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 and Best Available Retrofit Technology (BART) 

regulations and guidelines, CH2M HILL was requested to perform a BART analysis for 

PacifiCorp’s Jim Bridger Unit 1 (hereafter referred to as Jim Bridger 1). A BART analysis has 

been conducted for the following criteria pollutants: nitrogen oxide (NOx), sulfur dioxide (SO2), 

and particulate matter less than 10 micrometers in aerodynamic diameter (PM10). The Jim Bridger 

Station consists of four 530-megawatt (MW) units with a total generating capacity of 2,120 MW. 

Because the total generating capacity of the Jim Bridger Station exceeds 750 MW, 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 Implementation Plan (SIP) is approved by the EPA. A 

compliance date of 2014 was assumed for this analysis. 

In completing the BART analysis, technology alternatives were investigated and potential 

reductions in NOx, SO2, and PM10 emissions rates were identified. The following technology 

alternatives were investigated, listed below by pollutant: 

• NOx emission controls: 

− Low-NOx burners (LNBs) with over-fire air (OFA) 

− Rotating opposed fire air (ROFA) 

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

− LNBs with selective catalytic reduction (SCR) system 

• SO2 emission controls: 

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

− Upgrade wet sodium FGD system to achieve an SO2 emission rate of 0.10 pound (lb) per 

million British thermal units (MMBtu) 

− New dry FGD system 

• PM10 emission controls: 

− Sulfur trioxide (SO3) 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 analysis are identified in the Code of Federal 

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

• The identification of available, technically feasible, retrofit 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 environmental impacts of compliance 

• The degree of visibility improvement that may 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, technically feasible, retrofit 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 Effectiveness 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 environmental impacts of compliance 

• Step 5 – Evaluate Visibility Impacts 

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

BART 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs included in 

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

BART implementation date. 

Coal Characteristics 

The main source of coal burned at Jim Bridger 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 NOx formation. These 

coals have higher nitrogen content than coals 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 evaluated the effect of these qualities on NOx 

formation and achievable emission rates. 

Recommendations 

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

OFA, upgrading the existing FGD system, and operating the existing ESP with an SO3 flue gas 

conditioning system. This combination of control devices is identified as Scenario 1 throughout 

this report. 

NOx Emission Control 

The BART presumptive NOx limit assigned by EPA for tangentially-fired boilers burning 

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

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

presumptive BART NOx 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 NOx emissions, reasonable control costs, and the advantages of 

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

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

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

SO2 Emission Control 

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

Jim Bridger 1, based on the significant reduction in SO2 emissions, reasonable control costs, and 

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

environmental impacts. This upgrade approach will meet the BART presumptive SO2 limit of 

0.15 lb per MMBtu. 

PM10 Emission Control 

CH2M HILL recommends finalizing the permitting 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 PM10 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 areas potentially affected are located more than 

50 kilometers, but less than 300 kilometers, 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 NOx, SO2, and PM10 emissions, four postcontrol atmospheric dispersion modeling scenarios were developed to cover the range of 

effectiveness for combining the individual NOx, SO2, and PM10 control technologies under 

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

• Scenario 1: New LNB with OFA modifications, 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 

Manual1. 

Least-cost Envelope Analysis 

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

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

comparisons focus on annualized cost and emission reduction differences between dominant 

alternatives. The dominant set of control alternatives 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 alternatives identified in the BART analysis. 

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

annualized cost, cost per deciview (dV) reduction, 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. 

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BART ANALYSIS FOR JIM BRIDGER UNIT 1 

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC ES-5

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

days above 0.5 dV, and the total annualized cost versus 98th percentile delta-deciview (ΔdV) 

reduction. 

Results of the least-cost envelope analysis validate the selection 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 scenario, 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 not selected due to very high incremental costs, 

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

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

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 that demonstrate only dV differences of approximately 1.5 to 

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

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

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

expected under any of the control scenarios. Thus, the results 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 visibility 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 NOx Analysis....................................................................3-2 

3.2.2 BART SO2 Analysis...................................................................3-14 

3.2.3 BART PM10 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 NOx Emission Control .................................................................5-9 

5.2.2 SO2 Emission Control ..................................................................5-9 

5.2.3 PM10 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 NOx Control Technology Emission Rate Ranking 

3-3 NOx Control Cost Comparison 

3-4 SO2 Control Technology Emission Rates 

3-5 SO2 Control Cost Comparison (Incremental to Existing FGD System) 

3-6 PM10 Control Technology Emission Rates 

3-7 PM10 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 Baseline vs. Post-control Scenarios at Class I 

Areas 

5-1 Control Scenario Results for the 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 Agglomeration on the Speed of Coal Combustion 

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

NOx Limits 

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

NOx Limits 

3-4 First Year Control Cost for NOx 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 Bridger Class I WA Days Reduction 

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

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

5-4 Least-cost Envelope Fitzpatrick Class I WA 98th Percentile Reduction 

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

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

Appendices 

A Economic Analysis

B 2006 Wyoming BART Protocol
Acronyms and Abbreviations 

°F Degrees Fahrenheit 

°C Degrees Celsius 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CALDESK Program to Display Data and Results 

CALMET Meteorological Data Preprocessing Program for CALPUFF 

CALPOST Post-processing Program for Calculating Visibility Impacts 

CALPUFF Gaussian Puff Dispersion Model 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

EIA Energy Information Administration 

ESP Electrostatic Precipitator 

EPA United States Environmental Protection Agency 

Fuel NOx 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-NOx Burner 

LOI Loss on Ignition 

MMBtu Million British Thermal Units 

MM5 Mesoscale Meteorological Model, Version 5 

MW Megawatt 

N2 Nitrogen 

NOx 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 

PM10 Particulate Matter less than 10 Micrometers in Aerodynamic Diameter 

PM2.5 Particulate Matter less than 2.5 Micrometers 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 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

Thermal NOx High Temperature Fixation of Atmospheric Nitrogen in Combustion Air 

TRC TRC Company, Inc. 

USGS U.S. Geological Survey 

WA Wilderness Area 

WDEQ-AQD Wyoming Department of Environmental Quality – Air Quality Division 
1.0 Introduction 

Best Available Retrofit Technology (BART) guidelines were established as a result of 

U.S. Environmental Protection Agency (EPA) regulations 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 additional controls, and the type of controls that 

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

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

The Wyoming Department of Environmental Quality (WDEQ) BART regulations state that 

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

December 15, 2006. PacifiCorp received an extension 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 the source. This revised report—submitted in 

October 2007—incorporates editorial revisions and new model runs since the January 2007 

version. 

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

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

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

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

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

of EPA’s approval of the SIP. 

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

• Any existing pollution control technology in use at the source 

• The cost of the controls 

• The remaining useful life of the source 

• The energy and non-air quality environmental impacts of compliance 

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

such technology 

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

CH2M HILL for PacifiCorp. The analysis was performed for the pollutants nitrogen oxide 

(NOx), sulfur dioxide (SO2), and particulate matter less than 10 micrometers in aerodynamic 

diameter (PM10), because they are the primary criteria pollutants that affect visibility. 

Section 2 of this report provides a description of the present unit operation, including a 

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

Section 3, by pollutant type. Section 4 provides the 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 Springs, Wyoming. Unit 1 is equipped with a tangentially fired, 

pulverized-coal boiler with low-NOx burners (LNBs) manufactured by Combustion 

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

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

three absorber towers installed in 1990. An Emerson Ovation distributed control system was 

installed in 2006. 

Jim Bridger 1 was placed in service in 1974. Its current economic depreciation 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 control devices at Jim Bridger 1 to operate until 2040. 

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

The BART presumptive NOx 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 NOx

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

Jim Bridger 1 are the Bridger Mine and secondarily the Black Butte Mine and Leucite Hills 

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

coal in many of the parameters influencing NOx formation. These coals have higher nitrogen 

content than coals 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 the different combustion characteristics of PRB coals, as compared to those coals 

used at Jim Bridger 1, and has evaluated the effect of these qualities on NOx formation and 

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

primary source of coal will be the Bridger Underground Mine, 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. 

