

(dV) Incremental Cost

Effectiveness

(Million$/Days) Incremental

Cost

Effectiveness

(Million$/dV)

Baseline and Scenario 1 10.0 0.44 $0.3 $7.7

Scenario 1 and Scenario 2 0.7 0.03 $9.5 $238.7

Scenario 1 and Scenario 3 3.7 0.19 $4.0 $75.5

Scenario 1 and Scenario 4 4.0 0.21 $5.3 $101.3

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-4

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# TABLE 5-5



# Fitzpatrick Class I Wilderness Area Incremental Analysis Data

Jim Bridger 1

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 5.0 0.23 $0.7 $14.6

Scenario 1 and Scenario 2 n/a 0.02 n/a $353.7

Scenario 1 and Scenario 3 2.0 0.11 $7.4 $134.9

Scenario 1 and Scenario 4 2.0 0.11 $10.5 $188.1

TABLE 5-6



# Mt. Zirkel Class I Wilderness Area Incremental Analysis Data

Jim Bridger 1

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 $0.2 $6.1

Scenario 1 and Scenario 2 0.7 0.05 $9.5 $128.2

Scenario 1 and Scenario 3 10.3 0.31 $1.4 $47.5

Scenario 1 and Scenario 4 11.3 0.32 $1.9 $65.5

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-5

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# FIGURE 5-1



# Least-cost Envelope Bridger Class I WA Days Reduction

Jim Bridger 1

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

$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 1

g

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



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



# JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-6

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# FIGURE 5-3



# Least-cost Envelope Fitzpatrick Class I WA Days Reduction

Jim Bridger 1

Scenario 4

Baseline Scenario 1 Scenario 2 Scenario 3

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

012345678



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



# FIGURE 5-4



# Least-cost Envelope Fitzpatrick Class I WA 98 th



# Percentile Reduction

Jim Bridger 1

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_JB1_OCT2007_FINAL.DOC 5-7

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# FIGURE 5-5



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

Jim Bridger 1

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 1

Scenario 3

Scenario 2

Scenario 1

Baseline Scenario 4

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

0.00 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_JB1_OCT2007_FINAL.DOC 5-8

# BART ANALYSIS FOR JIM BRIDGER UNIT 1



# 5.1.2 Analysis Results

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

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

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

the dominant control alternative scenarios, whic h indicates a scenario with lower improvement

and/or higher costs. Scenario 3 is not selected due to very high incremental costs on the basis of

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

some potential visibility advantage over Scenario 1, the projected improvement is less than half

a dV, and the projected costs are excessive.

Analysis of the results for the Jim Bridger WA Class I Area in Tables 5-1 and 5-4 and

Figures 5-1 and 5-2 illustrate s the conclusions stated above . The greatest reduction in 98 th



# percentile dV and number of days exceeding 0.5 dV is between the Baseline and Scenario 1.

The average incremental cost effectiveness for Scenario 1 compared to the Baseline for the

Bridger Wilderness area (Table 5-4) is re asonable at $300,000 per day and $7.7 million per dV.

However, the incremental cost effectiveness for S cenario 3 compared to Scenario 1 is excessive

at $4 million per day and $75.5 million per dV. Ther efore, Scenario 1 represents BART for

Jim Bridger 1.



# 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 more closely aligned with bituminous coals, with a

presumptive BART NO

x 

# limit of 0.28 lb per MMBtu.

CH2M HILL recommends the existing low-NO

x 

# burners with over-fire ai r (LNB with OFA) as

BART for Jim Bridger 1, based on th e projected significant reduction in NO

x 

# emissions,

reasonable control costs, and the advantages of no additional power requirements or non-air

quality environmental impacts. Nitrogen oxide re ductions are expected to be similar to those

realized at Jim Bridger 2. CH2M HILL recomm ends that the unit be permitted 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 1, based on the significant reduction in SO 2 

# emissions, reasonable control costs,

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

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

# limit of

0.15 lb per MMBtu.



# 5.2.3 PM 10



# Emission Control

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

performance of the existing ESP as BART for Jim Bridger 1, based on the significant reduction

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-9

# BART ANALYSIS FOR JIM BRIDGER UNIT 1

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 5-10 

# in PM 10 

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

requirements and no non-air quality environmental impacts.