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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) /Exit 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 Factor (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 Btu (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 (NOx) Controls Low-NOx burners 

NOx Emission Rate (lb/MMBtu) 0.45 

Current Sulfur Dioxide (SO2) Controls Sodium-based wet scrubber 

SO2 Emission Rate (lb/MMBtu) 0.267 

Current PM10(b) Controls Electrostatic Precipitator 

PM10 Emission Rate (lb/MMBtu)(c) 0.045 

NOTES: 

(a)Coal characteristics based on Bridger Underground Mine (primary coal source) (b)PM10 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 

(SO3) injection system. 
B

TABLE 2-2 Coal Sources and Characteristics Jim Bridger 1 

Ultimate Analy

Mines 

Moisture 

(%) Ash (%) 

Volatile 

Matter 

(%) 

Fixed 

Carbon 

(%) 

British 

thermal 

units per 

pound 

(Btu/lb) 

Sulfur 

(%) 

Moisture 

and Ash 

Free 

(Btu/lb) Hydrogen Carbon Sulfur 

Bridger Mine Underground 

19.3 10.3 32.2 38.3 9660 0.58 13712 4.66 69.2 0.72 

Maximum Not enough data yet to run statistical analysis for variability Minimum Not enough data yet to run statistical analysis for variability Bridger Mine Surface 19.1 10.6 32.3 38.0 9390 0.57 13340 4.38 37.4 0.71 Maximum 20.5 12.5 35.5 41.9 9800 0.72 13500 4.69 4.0 0.90 

Minimum 17.5 9.0 31.0 36.0 9000 0.49 13100 4.00 64.3 0.60 

Bridger Mine Highwall 18.0 9.5 33.0 39.5 9700 0.58 13500 No samples of seMaximum Not enough data yet to run statistical analysis for variability Minimum Not enough data yet to run statistical analysis for variability Black Butte Mine 20.0 9.2 33.3 35.6 9450 0.45 13330 4.43 68.7 0.56 Maximum 21.1 10.8 35.4 41.9 10275 0.62 13500 4.66 70.5 0.78 Minimum 18.0 7.6 29.9 36.8 9180 0.33 13140 4.21 66.1 0.41 

Leucite Hills Mine (through 2009) 

19.4 11.5 30.7 38.3 9080 0.64 13140 4.20 66.0 0.81 

Maximum 23.0 15.0 33.0 43.0 10250 0.90 13800 4.70 70.0 1.20 Minimum 17.0 8.0 28.3 33.6 8000 0.40 12300 3.70 61.0 0.50 

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 
3.0 BART Engineering Analysis 

This section presents the required 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 analysis are identified in 40 CFR 51, Appendix Y, 

Section IV. The evaluation must include: 

• The identification of available, technically feasible, retrofit 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 environmental impacts of compliance 

• The degree of visibility improvement that may 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, technically feasible, retrofit 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 Effectiveness 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 environmental impacts of compliance 

• Step 5 – Evaluate Visibility Impacts 

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

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

control equipment in use at the source, the costs of compliance associated with the control 

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

existing control devices. In some cases, enhancing the performance of the existing control 

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

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs included in 

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

BART implementation date. 

3.2.1 BART NOx Analysis 

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

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

Formation of NOx

During coal combustion, NOx is formed in three different ways. The dominant source of NOx

formation is the oxidation of fuel-bound nitrogen (fuel NOx). During combustion, part of the 

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

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

oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen (N2). A 

smaller part of NOx formation is due to high temperature fixation of atmospheric nitrogen in the 

combustion air (thermal NOx). A very small amount of NOx is called prompt NOx. Prompt NOx

results from an interaction of hydrocarbon radicals, nitrogen, and oxygen. 

In a conventional pulverized coal burner, air is introduced with turbulence to promote good 

mixing of fuel and air, which provides 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 NOx. 

Coal characteristics directly and significantly affect NOx 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 NOx 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 NOx 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-bituminous C and demonstrate the high reactivity and 

low NOx 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 production (Energy Information Administration, 

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

characteristics. Emissions standards differentiating between bituminous and sub-bituminous 

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

dominant market presence and unique characteristics. 

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

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

most of the low NOx forming characteristics. Coals from the Bridger, Black Butte, and Leucite 

Hills mines fall into this category. 

As defined by the American Society for Testing 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 when it is heated to above about 

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

after cooling to room temperature.” Because the agglomerating property of coals is the result of 

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

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

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

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

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

property assists in making sub-bituminous coals more amenable to controlling NOx, by allowing 

less air to be introduced during the initial ignition portion of the combustion process. The coals 

from the Bridger, Black Butte and Leucite Hills mines just barely fall into the category of 

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

do not exhibit those properties of non-agglomerating coals or exhibit them to only a minor 

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

to control NOx 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 coal 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 lower oxygen content than the PRB 

coal. The higher nitrogen content is an indication that more nitrogen is available to the 

combustion process and higher NOx emissions are likely. Oxygen content 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 NOx emissions, and they are also more conducive to 

reduction of NOx emissions through the use of combustion control measures, such as LNBs and 

over-fire air (OFA). These characteristics indicate that higher NOx formation is likely with coal 

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

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

PRB coal and Twentymile. Twentymile is a clearly bituminous coal that produces higher NOx, as 

has been demonstrated at power plants burning this fuel. 

Figures 3-2 and 3-3 graphically illustrate the relationship of nitrogen and oxygen content to the 

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

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

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

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

Butte, and Leucite Hills that has been used at Jim Bridger 1, and indicates the average NOx

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 NOx 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 expected 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 system at Jim Bridger 1 would likely result in 

performance and NOx 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 NOx

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

Hill coals, the likely NOx emission rate will be closer to the bituminous end (0.28) of the BART 

presumptive NOx limit range, rather than the BART presumptive NOx limit of 0.15 lb per 

MMBtu for sub-bituminous coal. All these factors are consistent with the 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 NOx 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 NOx 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 Presumptive Limit - 0.15lb/MMBtu

Bituminous Presumptive 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 design and operation of the boiler and associated 

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

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

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

problematic. This is particularly troublesome when dealing with performance issues that are very 

sensitive to both coal quality and combustion conditions, such as NOx formation. There is 

significant variability in the quality of coals burned at Jim Bridger 1. In addition to burning coal 

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

consisting of three sources: underground, surface, and highwall operations. Each of these coal 

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

coal within the mine. 

Several of the coal quality characteristics and their effect on NOx formation have been previously 

discussed. There are some additional considerations that illustrate the complexity of achieving 

and maintaining consistent low NOx 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 taken into consideration when designing a boiler and 

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

such as NOx 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 compared with sea level pressure 

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

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

for efficient combustion, larger volumes of air are required. When adjusting air flows and 

distribution to lower NOx using LNBs and OFA, original boiler design restrictions again limit the 

modifications that can be made and still achieve satisfactory combustion performance. 

Another significant factor in controlling NOx emissions is the fineness of the coal entering the 

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

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

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

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

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

Jim Bridger 1, are more difficult to grind and can contribute to higher NOx levels. In addition, 

coal fineness can deteriorate over time periods between pulverizer maintenance and service as 

pulverizer grinding surfaces wear. 

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

oxygen content of the coals, and the grindability index are taken into account, this analysis 

demonstrates that, for the coal used at Jim Bridger 1, the more applicable presumptive BART 

limit is 0.28 lb per MMBtu. The BART analysis for NOx 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 Available Retrofit Control Technologies 

The first step of the BART process is to evaluate NOx control technologies with practical 

potential for application to Jim Bridger 1, including those control technologies identified as Best 

Available Control Technology (BACT) or lowest 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 potentially applicable emission control technologies. 

Jim Bridger 1 NOx emissions are currently controlled through the use of good combustion 

practices and OFA. 

The following potential NOx control technology options were considered: 

• New/modified LNBs with advanced OFA 

• Rotating Opposed Fire Air (ROFA) 

• Conventional selective non-catalytic reduction (SNCR) system 

• Selective catalytic reduction (SCR) system 

Step 2: Eliminate Technically Infeasible Options 

For Jim Bridger 1, a tangential-fired configuration burning sub-bituminous coal, technical 

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

ability to achieve the regulatory presumptive limit (used as a guide) of 0.28 lb per MMBtu of 

NOx. Jim Bridger 1 has an uncontrolled NOx emission rate of 0.45 lb per MMBtu. 

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

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

Study). Updated cost estimates for SCR and SNCR were used (Sargent 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 ammonia, 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 NOx to nitrogen and water. Nitrogen oxide reductions of up to 60 percent have been 

achieved, although 15 to 30 percent is more realistic for most applications. Selective noncatalytic reduction is typically applied on smaller units. Adequate reagent 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 NOx 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 

NOx Control Technology Emission Rate Ranking 

Jim Bridger 1 

Technology 

Projected Emission Rate 

(pounds per million 

British thermal units) 

Presumptive Best Available Retrofit Technology (BART) Limit 0.28 

Low-NOx 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 Effectiveness of Remaining Control Technologies 

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

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

proposals include inherent uncertainties. These proposals are usually prepared in a limited time 

frame, may be based on incomplete information, 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 contractual guarantees are established only after more 

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

technologies and the control effectiveness evaluated in this BART analysis. 

New LNBs with OFA System. The mechanism used to lower NOx with LNBs is to stage the 

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

combustion is not diverted to combine with nitrogen and form NOx. Fuel-rich conditions favor 

the conversion of fuel nitrogen to N2 instead of NOx. Additional air (or OFA) is then introduced 

downstream in a lower temperature 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 tangential-firing such as Jim Bridger 1, it is generally 

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

burners and reduces burner zone heat flux. These modifications usually require boiler waterwall 

tube replacement. 