# 5.3 Just-Noticeable Differences in Atmospheric Haze

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

Haze” by Dr. Ronald Henry of the University of Southern California (H enry, 2002), state that

only dV differences of approximately 1.5 to 2.0 dV , or more are perceivable by the human eye.

Deciview changes of less than 1.5 cannot be distinguished by the average person. Therefore,

the modeling analysis results indicate that only minimal, if any, observable visibility

improvements at the Class I areas studied would be expected under any of the scenarios. Thus

the results indicate that even though many millions of dollars will be spent, only minimal if any

noticeable visibility improvements may result.

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

water in various forms (fog, clouds, snow or ra in) or other naturally caused aerosols obscure

the atmosphere. During the period of 2001 thr ough 2003, there were several mega-wildfires

that lasted for many days and could have ha d a significant impact on background visibility in

these Class I areas. If natural obscuration were to reduce the reduction in visibility impacts

modeled for the Jim Bridger 1 facility, the eff ect would be to increa se the costs per dV

reduction that are presen ted in this report.

# 6.0 References

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

Technology Determinations; Final Rule. July 6, 2005.

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

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

.

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

and Nonattainment Area Permitting . Draft. October 1990.

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

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

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

Waste Management Association. Volume 52, p. 1238.

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

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

October 2006.

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

Modeling Analysis in North Dakota . North Dakota Department of Health. October 26,

2005.

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

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

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

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

Quality Division. September 2006.