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

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

expected NOx emission rate of 0.24 lb per MMBtu. PacifiCorp has indicated that this rate 

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

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

reduction from the current NOx emission rate, and is below the more applicable presumptive 

NOx emission rate of 0.28 lb per MMBtu. 

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

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

Rotation is reported to prevent laminar flow, so that 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 installation 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 NOx emission rate of 0.18 lb per MMBtu using ROFA technology. 

An operating margin of 0.04 lb per MMBtu was added to the expected rate due to Mobotec’s 

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

primarily based on ROFA equipment, the operation 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, results of computational fluid dynamics modeling will 

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

tube assemblies for OFA port installation. Mobotec does not provide installation services, 

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

However, they do provide one onsite construction supervisor during installation and startup. 

SNCR. Selective non-catalytic reduction is generally utilized to achieve modest NOx reductions 

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

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

reduces NOx to nitrogen and water. Nitrogen oxide reductions of up to 60 percent have been 

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

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NOx, 

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 ammonia to create problems 

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

surfaces, and/or create a visible stack plume. Reagent utilization can have a significant impact on 

economics, with higher levels of NOx reduction generally resulting in lower reagent utilization 

and higher operating cost. 

Reductions from higher baseline concentrations (inlet NOx) are lower in cost per ton, but result 

in higher operating costs, due to greater reagent consumption. To reduce reagent costs, S&L has 

assumed that combustion modifications including LNBs and advanced OFA are capable of 

achieving a projected NOx emission rate of 0.24 lb per MMBtu. A further reduction of 15 percent 

in NOx emission rates for SNCR would result in a projected emission 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 into the flue-gas stream, where it reduces NOx to 

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

place on the surface of a vanadium/titanium-based catalyst at a temperature range between 

580° F to 750° F. Due to the catalyst, the SCR process is more efficient than SNCR and results in 

lower NOx emissions. The most common type of SCR is the high-dust configuration, where the 

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

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

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

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 flue gas flow velocity and increase flue gas 

residence time. Due to the higher removal rate, a full-scale SCR 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 NOx emission levels as much as 

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

ammonia requirements of the SCR. The S&L design basis for LNB with OFA and SCR results in 

a projected NOx emission rate of 0.07 lb per MMBtu. Additional catalyst surface was included in 

the SCR design to accommodate the characteristics of the coal used at Jim Bridger 1. 

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

of NOx emissions needed to consistently achieve compliance with an established goal, a review 

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

review, it was noted that NOx emissions can vary significantly 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 NOx emissions value from vendor. 

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

• Review and evaluate unit physical and operational characteristics and restrictions. The fewer 

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

NOx emissions are. 

• For each technology expected value, there is a corresponding potential for actual NOx

emissions to vary from this expected value. From the vendor information presented, along 

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

Step 4: Evaluate Impacts and Document the Results 

This step involves the consideration of energy, environmental, and economic impacts associated 

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

evaluation. 

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

expected to significantly impact the boiler efficiency or forced draft fan power usage. Therefore, 

these technologies will not have energy impacts. 

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

ROFA fans (6,410 kilowatts [kW] total). The SNCR system would require approximately 

530 kW of additional power. 

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

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

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 carbon 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 environmental impacts involve the storage of ammonia, 

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

plant site. 

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

to CH2M HILL by PacifiCorp, 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 

NOx removed is summarized in Table 3-3, and the first year control costs are shown in 

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

TABLE 3-3 

NOx Control Cost Comparison 

Jim Bridger 1 

Factor 

Low-NOx

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 (NOx) Design Control 

Efficiency 

46.7% 51.1% 55.6% 84.4% 

NOx Removed per Year (Tons) 4,967 5,440 5,913 8,987 

First Year Average Control Cost 

(dollars per ton [$/Ton] of NOx Removed) $181/ton $843/ton $613/ton $1,736/ton 

Incremental Control Cost 

($/Ton of NOx Removed) $181/ton $7,797/ton $2,885/ton $3,894/ton 
B

FIGURE 3-4 First Year Control Cost for NOx Air Pollution Control Options 

Jim Bridger 1 

0

1,0002,0003,0004,0005,0006,0007,0008,0009,000

LNB w/OFA ROFA LNB w/OFA & SNCR LNB 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 
BART ANALYSIS FOR JIM BRIDGER UNIT 1 

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

based on its significant reduction in NOx emissions, reasonable control cost, and no additional 

power requirements or environmental impacts. 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, which, 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 SO2 Analysis 

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

coal sulfur content. The BART analysis for SO2 emissions on Jim Bridger 1 is described below. 

Step 1: Identify All Available Retrofit Control Technologies 

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

applicable emission control technologies for SO2 at Jim Bridger 1; this included control 

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

The following potential SO2 control technology options were considered: 

• Optimize current operation of existing wet sodium FGD system 

• Upgrade wet sodium FGD system to meet SO2 emission rate of 0.10 lb per MMBtu 

• New dry FGD system 

Step 2: Eliminate Technically Infeasible Options 

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

guideline) of 95 percent reduction in SO2 emissions, or 0.15 lb per MMBtu. Based on the coal 

that Jim Bridger 1 currently burns, the unit would be required to achieve an 87.5 percent SO2

removal efficiency to meet the presumptive limit of 0.15 lb per MMBtu. 

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

with projected SO2 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 

SO2 Control Technology Emission Rates 

Jim Bridger 1 

Technology 

Projected Emission Rate 

(pounds per million British 

thermal units) 

Presumptive Best Available Retrofit 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 scrubber mixes the flue gas and alkaline reagent 

using a series of spray nozzles to distribute the reagent across the scrubber vessel. The sodium 

in the reagent reacts with the SO2 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 achieves approximately 78 percent 

SO2 removal to achieve an SO2 outlet emission rate of 0.27 lb per MMBtu. Optimizing the 

existing wet FGD system is projected to achieve an SO2 outlet emission rate of 0.20 lb per 

MMBtu (83.3 percent SO2 removal). Optimization would be accomplished by partially closing 

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

from the scrubber, relocating the opacity monitor, and modifying the system to minimize 

scaling problems. 

Upgrading the wet FGD system would achieve an SO2 outlet emission rate of 0.10 lb per 

MMBtu (91.7 percent SO2 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 SO2 removal (0.06 lb per MMBtu) on a 

continuous basis since this high level of removal must be incorporated into the original design 

of the scrubber. 

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

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

MMBtu of SO2. 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 SO2 removal), which would meet the presumptive limit of 

0.15 lb per MMBtu of SO2 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 atomizer wheel. The rapid speed of the atomizer wheel 

causes the lime slurry to separate into very fine droplets that intermix with the flue gas. The 

SO2 in the flue gas reacts with the calcium in the lime slurry to form dry calcium sulfate 

particles. At Jim Bridger 1 this dry particulate matter would be captured 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 spray dryer system typically produces a dry waste 

product suitable for landfill disposal. 

The dry FGD system with the existing ESP is projected to achieve 82.5 percent SO2 removal at 

Jim Bridger 1. This would result in a controlled SO2 emission rate of 0.21 lb per MMBtu, based 

on an uncontrolled SO2 emission rate of 1.20 lb per MMBtu. Therefore, this option cannot meet 

the presumptive limit of 0.15 lb per MMBtu of SO2, and is eliminated from further analysis. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

When evaluating the control effectiveness of SO2 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 SO2 on a BART-eligible coal burning unit is 95 percent removal, or 

0.15 lb per MMBtu. 

The projected emission rate for an upgraded wet sodium FGD system for Jim Bridger 1 would 

be 0.10 lb per MMBtu. This option would meet the presumptive SO2 limit of 0.15 lb per 

MMBtu. 

Step 4: Evaluate Impacts and Document the Results 

This step involves the consideration 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 reheating by the bypassed flue gas. 

Economic Impacts. A summary of the costs and amount of SO2 removed for the upgraded wet 

sodium FGD system is provided in Table 3-5. The complete economic 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 SO2 emissions (meeting 

presumptive limit of 0.15 lb per MMBtu), reasonable control costs, and 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 

SO2 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 (SO2) Design Control 

Efficiency 

62.5% (91.7% based on Uncontrolled SO2) 

Incremental Tons SO2 Removed per Year 3,950 

First Year Average Control Cost (dollars per ton 

[$/Ton] of SO2 Removed) 632 

Incremental Control Cost 

($/Ton of SO2 Removed) 632 

3.2.3 BART PM10 Analysis 

Jim Bridger 1 is currently equipped with an ESP. Electrostatic precipitators remove particulate 

matter (PM) from the flue gas stream by charging 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 PM10 emissions to levels below 0.045 lb per MMBtu. 

The BART analysis for PM10 emissions at Jim Bridger 1 is described below. For the modeling 

analysis in Section 4, PM10 was used as an indicator for PM, and PM10 includes particulate 

matter less than 2.5 micrometers in aerodynamic diameter (PM2.5) as a subset. 

Step 1: Identify All Available Retrofit Control Technologies 

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

• Flue gas conditioning 

• Polishing fabric filter (baghouse) downstream of existing ESP 

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

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

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

lower costs, installation of a full-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 accomplished by injection of sulfur trioxide (SO3), will 

lower the resistivity of the particles so that they will accept more 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 licensed by the Electric Power Research Institute, and 

referred to as a COHPAC (Compact Hybrid Particulate 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 size of a full-size fabric filter, 

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

fabric filter (3.5 to 4:1). This technology is retained as technically feasible. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

The existing ESP at Jim Bridger 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 approximately 0.015 lb per MMBtu. 

The PM10 control technology emission rates are summarized in Table 3-6. 

TABLE 3-6 

PM10 Control Technology Emission Rates 

Jim Bridger 1 

Control Technology Short-Term Expected PM10(a) Emission Rate 

(pounds per million British thermal units) 

Flue Gas Conditioning 0.030 

Polishing Fabric Filter 0.015 

NOTES:

(a)PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter 

Step 4: Evaluate Impacts and Document the Results 

This step involves the consideration 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 associated ductwork. Therefore, a COHPAC retrofit will require an 

internal diameter fan upgrade and upgrade of the auxiliary power supply system. 

A COHPAC fabric filter at Jim Bridger 1 would require approximately 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 approximately 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 control costs for FGC and fabric filters are shown in 

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

TABLE 3-7 

PM10 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, reasonable control cost, minimum additional power 

requirements, and no environmental impacts. 

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
B

FIGURE 3-5 First Year Control Cost for PM Air Pollution Control Options Jim Bridger 1 

0

2,0004,0006,0008,000

10,00012,00014,00016,00018,00020,000

Flue Gas Conditioning Fabric Filter

Air Pollution Control Option

Control Cost ($/Ton PM Removed)

First Year Average Control Cost First Year Incremental Control Co

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 
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 kilometers, 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 algorithms for chemical transformation and 

deposition, and a post processor capable of calculating concentrations, visibility impacts, and 

deposition (CALPOST). The CALPUFF modeling system 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 generate 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 facility and allow for a 50-kilometer buffer around 

the Class I areas that were within 300 kilometers 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 Department 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 latitude of the projection origin and the longitude of the central 

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

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

distortion in the north-south direction. 

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 4-1
Bridger

Wilderness Area Fitzpatrick Wilderness Area

Mount ZirkelWilderness Area

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

0 

Jim 

Class 

Sta

Sta

Dom

114° 5' 20.40" Longitude39° 3' 53.37" Latitude

100° 56' 34.08" Longitude45° 51' 57.22" Latitude

101° 54' 25.88" Longitude38° 54' 0.04" Latitude

114° 28' 37.96" Longitude46° 6' 26.20" Latitude

Jim Bridger

SLC \\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, Inc.’s (TRC) current example 

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

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

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

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

appear in Table 3 of Appendix B. Table 4-1 lists the key user-specified 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 produce 3 years of analysis: 2001, 2002, and 2003. 

WDEQ-AQD provided 12-kilometer resolution Mesoscale Meteorological Model, Version 5 

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

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

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

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

JMS EY102007001SLC\BART_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 refined using local surface observations to create a final Step 2 

wind field. 

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

CH2M HILL processed the data from the 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, roughness length, and leaf area index were computed 

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

Model data, which 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 for 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 CALMET 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-air weather maps (National Oceanic and 

Atmospheric Administration, 2006). 
RAP (UA)

P60

WRL

TOR

SHR

RKS

RIW (UA)

RWL

LAR

LND

GEY

GCC

EVW

DGW

CYS

CPR

BYG

BPI

VEL

SLC (UA)

PUC

OGD

LGU

DLN

RXE

PIH

IDA

LLJ

BYI

RIL

EEO

LIC LXV

GJT

DEN (UA)

APA

CAG

ITR

ASE

AKO

BridgerWilderness Area

FitzpatrickWilderness Area

Mount ZirkelWilderness Area

Idaho

Utah

Wyoming

Montana

K

Colorado

Nebraska

Nevada

South Dakota

North Dakota

Oregon

Washington

RAP

IEN

PHP

D07

CUT

2WX

SNY

BFF

CDR

AIA

LVM

DLN

BTM

BZN BIL

0 

Surface and Upper A

Jim 

Sta

Sta

Dom

114° 5' 20.40" Longitude39° 3' 53.37" Latitude

100° 56' 34.08" Longitude45° 51' 57.22" Latitude

101° 54' 25.88" Longitude38° 54' 0.04" Latitude

114° 28' 37.96" Longitude46° 6' 26.20" Latitude

Jim Bridger

SLC \\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 was used to predict 

visibility impacts for the pre-control (baseline) scenario for 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 concentrations were used by CALPUFF for the 

calculation of SO2 and NOx 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 ammonia 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 modeling reflect those that are in place under the 

current permit for Jim Bridger 1. Post-control stack parameters reflect the anticipated 

changes associated with installation of the control technology alternatives 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 worst-case situation. 

4.3.3 Emission Rates 

Pre-control emission rates for Jim Bridger 1 reflect 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 emission monitoring data to determine peak 24-hour 

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

more recent period was more representative. Allowable short-term (24-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 emission monitoring data 

were not available. 

Emissions were modeled for the following pollutants: 

• SO2

• NOx

• Coarse particulate (PM2.5<diameter<PM10) 

• Fine particulate (diameter<PM2.5) 

• Sulfates 

Post-control emission rates reflect the effects 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 developed to cover the range of effectiveness for 

the combination of the individual NOx, SO2, and PM control technologies being evaluated. 

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

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

levels for each pollutant. 

• Scenario 1: New LNB with OFA modifications, 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 NOx 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 NOx, SO2, and PM controls alone was not performed 

because any final BART solution will include a combination of control technologies for NOx, 

SO2, and PM. 

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

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

protocol, elemental carbon stack emissions and organic aerosol emissions were not modeled.
TABLE 4-2 

BART Model Input Data Jim Bridger 1 

Baseline Post-control Scenario 1 Post-con

Current Operations with 

Wet Flue Gas 

Desulfurization (FGD) and 

Electrostatic Precipitator 

(ESP) 

Low-NOx Burner (LNB) with Over-fire 

Air (OFA), Upgrade Wet FGD, and Flue 

Gas Conditioning (FGC) for Enhanced 

ESP Performance 

LNB with O

FGD, Ne

Sulfur Dioxide (SO2) Stack Emissions pounds per hour (lb/hr) 1,602 600 Nitrogen Oxide (NOx) Stack Emissions (lb/hr) 2,700 1,440 

PM10 Stack Emissions (lb/hr) 270 180 

Coarse Particulate (PM2.5<diameter<PM10) Stack Emissions (lb/hr)(a) 116 77.4 

Fine Particulate (diameter<PM2.5) Stack Emissions (lb/hr)(b) 154 103 

Sulfuric Acid (H2SO4) Stack Emissions (lb/hr) 55.2 55.2 

H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) 54.1 54.1 

Ammonium Sulfate [(NH4)2SO4] Stack Emissions (lb/hr) 

(NH4)2SO4 as SO4 Stack Emissions (lb/hr) 

(NH4)HSO4 Stack Emissions (lb/hr) 

(NH4)HSO4 as SO4 Stack Emissions (lb/hr) 

Total Sulfate (SO4) (lb/hr) 54.1 54.1 

Stack Conditions

Stack Height (meters) 152 152 Stack Exit Diameter (meters) 7.32 7.32 Stack Exit Temperature (Kelvin) 333 322 

Stack Exit Velocity (meters per second)(c) 25.6 24.7 

NOTES:

(a)Based on AP-42, Table 1.1-6, the coarse particulates are counted as a percentage of PM10. This equates to 43 percent ESP and 57 percent Baghouse. PM10 and PM2.5 refer to pa

diameter. 