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 6-1

# APPENDIX A 

# Economic AnalysisPacifiCorp BART Analysis Scenarios3Index 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/A$ 3,392,440 N/A N/A N/AN/A$ 3,392,440 N/A N/A N/A$ 3,392,440 N/A N/A N/AN/AN/A$ 9,759,059 N/A N/A N/A$ 9,759,059 N/A N/A N/AN/A$ 9,759,059 N/A N/A N/A N/A$ 18,093,916 N/A N/A N/A N/A$ 18,093,916 N/A N/A N/A N/A$ 18,093,916 N/A N/A N/A$ 24,460,535 N/A N/A N/A$ 24,460,535 N/A N/A N/A$ 24,460,535 N/A N/A N/AScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 1 - LNB with OFA, DryFGD, Fabric FilterBaseline - Current Operation withESPScenario 1 - LNB with OFA, DryFGD, Existing ESPScenario 2 - LNB with OFA, DryFGD, New Fabric FilterJim BridgerSelect Unit:Scenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterDJ Unit 4Scenario 4 - LNB with OFA andSCR, Wet FGD, Existing ESP,New StackDave JohnstonDJ Unit 3Baseline - Current Operation withVenturi ScrubberJB Unit 1 JB Unit 2 JB Unit 3 JB Unit 4Baseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPBaseline - Current Operation withWet FGD and ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, New Fabric FilterScenario 2 - LNB with OFA, WetFGD, Fabric FilterScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPScenario 1 - LNB with OFA, WetFGD, ESPNaughtonScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 4 - LNB with OFA andSCR, Wet FGD, Fabric FilterScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 3 - LNB with OFA andSCR, Wet FGD, ESPScenario 2 - LNB with OFA, WetFGD, New Fabric FilterBaseline - Current Operation withESPBaseline - Current Operation withESPBaseline - Current Operation with WetFGD and ESPNTN Unit 1 NTN Unit 2 NTN Unit 3Scenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA, DryFGD, New Fabric FilterScenario 2 - LNB with OFA, Wet FGD,New Fabric FilterScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, DryFGD, ESPScenario 1 - LNB with OFA, Wet FGD,ESPScenario 4 - LNB with OFA and SCR, WetFGD, Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA andSCR, Dry FGD, New Fabric FilterScenario 3 - LNB with OFA and SCR, WetFGD, ESPScenario 4 - N/AJim Bridger Unit 1Scenario 3 - LNB with OFA and SCR, WetFGD, Fabric Filter, New StackScenario 2 - LNB with OFA and SCR, DryFGD, Fabric FilterScenario 1 - LNB with OFA, Dry FGD,Fabric FilterBaseline - Current Operation with DryFGD, Fabric FilterWDK Unit 1WyodakScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackScenario 4 - LNB with OFA andSCR, Wet FGD, ESP, New StackEY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls1 of 1ECONOMIC ANALYSIS SUMMARYJim Bridger Unit 1Boiler 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 ($)0 8,700,001 20,528,122 22,127,239 129,575,495 12,999,900 0 48,386,333FIRST YEAR O&M COST ($)Operating Labor ($) 0 0 0 0 0 0 0 0Maintenance Material ($) 0 28,000 42,000 123,000 190,000 25,550 0 51,099Maintenance Labor ($) 0 42,000 63,000 184,500 285,000 17,033 10,000 76,649Administrative Labor ($) 0 0 0 0 0 0 0 0TOTAL FIXED O&M COST0 70,000 105,000 307,500 475,000 42,583 10,000 127,749Makeup Water Cost 0 0 0 0 0 30,503 0 0Reagent Cost 0 0 0 1,005,811 912,848 533,206 145,854 0SCR Catalyst / FF Bag Cost 0 0 0 0 594,000 0 0 300,040Waste Disposal Cost 0 0 0 0 0 442,958 0 0Electric Power Cost 0 0 2,528,012 208,926 1,291,005 208,926 19,710 1,335,944TOTAL VARIABLE O&M COST0 0 2,528,012 1,214,7372,797,8531,215,593165,5641,635,984TOTAL FIRST YEAR O&M COST 0 70,000 2,633,012 1,522,237 3,272,853 1,258,176 175,564 1,763,732FIRST YEAR DEBT SERVICE ($)0 827,612 1,952,796 2,104,916 12,326,235 1,236,652 0 4,602,887TOTAL FIRST YEAR COST ($)0 897,612 4,585,808 3,627,153 15,599,088 2,494,828 175,564 6,366,619Power