(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 at the lower, correct velocity of 81.24 feet per second due to lack of time and the fact that the conclusions to select Scenario 1 would no

Total Sulfate (SO4) (lb/hr) = H2SO4 as Sulfate (SO4) Stack Emissions (lb/hr) + (NH4)2SO4 as SO4 Stack Emissions (lb/hr) + (NH4)HSO4 as SO4 Stack 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 were placed at uniform receptor spacing along 

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

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

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

Conformal Conic coordinates, including receptors, 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 extinction were made for each pollutant 

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

relative to natural background. The following default light extinction coefficients for each 

pollutant, as shown below, were used: 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

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

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

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

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

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

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

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

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

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

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

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

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

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 percent best days dV value for that area would 

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

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

2005). However, the Wyoming BART Air Modeling 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 results 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 baseline and the post-control scenarios. The postcontrol scenario included emission rates for SO2, NOx, and PM10 that would be achieved if 

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

Baseline (and post-control) 98th percentile results were greater than 0.5 ΔdV for the 

Bridger, WA, Fitzpatrick, WA, and Mt. Zirkel, WA. The 98th percentile results for each 

Class I area are presented in Table 4-4. 
TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Jim Bridger 1

Modeling 

Scenario 

Total First Year 

Annualized Cost Class I Area 

Highest Delta 

Deciview (ΔdV) 

2001 

Bridger WA 2.504 

Fitzpatrick WA 2.177 

Baseline: Current Operation with Wet Flue Gas Desulfurization (FGD), Electrostatic Precipitator (ESP) 

Mt. Zirkel WA 1.966 

$3,392,440 Bridger WA 1.364 

$3,392,440 Fitzpatrick WA 1.369 

Scenario 1: Low-NOx Burners (LNBs) with Over-fire Air (OFA), upgrade wet FGD, Flue Gas Conditioning (FGC) for enhanced ESP performance 

$3,392,440 Mt. Zirkel WA 1.167 

$9,759,059 Bridger WA 1.393 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter $9,759,059 Fitzpatrick WA 1.171 

$9,759,059 Mt. Zirkel WA 1.099 

$18,093,916 Bridger WA 0.876 

$18,093,916 Fitzpatrick WA 0.675 

Scenario 3: LNB with OFA and Selective Catalytic Reduction (SCR), upgrade wet FGD, FGC for enhanced ESP performance 

$18,093,916 Mt. Zirkel WA 0.756 

$24,460,535 Bridger WA 0.838 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter $24,460,535 Fitzpatrick WA 0.654 

$24,460,535 Mt. Zirkel WA 0.729 

2002 

Bridger WA 4.104 

Baseline: Current Operation with Wet FGD, ESP Fitzpatrick WA 1.894 

Mt. Zirkel WA 2.801 

$3,392,440 Bridger WA 2.454 

Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance $3,392,440 Fitzpatrick WA 1.078 

$3,392,440 Mt. Zirkel WA 1.544 

$9,759,059 Bridger WA 2.326 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter $9,759,059 Fitzpatrick WA 1.002 

$9,759,059 Mt. Zirkel WA 1.496 

$18,093,916 Bridger WA 1.321 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance $18,093,916 Fitzpatrick WA 0.549 

$18,093,916 Mt. Zirkel WA 0.887 $24,460,535 Bridger WA 1.295 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter $24,460,535 Fitzpatrick WA 0.539 

$24,460,535 Mt. Zirkel WA 0.869 

JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_JB1_OCT2007_FINAL.DOC TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-control Scenarios at Class I Areas Jim Bridger 1

Modeling 

Scenario 

Total First Year 

Annualized Cost Class I Area 

Highest Delta 

Deciview (ΔdV) 

2003 

Bridger WA 1.706 

Baseline: Current Operation with wet FGD, ESP Fitzpatrick WA 1.933 

Mt. Zirkel WA 1.958 

$3,392,440 Bridger WA 0.997 

Scenario 1: LNB with OFA, upgrade we $3,392,440 Fitzpatrick WA 1.112 

t FGD, FGC for enhanced ESP performance 

$3,392,440 Mt. Zirkel WA 1.042 

$9,759,059 Bridger WA 0.985 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter $9,759,059 Fitzpatrick WA 1.087 

$9,759,059 Mt. Zirkel WA 1.057 

$18,093,916 Bridger WA 0.853 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance $18,093,916 Fitzpatrick WA 0.681 

$18,093,916 Mt. Zirkel WA 0.669 $24,460,535 Bridger WA 0.810 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter $24,460,535 Fitzpatrick WA 0.662 

$24,460,535 Mt. Zirkel WA 0.636 

3-year Averages 

Bridger WA 

Baseline: Current Operation with wet FGD, ESP Fitzpatrick WA 

Mt. Zirkel WA 

$3,392,440 Bridger WA 

Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance $3,392,440 Fitzpatrick WA 

$3,392,440 Mt. Zirkel WA 

$9,759,059 Bridger WA 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter $9,759,059 Fitzpatrick WA 

$9,759,059 Mt. Zirkel WA 

$18,093,916 Bridger WA 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance $18,093,916 Fitzpatrick WA 

$18,093,916 Mt. Zirkel WA $24,460,535 Bridger WA 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter $24,460,535 Fitzpatrick WA 

$24,460,535 Mt. Zirkel WA 

NOTES: Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $3,392,440 / (0.7964 - 0.427) = $9,193,605 Sample Calculations: Cost per Reduction in No. of Days Exceeding 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 economic evaluations, and consideration of the 

modeling analysis for Jim Bridger 1, the preliminary recommended BART controls for NOx, 

SO2, and PM are as follows:

• New LNBs and modifications to the OFA system for NOx control

• Upgrade wet sodium FGD for SO2 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 improvements 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 Section 4 to determine the impact on the three 

Class I areas are listed in Tables 5-1 through 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 98th percentile ΔdV 

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 states that “Incremental cost-effectiveness 

comparisons should focus on annualized cost and emission reduction differences between 

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

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

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

BACT analysis...” 

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

performed in the following way. First, the control 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 option scenarios is plotted 

for each analysis. Figures 5-1 through 5-6 present 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 incremental costs, the analysis 

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

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

least-cost envelope depicted by the curvilinear line connecting them. Scenario 2 is an inferior 

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

Scenario 2 represents an inferior control, because Scenario 1 provides approximately the 

same amount of visibility impact reduction for less cost than Scenario 2. The incremental 

cost effectiveness is determined by the difference in total annual costs between two 

contiguous scenarios divided by the difference in emissions reduction. 

TABLE 5-1 

Control Scenario Results for the Bridger Class I Wilderness Area 

Jim Bridger 1 

Scenario Controls 

98th

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-NOx 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 

98th

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-NOx 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 

98th

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-NOx 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 6 810 12 14

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

16

FIGURE 5-2 

Least-cost Envelope Bridger Class I WA 98th 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 98th 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 98th 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 through 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, which 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 illustrates the conclusions stated above. The greatest reduction in 98th

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 reasonable at $300,000 per day and $7.7 million per dV. 

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

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

Jim Bridger 1. 

5.2 Recommendations 

5.2.1 NOx Emission Control 

The BART presumptive NOx limit assigned by EPA for tangentially-fired boilers burning 

sub-bituminous coal is 0.15 lb per MMBtu. However, 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 NOx limit of 0.28 lb per MMBtu. 

CH2M HILL recommends the existing low-NOx burners with over-fire air (LNB with OFA) as 

BART for Jim Bridger 1, based on the projected significant reduction in NOx emissions, 

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

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

realized at Jim Bridger 2. CH2M HILL recommends that the unit be permitted at a rate of 

0.26 lb per MMBtu. 

5.2.2 SO2 Emission Control 

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

Jim Bridger 1, based on the significant reduction in SO2 emissions, reasonable control costs, 

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

environmental impacts. This upgrade approach will meet the BART presumptive SO2 limit of 

0.15 lb per MMBtu. 

5.2.3 PM10 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 PM10 emissions, reasonable control costs, and the advantages of minimal additional power 

requirements and no non-air quality environmental impacts. 

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

Haze” by Dr. Ronald Henry of the University of Southern California (Henry, 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 natural obscuration where 

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

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

that lasted for many days and could have had 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 effect would be to increase the costs per dV 

reduction that are presented in this report. 
6.0 References 

40 CFR Part 51. Regional Haze Regulations and Guidelines 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 Visibility Conditions Under the Regional Haze 

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

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

Waste Management Association. Volume 52, p. 1238. 