Consumption (MW)0.0 0.0 6.4 0.5 3.3 0.5 0.1 3.4Annual Power Usage (Million kW-Hr/Yr)0.0 0.0 50.6 4.2 25.8 4.2 0.4 26.7CONTROL 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.)0 181 843 613 1,736 0 0 0Incremental Control Cost ($/Ton NOx Removed)0 181 7,797 2,885 3,89400 02-1 3-2 4-2 5-4SO2 Removal Rate (%)77.8%0.0%0.0%0.0%0.0%62.5%0.0%0.0%SO2 Removed (Tons/Yr) 0 0 0 0 0 3,950 0 0First Year Average Control Cost ($/Ton SO2 Rem.)0 0 0 0 0 632 0 0Incremental Control Cost ($/Ton SO2 Removed)Base 0 0 0 0 632 0 08-1PM Removal Rate (%)99.47%0.00%0.00%0.00%0.00%0.00%33.33%66.67%PM Removed (Tons/Yr) 0 0 0 0 0 0 355 710First Year Average Control Cost ($/Ton PM Rem.)0 0 0 0 0 0 495 8,973Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 0 495 17,4529-1 10-9PRESENT WORTH COST ($)0 9,555,250 52,697,883 40,725,706 169,562,733 28,372,107 2,145,015 69,935,356PM ControlNOx ControlParameterCurrentOperationSO2 ControlEY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls1 of 1INPUT CALCULATIONSJim Bridger Unit 1Boiler 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)51,177 270 270 270 270 270 270 270(Lb/MMBtu)8.530 0.045 0.045 0.045 0.045 0.045 0.045 0.045(Lb Moles/Hr)1,705.3 9.0 9.0 9.0 9.0 9.0 9.0 9.0(Tons/Yr)201,739 1,064 1,064 1,064 1,064 1,064 1,064 1,064Fly Ash Removal Rate (%)99.47%0.00%0.00%0.00%0.00%0.00%33.33%66.67%(Lb/Hr)50,907 0 0 0 0 0 90 180(Ton/Yr)200,674 0 0 0 0 0 355 710Fly Ash Emission Rate (Lb/Hr)270 270 270 270 270 270 180 90(Lb/MMBtu)0.0450.045 0.045 0.045 0.045 0.0450.030 0.015(Ton/Yr)1,064 1,064 1,064 1,064 1,064 1,064 710 355ParameterCommentsCurrentOperationSO2 ControlNOx Control PM ControlEY102007001SLC\App A_PCorp JB1 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 22,127,239 129,575,49500 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 ($2006)0 8,700,001 20,528,122 22,127,239 129,575,49512,999,900 0 48,386,333NOx Emission Control System ($/kW)0 16 39 42 244 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 ($/kW)0 16 39 42 244 25 0 91Total Fixed Operating & Maintenance CostsOperating Labor ($)00000 0 0 0Maintenance Material ($)0 28,000 42,000 123,000 190,000 25,550 0 51,099Maintenance Labor ($)0 42,000 63,000 184,500 285,000 17,033 10,000 76,649Administrative Labor ($)00000 0 0 0Total Fixed O&M Cost ($)0 70,000 105,000 307,500 475,000 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 53 0 0Unit Price ($/1000 Gallons)1.221.22 1.22 0.00 1.22 1.22 1.22 1.22First Year Water Cost ($)0 0 0 0 0 30,503 0 0Annual Water Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Reagent CostNone None None UreaAnhydrous NH3Soda Ash Elemental SulfurNoneUnit Cost ($/Ton)0.00 0.00 0.00 370 400 80.00 370 0.00($/Lb)0.000 0.000 0.000 0.185 0.200 0.040 0.185 0.000Molar Stoichiometry0.00 0.00 0.00 0.45 1.00 1.02 0.00 0.00Reagent Purity (Wt.%)100%100%100%100%100%100%100%90%Reagent Usage (Lb/Hr)0 0 0 690 579 1,6911000First Year Reagent Cost ($)0 0 0 1,005,811 912,848 533,206 145,854 0Annual Reagent Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%SCR Catalyst / FF Bag Replacement CostSCR Catalyst Bags BagsAnnual SCR Catalyst (m3) / No. FF Bags0000198 0 0 2,885SCR Catalyst ($/m3) / Bag Cost ($/ea.)3,0003,000 3,000 3,000 3,000 104 3,000 104First Year SCR Catalyst / Bag Replace. Cost ($)0 0 0 0 594,000 0 0 300,040Annual SCR Catalyst / Bag Cost Esc. Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%FGD Waste Disposal CostFGD Solid Waste Disposal Rate, Dry (Lb/Hr)0 0 0 0 0 4,618 0 0FGD Waste Disposal Unit Cost ($/Dry Ton)24.3324.33 24.33 24.33 24.33 24.33 24.33 24.33First Year FGD Waste Disposal Cost ($)0 0 0 0 0 442,958 0 0Annual Waste Disposal Cost Esc. Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%Auxiliary Power CostAuxiliary Power Requirement (% of Plant Output)0.00%0.00%1.21%0.10%0.62%0.10%0.01%0.64%(MW)0.00 0.00 6.41 0.53 3.28 0.53 0.05 3.39Unit Cost ($2006/MW-Hr)50.0050.00 50.00 50.00 50.00 50.00 50.00 50.00First Year Auxiliary Power Cost ($)0 0 2,528,012 208,926 1,291,005 208,926 19,710 1,335,944Annual Power Cost Escalation Rate (%)2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%EY102007001SLC\App A_PCorp JB1 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 JB1 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 JB1 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 JB1 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$$ -82Lime1.02-1.75Index No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsIndex No. Name of UnitAnnual Fixed O&M CostsVariable Operating RequirementsVariable Operating RequirementsVariable Operating RequirementsEY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls4 of 5Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagentUsage (Lb/Hr)Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ -$ -$ -$ -None- --2 Dave Johnston Unit 4-$ -$ -$ $ - -None- --3 Jim Bridger Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.054 Jim Bridger Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.055 Jim Bridger Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.056 Jim Bridger Unit 4-$ -$ 10,000$ $ - -Elemental Sulfur100 -0.057 Naughton Unit 1-$ -$ 10,000$ $ - -Elemental Sulfur33 -0.058 Naughton Unit 2-$ -$ 10,000$ $ - -Elemental Sulfur43 -0.059 Naughton Unit 3-$ -$ 10,000$ $ - -Elemental Sulfur67 -0.0510 Wyodak Unit 1-$ -$ 10,000$--Elemental Sulfur63-0.05Table 13 - Case 10 O&M Costs (Fabric Filter)Oper. Labor Maint. Materials Maint. Labor Admin. LaborMakeup WaterUse (Gpm) ReagentReagent MolarStoich.Annual FF BagReplace.Aux. PowerUsage (MW)1 Dave Johnston Unit 3-$ 45,016$ 67,524$ -$ -None- 1,4571.382 Dave Johnston Unit 4-$ 68,133$ 102,199$ $ - -None- 1,7982.353 Jim Bridger Unit 1-$ 51,099$ 76,649$ $ - -None- 2,8853.394 Jim Bridger Unit 2-$ 51,099$ 76,649$ $ - -None- 2,8853.375 Jim Bridger Unit 3-$ 51,099$ 76,649$ $ - -None- 2,8273.336 Jim Bridger Unit 4-$ 51,099$ 76,649$ $ - -None- 2,8853.397 Naughton Unit 1-$ 45,016$ 67,524$ $ - -None- 8651.018 Naughton Unit 2-$ 45,016$ 67,524$ $ - -None- 1,1931.389 Naughton Unit 3-$ 48,666$ 72,999$ $ - -None- 1,7992.0610 Wyodak Unit 1-$ 48,666$ 72,999$$ --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 JB1 BART Economic Analysis_01-11-07.xls5 of 5CAPITAL COSTJim Bridger Unit 1CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control SystemCAPITAL COST COMPONENTFactor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source CostLNB w/OFA or ROFALNB w/OFA ROFA LNB w/OFA LNB w/OFAMajor Materials Design and SupplyVendor $2,981,982Vendor $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 $9,528,000 S&L Report $80,923,000 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0Contingency20.0%$020.0%$020.0%$1,905,60020.0%$16,184,60020.0%$020.0%$020.0%$020.0%$020.0%$0Labor Premium5.6%$05.6%$05.6%$532,9015.6%$4,526,0235.6%$05.6%$05.6%$05.6%$05.6%$0EPC Premium0.0%$00.0%$00.0%$08.4%$6,835,5668.4%$08.4%$08.4%$08.4%$08.4%$0Boiler Reinforcement (Allowance)0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Sales Tax1.1%$01.1%$01.1%$104,9991.1%$891,7711.1%$01.1%$01.1%$01.1%$01.1%$0Escalation0.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$00.0%$0Contingency on Adders2.8%$02.8%$02.8%$267,4512.8%$2,271,5092.8%$02.8%$02.8%$02.8%$02.8%$0Surcharge and AFUDC11.4%$011.4%$011.4%$1,088,28811.4%$9,243,02511.4%$011.4%$011.4%$011.4%$011.4%$0Total Capital Cost for SNCR or SCR $0 $0 $13,427,239 $120,875,494 $0 $0 $0 $0 $0Dry or Wet FGD, FGC or Fabric FilterDry FGD Dry FGD w/FF Wet FGD FGC Fabric FilterMajor Materials Design and SupplyS&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $8,010,093 S&L Report $0 S&L Report $29,814,000Contingency20.0%$020.0%$020.0%$020.0%$020.0%$020.0%$020.0%$1,602,01920.0%$020.0%$5,962,800Labor Premium5.6%$05.6%$05.6%$05.6%$05.6%$05.6%$05.6%$448,0055.6%$05.6%$1,667,497EPC Premium8.4%$08.4%$08.4%$08.4%$08.4%$08.4%$08.4%$676,6138.4%$08.4%$2,518,389Boiler Reinforcement (Allowance)2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$02.8%$225,4042.8%$02.8%$838,966Sales Tax1.1%$01.1%$01.1%$01.1%$01.1%$01.1%$01.1%$88,2711.1%$01.1%$328,550Escalation10.1%$010.1%$010.1%$010.1%$010.1%$010.1%$010.1%$809,74010.1%$010.1%$3,013,897Contingency on Adders2.8%$02.8%$02.8%$02.8%$02.8%$02.8%$02.8%$224,8432.8%$02.8%$836,879Surcharge and AFUDC11.4%$011.4%$011.4%$011.4%$011.4%$011.4%$011.4%$914,91311.4%$011.4%$3,405,355Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 $0 $12,999,900 $0 $48,386,333PM ControlFlue Gas ConditioningNOx Control45 76293LNB w/OFA & SNCRWet FGDESP ESPLNB w/OFA & SCRWet FGDESPLNCFS-1 & Windbox Mods.N/AESPParameterLNB w/OFA ROFA LNB w/OFA & SCRUpgraded Wet FGDESPLNB w/OFAWet FGDESP ESPROFAWet FGDLNCFS-1 & Windbox Mods.N/AN/AN/ALNB w/OFA & SNCRSO2 ControlUpgraded Wet FGDFabric Filter8LNCFS-1 & Windbox Mods.Fabric Filter10LNCFS-1 & Windbox Mods.Wet FGDLNCFS-1 & Windbox Mods.Wet FGDFlue Gas ConditioningEY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls1 of 1Jim Bridger Unit 1LNB w/OFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 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 1ROFAYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 105,000----2,528,0122,528,0121,952,7964,585,8088432 2015 107,100----2,578,5732,578,5731,952,7964,638,4688533 2016 109,242----2,630,1442,630,1441,952,7964,692,1828634 2017 111,427----2,682,7472,682,7471,952,7964,746,9708735 2018 113,655----2,736,4022,736,4021,952,7964,802,8538836 2019 115,928----2,791,1302,791,1301,952,7964,859,8548937 2020 118,247----2,846,9532,846,9531,952,7964,917,9959048 2021 120,612----2,903,8922,903,8921,952,7964,977,2999159 2022 123,024----2,961,9702,961,9701,952,7965,037,78992610 2023 125,485----3,021,2093,021,2091,952,7965,099,48993711 2024 127,994----3,081,6333,081,6331,952,7965,162,42394912 2025 130,554----3,143,2663,143,2661,952,7965,226,61696113 2026 133,165----3,206,1313,206,1311,952,7965,292,09297314 2027 135,829----3,270,2543,270,2541,952,7965,358,87898515 2028 138,545----3,335,6593,335,6591,952,7965,427,00099816 2029 141,316----3,402,3723,402,3721,952,7965,496,4841,01017 2030 144,142----3,470,4193,470,4191,952,7965,567,3581,02318 2031 147,025----3,539,8283,539,8281,952,7965,639,6491,03719 2032 149,966----3,610,6243,610,6241,952,7965,713,3861,05020 2033 152,965----3,682,8373,682,8371,952,7965,788,5981,064Present Worth1,282,875----30,886,88630,886,88620,528,12252,697,883484(% of PW)2.4% 0.0% 0.0% 0.0% 0.0% 58.6% 58.6% 39.0% 100.0%EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls1 of 4Jim Bridger Unit 1LNB w/OFA & SNCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 307,500-1,005,811--208,9261,214,7372,104,9163,627,1536132 2015 313,650-1,025,927--213,1051,239,0322,104,9163,657,5986193 2016 319,923-1,046,446--217,3671,263,8122,104,9163,688,6516244 2017 326,321-1,067,375--221,7141,289,0882,104,9163,720,3266295 2018 332,848-1,088,722--226,1481,314,8702,104,9163,752,6346356 2019 339,505-1,110,496--230,6711,341,1682,104,9163,785,5896407 2020 346,295-1,132,706--235,2851,367,9912,104,9163,819,2026468 2021 353,221-1,155,361--239,9901,395,3512,104,9163,853,4886529 2022 360,285-1,178,468--244,7901,423,2582,104,9163,888,45965810 2023 367,491-1,202,037--249,6861,451,7232,104,9163,924,13066411 