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

http://docs.lib.noaa.gov/rescue/dwm/data_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—Individual 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 Analysis
PacifiCorp BART Analysis Scenarios

3

Index No. Name of Unit

1 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 3

10 Wyodak Unit 1

Scenario First Year Cost Scenario

 First Year 

Cost Scenario First Year Cost Scenar

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

 N/A N/A N/A 

Scenario First Year Cost Scenario First Year Scenario First Year Cost Scenar

 $ 3,392,440 N/A N/A  $ 3,392,440 N/A N/A  $ 3,392,440 N/A N/A  $ 9,759,059 N/A N/A  $ 9,759,059 N/A N/A  $ 9,759,059 N/A N/A  $ 18,093,916 N/A N/A  $ 18,093,916 N/A N/A  $ 18,093,916 N/A N/A  $ 24,460,535 N/A N/A  $ 24,460,535 N/A N/A  $ 24,460,535 N/A N/A 

Scenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric Filter

Scenario 1 - LNB with OFA, Dry FGD, Fabric Filter

Baseline - Current Operation with ESPScenario 1 - LNB with OFA, Dry FGD, Existing ESPScenario 2 - LNB with OFA, Dry FGD, New Fabric Filter

Jim Bridger

Select Unit:

Scenario 2 - LNB with OFA, Wet FGD, New Fabric FilterScenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric FilterScenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

DJ Unit 4

Scenario 4 - LNB with OFA and SCR, Wet FGD, Existing ESP, New Stack

Dave Johnston

DJ Unit 3

Baseline - Current Operation with Venturi Scrubber 

JB Unit 1 JB Unit 2 JB Unit 3 

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current Operation with Wet FGD and ESP

Baseline - Current OWet FGD and ESP

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Scenario 2 - LNB witFGD, Fabric Filter

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB with OFA, Wet FGD, ESP

Scenario 1 - LNB witFGD, ESP

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB with OFA and SCR, Wet FGD, Fabric Filter

Scenario 4 - LNB witSCR, Wet FGD, Fab

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB with OFA and SCR, Wet FGD, ESP

Scenario 3 - LNB witSCR, Wet FGD, ESP

Scenario 2 - LNB with OFA, Wet FGD, New Fabric Filter

Baseline - Current Operation with ESP

Baseline - Current OESP

NTN Unit 1 

Scenario 2 - LNB with OFA, Dry FGD, New Fabric Filter

Scenario 2 - LNB witFGD, New Fabric Fil

Scenario 1 - LNB with OFA, Dry FGD, ESP

Scenario 1 - LNB witFGD, ESP

Scenario 3 - LNB with OFA and SCR, Dry FGD, New Fabric Filter

Scenario 3 - LNB witSCR, Dry FGD, New 

Jim Bridger Unit 1

Scenario 4 - LNB with OFA and SCR, Wet FGD, ESP, New Stack

Scenario 4 - LNB witSCR, Wet FGD, ESP

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
ECONOMIC ANALYSIS SUMMARY

Jim Bridger Unit 1 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Up

Case 1 2 3 4 5 

NOx Emission Control System

LNCFS-1 & 

Windbox Mods. LNB w/OFA ROFA

LNB w/OFA & 

SNCR

LNB w/OFA & 

SCR

LNC

SO2 Emission Control System Wet FGD Wet FGD Wet FGD Wet FGD Wet FGD UpgPM Emission Control System ESP ESP ESP ESP ESP 

TOTAL INSTALLED CAPITAL COST ($) 0 8,700,001 20,528,122 22,127,239 129,575,495 FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 Maintenance Material ($) 0 28,000 42,000 123,000 190,000 Maintenance Labor ($) 0 42,000 63,000 184,500 285,000 Administrative Labor ($) 0 0 0 0 0 TOTAL FIXED O&M COST 0 70,000 105,000 307,500 475,000 

Makeup Water Cost 0 0 0 0 0 Reagent Cost 0 0 0 1,005,811 912,848 SCR Catalyst / FF Bag Cost 0 0 0 0 594,000 Waste Disposal Cost 0 0 0 0 0 Electric Power Cost 0 0 2,528,012 208,926 1,291,005 TOTAL VARIABLE O&M COST 0 0 2,528,012 1,214,737 2,797,853 

TOTAL FIRST YEAR O&M COST 0 70,000 2,633,012 1,522,237 3,272,853 

FIRST YEAR DEBT SERVICE ($) 0 827,612 1,952,796 2,104,916 12,326,235 TOTAL FIRST YEAR COST ($) 0 897,612 4,585,808 3,627,153 15,599,088 

Power Consumption (MW) 0.0 0.0 6.4 0.5 3.3 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 50.6 4.2 25.8 

CONTROL COST ($/Ton Removed)

NOx Removal Rate (%) 0.0% 46.7% 51.1% 55.6% 84.4% 

NOx Removed (Tons/Yr) 0 4,967 5,440 5,913 8,987 First Year Average Control Cost ($/Ton NOx Rem.) 0 181 843 613 1,736 

Incremental Control Cost ($/Ton NOx Removed) 0 181 7,797 2,885 3,894 

2-1 3-2 4-2 5-4

SO2 Removal Rate (%) 77.8% 0.0% 0.0% 0.0% 0.0% 

SO2 Removed (Tons/Yr) 0 0 0 0 0 First Year Average Control Cost ($/Ton SO2 Rem.) 0 0 0 0 0 

Incremental Control Cost ($/Ton SO2 Removed) Base 0 0 0 0 

PM Removal Rate (%) 99.47% 0.00% 0.00% 0.00% 0.00% 

PM Removed (Tons/Yr) 0 0 0 0 0 First Year Average Control Cost ($/Ton PM Rem.) 0 0 0 0 0 

Incremental Control Cost ($/Ton PM Removed) Base 0 0 0 0 

PRESENT WORTH COST ($) 0 9,555,250 52,697,883 40,725,706 169,562,733 

NOx Control 

Parameter Current Operation

SO

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
INPUT CALCULATIONS

Jim Bridger Unit 1 Boiler Design: Tangential-Fired PC

LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Upgraded 

FGD 

Case 1 2 3 4 5 8 

NOx Emission Control System

LNCFS-1 & 

Windbox Mods. LNB w/OFA ROFA

LNB w/OFA & 

SNCR LNB w/OFA & SCR

LNCFS-1 & W

Mods.

SO2 Emission Control System Wet FGD Wet FGD Wet FGD Wet FGD Wet FGD Upgraded WePM Emission Control System ESP ESP ESP ESP ESP ESPUnit Design and Coal CharacteristicsType of Unit PC PC PC PC PC PC Net Power Output (kW) 530,000 530,000 530,000 530,000 530,000 530,00

Net Plant Heat Rate (Btu/kW-Hr) 11,320 11,320 11,320 11,320 11,320 11,320 Boiler Fuel

Bridger Mine 

Underground

Bridger Mine 

Underground

Bridger Mine 

Underground

Bridger Mine 

Underground

Bridger Mine 

Underground

Bridger M

Undergro

Coal Heating Value (Btu/Lb) 9,660 9,660 9,660 9,660 9,660 9,660 

Coal Sulfur Content (wt.%) 0.58% 0.58% 0.58% 0.58% 0.58% 0.581% 

Coal Ash Content (wt.%) 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 Coal Flow Rate (Lb/Hr) 621,077 621,077 621,077 621,077 621,077 621,07 (Ton/Yr) 2,448,284 2,448,284 2,448,284 2,448,284 2,448,284 2,448,28 (MMBtu/Yr) 47,300,846 47,300,846 47,300,846 47,300,846 47,300,846 47,300,8

Emissions

Uncontrolled SO2 (Lb/Hr) 7,210 1,602 1,602 1,602 1,602 1,602  (Lb/MMBtu) 1.20 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  (Tons/Yr) 28,421 6,315 6,315 6,315 6,315 6,315 SO2 Removal Rate (%) 77.8% 0.0% 0.0% 0.0% 0.0% 62.5%  (Lb/Hr) 5,608 0 0 0 0 1,002  (Ton/Yr) 22,106 0 0 0 0 3,950 SO2 Emission Rate (Lb/Hr) 1,602 1,602 1,602 1,602 1,602 600  (Lb/MMBtu) 0.27 0.27 0.27 0.27 0.27 0.10 

 (Ton/Yr) 6,315 6,315 6,315 6,315 6,315 2,365 Uncontrolled NOx (Lb/Hr) 2,700 2,700 2,700 2,700 2,700 2,700  (Lb/MMBtu) 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  (Tons/Yr) 10,643 10,643 10,643 10,643 10,643 10,643 NOx Removal Rate (%) 0.0% 46.7% 51.1% 55.6% 84.4% 0% 

 (Lb/Hr) 0 1,260 1,380 1,500 2,280 0  (Lb Moles/Hr) 0.00 41.98 45.98 49.98 75.97 0.00  (Ton/Yr) 0 4,967 5,440 5,913 8,987 0 NOx Emission Rate (Lb/Hr) 2,700 1,440 1,320 1,200 420 2,700  (Lb/MMBtu) 0.45 0.24 0.22 0.20 0.07 0.45 

 (Ton/Yr) 10,643 5,676 5,203 4,730 1,656 10,643 Uncontrolled Fly Ash (Lb/Hr) 51,177 270 270 270 270 270  (Lb/MMBtu) 8.530 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  (Tons/Yr) 201,739 1,064 1,064 1,064 1,064 1,064 Fly Ash Removal Rate (%) 99.47% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 50,907 0 0 0 0 0  (Ton/Yr) 200,674 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 270 270 270 270 270 270  (Lb/MMBtu) 0.045 0.045 0.045 0.045 0.045 0.045 

 (Ton/Yr) 1,064 1,064 1,064 1,064 1,064 1,064 

Parameter 

Current Operation NOx Control 

SO2 Con

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
LNB w/OFA ROFA LNB w/OFA & SNCR LNB w/OFA & SCR Upgraded 