2024 374,841-1,226,078--254,6801,480,7572,104,9163,960,51467012 2025 382,338-1,250,599--259,7731,510,3732,104,9163,997,62667613 2026 389,984-1,275,611--264,9691,540,5802,104,9164,035,48168314 2027 397,784-1,301,124--270,2681,571,3922,104,9164,074,09268915 2028 405,740-1,327,146--275,6731,602,8192,104,9164,113,47569616 2029 413,855-1,353,689--281,1871,634,8762,104,9164,153,64670317 2030 422,132-1,380,763--286,8111,667,5732,104,9164,194,62170918 2031 430,574-1,408,378--292,5471,700,9252,104,9164,236,41571719 2032 439,186-1,436,546--298,3981,734,9432,104,9164,279,04572420 2033 447,969-1,465,276--304,3661,769,6422,104,9164,322,528731Present Worth3,756,990-12,288,849--2,552,62714,841,47722,127,23940,725,706344(% of PW)9.2% 0.0% 30.2% 0.0% 0.0% 6.3% 36.4% 54.3% 100.0%Jim Bridger Unit 1LNB w/OFA & SCRYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton NOx Removed)0 20131 2014 475,000-912,848594,000-1,291,0052,797,85312,326,23515,599,0881,7362 2015 484,500-931,105605,880-1,316,8252,853,81012,326,23515,664,5451,7433 2016 494,190-949,727617,998-1,343,1622,910,88612,326,23515,731,3111,7504 2017 504,074-968,722630,358-1,370,0252,969,10412,326,23515,799,4131,7585 2018 514,155-988,096642,965-1,397,4253,028,48612,326,23515,868,8761,7666 2019 524,438-1,007,858655,824-1,425,3743,089,05612,326,23515,939,7291,7747 2020 534,927-1,028,015668,940-1,453,8813,150,83712,326,23516,011,9991,7828 2021 545,626-1,048,575682,319-1,482,9593,213,85412,326,23516,085,7141,7909 2022 556,538-1,069,547695,966-1,512,6183,278,13112,326,23516,160,9041,79810 2023 567,669-1,090,938709,885-1,542,8703,343,69312,326,23516,237,5971,80711 2024 579,022-1,112,757724,083-1,573,7283,410,56712,326,23516,315,8241,81512 2025 590,603-1,135,012738,564-1,605,2023,478,77912,326,23516,395,6161,82413 2026 602,415-1,157,712753,336-1,637,3063,548,35412,326,23516,477,0041,83314 2027 614,463-1,180,866768,402-1,670,0533,619,32112,326,23516,560,0191,84315 2028 626,752-1,204,484783,770-1,703,4543,691,70812,326,23516,644,6951,85216 2029 639,287-1,228,573799,446-1,737,5233,765,54212,326,23516,731,0641,86217 2030 652,073-1,253,145815,435-1,772,2733,840,85312,326,23516,819,1611,87118 2031 665,115-1,278,208831,743-1,807,7193,917,67012,326,23516,909,0191,88119 2032 678,417-1,303,772848,378-1,843,8733,996,02312,326,23517,000,6751,89220 2033 691,985-1,329,847865,346-1,880,7514,075,94412,326,23517,094,1641,902Present Worth5,803,480-11,153,0437,257,405-15,773,31034,183,758129,575,495169,562,733943(% of PW)3.4% 0.0% 6.6% 4.3% 0.0% 9.3% 20.2% 76.4% 100.0%EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls2 of 4Jim Bridger Unit 1Upgraded Wet FGDYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton SO2 Removed)0 20131 2014 42,58330,503533,206-442,958208,9261,215,5931,236,6522,494,8286322 2015 43,43531,113543,870-451,818213,1051,239,9051,236,6522,519,9916383 2016 44,30331,735554,747-460,854217,3671,264,7031,236,6522,545,6586454 2017 45,18932,370565,842-470,071221,7141,289,9971,236,6522,571,8386515 2018 46,09333,017577,159-479,472226,1481,315,7971,236,6522,598,5426586 2019 47,01533,678588,702-489,062230,6711,342,1131,236,6522,625,7806657 2020 47,95534,351600,476-498,843235,2851,368,9551,236,6522,653,5626728 2021 48,91435,038612,486-508,820239,9901,396,3341,236,6522,681,9016799 2022 49,89335,739624,735-518,996244,7901,424,2611,236,6522,710,80668610 2023 50,89036,454637,230-529,376249,6861,452,7461,236,6522,740,28969411 2024 51,90837,183649,975-539,964254,6801,481,8011,236,6522,770,36170112 2025 52,94637,926662,974-550,763259,7731,511,4371,236,6522,801,03670913 2026 54,00538,685676,234-561,778264,9691,541,6661,236,6522,832,32371714 2027 55,08539,459689,758-573,014270,2681,572,4991,236,6522,864,23772515 2028 56,18740,248703,554-584,474275,6731,603,9491,236,6522,896,78873316 2029 57,31141,053717,625-596,164281,1871,636,0281,236,6522,929,99174217 2030 58,45741,874731,977-608,087286,8111,668,7491,236,6522,963,85875018 2031 59,62642,711746,617-620,249292,5471,702,1231,236,6522,998,40275919 2032 60,81943,566761,549-632,654298,3981,736,1661,236,6523,033,63776820 2033 62,03544,437776,780-645,307304,3661,770,8891,236,6523,069,577777Present Worth520,271372,6796,514,628-5,412,0002,552,62714,851,93512,999,90028,372,107359(% of PW)1.8% 1.3% 23.0% 0.0% 19.1% 9.0% 52.3% 45.8% 100.0%Jim Bridger Unit 1Flue Gas ConditioningYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 10,000-145,854--19,710165,564-175,5644952 2015 10,200-148,771--20,104168,875-179,0755053 2016 10,404-151,747--20,506172,253-182,6575154 2017 10,612-154,781--20,916175,698-186,3105255 2018 10,824-157,877--21,335179,212-190,0365366 2019 11,041-161,035--21,761182,796-193,8375467 2020 11,262-164,255--22,197186,452-197,7145578 2021 11,487-167,540--22,641190,181-201,6685689 2022 11,717-170,891--23,093193,985-205,70158010 2023 11,951-174,309--23,555197,864-209,81559111 2024 12,190-177,795--24,026201,822-214,01260312 2025 12,434-181,351--24,507205,858-218,29261513 2026 12,682-184,978--24,997209,975-222,65862814 2027 12,936-188,678--25,497214,175-227,11164015 2028 13,195-192,451--26,007218,458-231,65365316 2029 13,459-196,300--26,527222,827-236,28666617 2030 13,728-200,226--27,058227,284-241,01267918 2031 14,002-204,231--27,599231,830-245,83269319 2032 14,282-208,315--28,151236,466-250,74970720 2033 14,568-212,482--28,714241,195-255,764721Present Worth122,179-1,782,023--240,8142,022,837-2,145,015302(% of PW)5.7% 0.0% 83.1% 0.0% 0.0% 11.2% 94.3% 0.0% 100.0%EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls3 of 4Jim Bridger Unit 1Fabric FilterYear DateTOTAL FIXEDO&M COSTMakeupWater CostReagent CostSCR Catalyst / FFBagCostWasteDisposal CostElectricPower CostTOTAL VARIABLEO&M COSTDEBT SERVICETOTAL ANNUALCOSTControl Cost($/Ton PM Removed)0 20131 2014 127,749--300,040-1,335,9441,635,9844,602,8876,366,6198,9732 2015 130,304--306,041-1,362,6631,668,7034,602,8876,401,8949,0233 2016 132,910--312,162-1,389,9161,702,0784,602,8876,437,8749,0744 2017 135,568--318,405-1,417,7141,736,1194,602,8876,474,5739,1255 2018 138,279--324,773-1,446,0691,770,8414,602,8876,512,0079,1786 2019 141,045--331,268-1,474,9901,806,2584,602,8876,550,1909,2327 2020 143,866--337,894-1,504,4901,842,3834,602,8876,589,1369,2878 2021 146,743--344,652-1,534,5791,879,2314,602,8876,628,8619,3439 2022 149,678--351,545-1,565,2711,916,8164,602,8876,669,3809,40010 2023 152,671--358,576-1,596,5771,955,1524,602,8876,710,7109,45811 2024 155,725--365,747-1,628,5081,994,2554,602,8876,752,8669,51812 2025 158,839--373,062-1,661,0782,034,1404,602,8876,795,8669,57813 2026 162,016--380,523-1,694,3002,074,8234,602,8876,839,7269,64014 2027 165,256--388,134-1,728,1862,116,3194,602,8876,884,4629,70315 2028 168,562--395,896-1,762,7492,158,6464,602,8876,930,0949,76716 2029 171,933--403,814-1,798,0042,201,8194,602,8876,976,6389,83317 2030 175,371--411,891-1,833,9652,245,8554,602,8877,024,1139,90018 2031 178,879--420,128-1,870,6442,290,7724,602,8877,072,5389,96819 2032 182,456--428,531-1,908,0572,336,5884,602,8877,121,93110,03820 2033 186,106--437,102-1,946,2182,383,3194,602,8877,172,31210,109Present Worth1,560,813--3,665,845-16,322,36519,988,21048,386,33369,935,3564,928(% of PW)2.2% 0.0% 0.0% 5.2% 0.0% 23.3% 28.6% 69.2% 100.0%EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls4 of 4EY102007001SLC\App A_PCorp JB1 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 JB1 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