FGD 

Case 1 2 3 4 5 8 

Parameter 

Current Operation NOx Control 

SO2 Con

General Plant DataAnnual Operation (Hours/Year) 7,884 7,884 7,884 7,884 7,884 7,884 Annual On-Site Power Plant Capacity Factor 0.90 0.90 0.90 0.90 0.90 0.90 

Economic Factors

Interest Rate (%) 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% Plant Economic Life (Years) 20 20 20 20 20 20 

Installed Capital Costs

NOx Emission Control System ($2006) 0 8,700,001 20,528,122 22,127,239 129,575,495 0

SO2 Emission Control System ($2006) 0 0 0 0 0 12,999,9

PM Emission Control System ($2006) 0 0 0 0 0 0 

Total Emission Control Systems ($2006) 0 8,700,001 20,528,122 22,127,239 129,575,495 12,999,9

NOx Emission Control System ($/kW) 0 16 39 42 244 0 SO2 Emission Control System ($/kW) 0 0 0 0 0 25 PM Emission Control System ($/kW) 0 0 0 0 0 0 Total Emission Control Systems ($/kW) 0 16 39 42 244 25 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 00000 0 Maintenance Material ($) 0 28,000 42,000 123,000 190,000 25,550 Maintenance Labor ($) 0 42,000 63,000 184,500 285,000 17,033 Administrative Labor ($) 00000 0 

Total Fixed O&M Cost ($) 0 70,000 105,000 307,500 475,000 42,583 

Annual Fixed O&M Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Water CostMakeup Water Usage (Gpm) 0 0 0 0 0 53 Unit Price ($/1000 Gallons) 1.22 1.22 1.22 0.00 1.22 1.22 

First Year Water Cost ($) 0 0 0 0 0 30,503 

Annual Water Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% Reagent Cost None None None Urea Anhydrous NH3 Soda As

Unit Cost ($/Ton) 0.00 0.00 0.00 370 400 80.00  ($/Lb) 0.000 0.000 0.000 0.185 0.200 0.040 Molar Stoichiometry 0.00 0.00 0.00 0.45 1.00 1.02 Reagent Purity (Wt.%) 100% 100% 100% 100% 100% 100% 

Reagent Usage (Lb/Hr) 0 0 0 690 579 1,691 

First Year Reagent Cost ($) 0 0 0 1,005,811 912,848 533,20

Annual Reagent Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% SCR Catalyst / FF Bag Replacement Cost SCR Catalyst Bags 

Annual SCR Catalyst (m3) / No. FF Bags 0000 198 0 

SCR Catalyst ($/m3) / Bag Cost ($/ea.) 3,000 3,000 3,000 3,000 3,000 104 

First Year SCR Catalyst / Bag Replace. Cost ($) 0 0 0 0 594,000 0 

Annual SCR Catalyst / Bag Cost Esc. Rate (%) 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 FGD Waste Disposal Unit Cost ($/Dry Ton) 24.33 24.33 24.33 24.33 24.33 24.33 

First Year FGD Waste Disposal Cost ($) 0 0 0 0 0 442,95

Annual Waste Disposal Cost Esc. Rate (%) 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%  (MW) 0.00 0.00 6.41 0.53 3.28 0.53 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 2,528,012 208,926 1,291,005 208,92

Annual Power Cost Escalation Rate (%) 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Input Tables

Table 1 - Cases

Existing

1 2 3 4 5 6 7 8 

1 Dave Johnston Unit 3 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

2 Dave Johnston Unit 4 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A 

Dry FGD w/Fabric 

Filter

Wet FGD w/Fa

Filter 

3 Jim Bridger Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

4 Jim Bridger Unit 2 Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A

 Upgraded W

FGD 

5 Jim Bridger Unit 3 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

6 Jim Bridger Unit 4 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR N/A N/A

 Upgraded W

FGD 

7 Naughton Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

8 Naughton Unit 2 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

 LNB w/OFA & 

SCR Dry FGD w/ESP 

Dry FGD w/Fabric 

Filter Wet FGD w/E

9 Naughton Unit 3 Current Operation Exist. LNB w/OFA ROFA SNCR SCR N/A N/A

 Upgraded W

FGD 

10 Wyodak Unit 1 Current Operation LNB w/OFA ROFA LNB w/OFA & SNCR

LNB w/OFA & 

SCR Upgraded Dry FGD N/A Wet FGD 

Table 2 - Unit Design and Coal Characteristics

NOx SO2 PM Boiler Design

Net Power 

Output (kW)

Net Plant Heat 

Rate (Btu/kWHr) Coal Heating Val

HHV (Btu/L

1 Dave Johnston Unit 3 None None ESP

3-Cell Burner, Opposed 

Wall-Fired PC 250,000 11,200 Dry Fork PRB 7,7

2 Dave Johnston Unit 4 Windbox Mods.

Lime Added to Venturi 

Scrubber Venturi Scrubber Tangential-Fired PC 360,000 11,390 Dry Fork PRB 7,7

3 Jim Bridger Unit 1

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

4 Jim Bridger Unit 2 LNB - TFS 2000 Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

5 Jim Bridger Unit 3

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

6 Jim Bridger Unit 4

LNCFS-1 & 

Windbox Mods. Wet FGD ESP Tangential-Fired PC 530,000 11,320 

Bridger Mine 

Underground 9,6

7 Naughton Unit 1 None None ESP Tangential-Fired PC 173,000 10,694 Kemmerer Mine 9,98 Naughton Unit 2 None None ESP Tangential-Fired PC 226,000 10,574 Kemmerer Mine 9,99 Naughton Unit 3 LNCFS II LNB Wet FGD ESP Tangential-Fired PC 356,000 10,336 Kemmerer Mine 9,9

10 Wyodak Unit 1 LNB Dry FGD ESP Opposed Wall-Fired PC 335,000 12,087 Clovis Point Mine 7,9

Index No. Name of Unit | Case --->

NOx Control SO2 Control 

Current Emission Control Systems Unit Design Co

Index No. Name of Unit

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Table 3 - Emissions

Controlled 

SO2 Controlled NOx

Controlled 

PM Case 2 Case 3 Case 4 Case 5 Case 6 

1 Dave Johnston Unit 3 1.20 0.70 0.200 0.27 0.21 0.20 0.07 0

 

2 Dave Johnston Unit 4 0.33 0.48 0.061 0.15 0.19 0.12 0.07 N3 Jim Bridger Unit 1 0.27 0.45 0.045 0.24 0.22 0.20 0.07 N

4 Jim Bridger Unit 2 0.27 0.24 0.074 0.24 0.22 0.20 0.07 N5 Jim Bridger Unit 3 0.27 0.45 0.057 0.24 0.22 0.20 0.07 N6 Jim Bridger Unit 4 0.17 0.45 0.030 0.24 0.22 0.20 0.07 N7 Naughton Unit 1 1.20 0.58 0.056 0.24 0.28 0.18 0.07 0

 

8 Naughton Unit 2 1.20 0.54 0.064 0.24 0.28 0.18 0.07 0

 

9 Naughton Unit 3 0.50 0.45 0.094 0.35 0.30 0.25 0.07 N

10 Wyodak Unit 1 0.50 0.50 0.030 0.23 0.18 0.22 0.07 

0

Table 4 - Case 1 O&M Costs (Current Operation)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (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. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (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 Unit

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

Current Emission Rates (Lb/MMBtu) NOx Control Emission Rates (Lb/MMBtu) SO2 Con

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Table 6 - Case 3 O&M Costs (Mobotec ROFA)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (MW

1 Dave Johnston Unit 3 $ 60,000 - $ 90,000 $ - $ - None - 22 Dave Johnston Unit 4 $ 54,000 - $ 81,000 $ $ - - None - 43 Jim Bridger Unit 1 $ 42,000 - $ 63,000 $ $ - - None - 64 Jim Bridger Unit 2 $ 42,000 - $ 63,000 $ $ - - None - 65 Jim Bridger Unit 3 $ 42,000 - $ 63,000 $ $ - - None - 66 Jim Bridger Unit 4 $ 42,000 - $ 63,000 $ $ - - None - 67 Naughton Unit 1 $ 48,000 - $ 72,000 $ $ - - None - 18 Naughton Unit 2 $ 48,000 - $ 72,000 $ $ - - None - 29 Naughton Unit 3 $ 48,000 - $ 72,000 $ $ - - None - 4

10 Wyodak Unit 1 $ 36,000 - $ 54,000 $ $ - None - - 5

Table 7 - Case 4 O&M Costs (LNB w/OFA & SNCR))

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Aux. Powe

Usage (MW

1 Dave Johnston Unit 3 $ 98,000 - $ 147,000 $ - $ - Urea 0.41 02 Dave Johnston Unit 4 $ 105,000 - $ 157,500 $ $ - - Urea 0.45 03 Jim Bridger Unit 1 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 04 Jim Bridger Unit 2 $ 95,000 - $ 142,500 $ $ - - Urea 0.45 05 Jim Bridger Unit 3 $ 122,000 - $ 183,000 $ $ - - Urea 0.45 06 Jim Bridger Unit 4 $ 123,000 - $ 184,500 $ $ - - Urea 0.45 07 Naughton Unit 1 $ 83,000 - $ 124,500 $ $ - - Urea 0.45 08 Naughton Unit 2 $ 93,000 - $ 139,500 $ $ - - Urea 0.51 09 Naughton Unit 3 $ 75,000 - $ 112,500 $ $ - - Urea 0.45 0

10 Wyodak Unit 1 $ 93,000 - $ 139,500 $ - Urea - 0.45 0

Table 8 - Case 5 O&M Costs (LNB w/OFA & SCR))

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual SC

Catalyst 

Replace. (m

1 Dave Johnston Unit 3 $ 155,000 - $ 232,500 $ - $ - Anhydrous NH3 1.00 1

 

2 Dave Johnston Unit 4 $ 166,000 - $ 249,000 $ $ - - Anhydrous NH3 1.00 1

 

3 Jim Bridger Unit 1 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 1

 

4 Jim Bridger Unit 2 $ 162,000 - $ 243,000 $ $ - - Anhydrous NH3 1.00 1

 

5 Jim Bridger Unit 3 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 2

 

6 Jim Bridger Unit 4 $ 190,000 - $ 285,000 $ $ - - Anhydrous NH3 1.00 2

 

7 Naughton Unit 1 $ 132,000 - $ 198,000 $ $ - - Anhydrous NH3 1.00 

 

8 Naughton Unit 2 $ 160,000 - $ 240,000 $ $ - - Anhydrous NH3 1.00 1

 

9 Naughton Unit 3 $ 156,000 - $ 234,000 $ $ - - Anhydrous NH3 1.00 1

 

10 Wyodak Unit 1 $ 181,000 - $ 271,500 $ $ - - Anhydrous NH3 1.00 

1

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating RequirementsAnnual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Table 9 - Case 6 O&M Costs (Dry FGD)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 714,175 506,128 $ 476,928 $ - $ 173 Lime 1.15 - 

2 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 1 $ 587,643 506,128 $ 391,762 $ $ - 120 Lime 1.40 - 

8 Naughton Unit 2 $ 860,17 506,128 $ 573,04 4 $ $ - 165 4 Lime 1.40 - 9 Naughton Unit 3 $ - - $ - $ $ - - Lime - - 

10 Wyodak Unit 1 $ 21,900 - $ 14,600 $ - 25 Lime 1.10 

-

Table 10 - Case 7 O&M Costs (Dry FGD w/Fabric Filter)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 714,175 506,128 $ 476,928 $ - $ 173 Lime 1.15 1,4

 

2 Dave Johnston Unit 4 $ 1,102,288 506,128 $ 734,858 $ $ - 248 Lime 1.10 1,7

 

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 1 $ 632,660 506,128 $ 459,286 $ $ - 120 Lime 1.15 8

 

8 Naughton Unit 2 $ 905,190 506,128 $ 640,568 $ $ - 165 Lime 1.15 1,1

 

9 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. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 1,182,587 809,804 $ 788,391 $ - $ 230 Lime 1.02 - 

2 Dave Johnston Unit 4 $ 1,430,78 809,804 $ 953,856 4 $ $ - 330 Lime 1.02 1,7

 

3 Jim Bridger Unit 1 $ 25,550 - $ 17,033 $ $ - 53 Soda Ash 1.02 - 4 Jim Bridger Unit 2 $ 25,550 - $ 17,033 $ $ - 53 Soda Ash 1.02 - 5 Jim Bridger Unit 3 $ 25,550 - $ 17,033 $ $ - 52 Soda Ash 1.02 - 6 Jim Bridger Unit 4 $ 25,550 - $ 17,033 $ $ - 27 Soda Ash 1.02 - 7 Naughton Unit 1 $ 963,589 809,804 $ 642,393 $ $ - 160 Lime 1.05 - 8 Naughton Unit 2 $ 1,226,386 809,804 $ 817,591 $ $ - 220 Lime 1.05 - 9 Naughton Unit 3 $ 21,900 - $ 14,600 $ $ - 66 Soda Ash 1.02 - 

10 Wyodak Unit 1 $ 328,496 303,677 $ 218,998 $ $ - 82 Lime 1.02 

-

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

Index No. Name of Unit

Annual Fixed O&M Costs

Variable Operating RequirementsVariable Operating RequirementsVariable Operating Requirements

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Table 12 - Case 9 O&M Costs (Flue Gas Conditioning)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent 

Usage (Lb/Hr)

Annual FF B

Replace

1 Dave Johnston Unit 3 $ - - $ - $ - $ - None - - 2 Dave Johnston Unit 4 $ - - $ - $ $ - - None - - 3 Jim Bridger Unit 1 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 

4 Jim Bridger Unit 2 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 5 Jim Bridger Unit 3 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 6 Jim Bridger Unit 4 $ - - $ 10,000 $ $ - - Elemental Sulfur 100 - 7 Naughton Unit 1 $ - - $ 10,000 $ $ - - Elemental Sulfur 33 - 8 Naughton Unit 2 $ - - $ 10,000 $ $ - - Elemental Sulfur 43 - 9 Naughton Unit 3 $ - - $ 10,000 $ $ - - Elemental Sulfur 67 - 

10 Wyodak Unit 1 $ - - $ 10,000 $ - - Elemental Sulfur 63 

-

Table 13 - Case 10 O&M Costs (Fabric Filter)

Oper. Labor Maint. Materials Maint. Labor Admin. Labor

Makeup Water 

Use (Gpm) Reagent

Reagent Molar 

Stoich.

Annual FF B

Replace

1 Dave Johnston Unit 3 $ 45,016 - $ 67,524 $ - $ - None - 1,4

 

2 Dave Johnston Unit 4 $ 68,133 - $ 102,199 $ $ - - None - 1,7

 

3 Jim Bridger Unit 1 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

4 Jim Bridger Unit 2 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

5 Jim Bridger Unit 3 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

6 Jim Bridger Unit 4 $ 51,099 - $ 76,649 $ $ - - None - 2,8

 

7 Naughton Unit 1 $ 45,016 - $ 67,524 $ $ - - None - 8

 

8 Naughton Unit 2 $ 45,016 - $ 67,524 $ $ - - None - 1,1

 

9 Naughton Unit 3 $ 48,666 - $ 72,999 $ $ - - None - 1,7

 

10 Wyodak Unit 1 $ 48,666 - $ 72,999 $ $ - - None - 

1,7

Table 14 - Major Materials Design and Supply Costs

2 3 4 5 6 7 8 9 

1 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 $ 

2 Dave Johnston Unit 4 $ 2,673,501 $ 4,343,192 $ 7,171,085 $ 66,200,000 $ - $ 137,267,000 $ 178,174,384 $ 

3 Jim Bridger Unit 1 $ 2,981,982 $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 4 Jim Bridger Unit 2 $ - $ 6,056,955 $ 9,528,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 

5 Jim Bridger Unit 3 $ 2,981,982 $ 6,056,955 $ 9,419,000 $ 80,923,000 $ - $ - $ 8,010,093 $ 

6 Jim Bridger Unit 4 $ 2,981,982 $ 6,056,955 $ 9,528,000 $ 93,009,000 $ - $ - $ 3,549,000 $ 7 Naughton Unit 1 $ 2,502,123 $ 2,675,792 $ 7,257,000 $ 37,292,000 $ 26,819,000 $ 42,301,000 $ 44,000,000 $ 800,0

8 Naughton Unit 2 $ 2,570,674 $ 3,123,533 $ 8,784,000 $ 47,934,000 $ 39,262,000 $ 57,621,000 $ 56,000,000 $ 800,0

9 Naughton Unit 3 $ - $ 4,351,377 $ 11,203,578 $ 67,373,000 $ - $ - $ 2,963,000 $ 800,0

10 Wyodak Unit 1 $ 3,187,636 $ 4,500,245 $ 7,234,860 $ 72,479,000 $ 996,100 $ - $ 178,174,384 $ 1,247,0

NOx Control SO2 Control P

Index No. Name of Unit | Case --->Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

Index No. Name of Unit

Annual Fixed O&M Costs Variable Operating Requirements

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
CAPITAL COST

Jim Bridger Unit 1

CaseNOx Emission Control SystemSO2 Emission Control SystemPM Emission Control System

CAPITAL COST COMPONENT Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Source Cost Factor/Sour

LNB w/OFA or ROFA LNB w/OFA ROFA LNB w/OFA LNB w/OFA

Major Materials Design and Supply Vendor $2,981,982 Vendor $6,056,955 Vendor $2,981,982 Vendor $2,981,982 Vendor $0 Vendor 

Construction 85.3% $2,544,638 85.3% $5,168,628 85.3% $2,544,638 85.3% $2,544,638 85.3% $0 85.3% 

Balance of Plant 51.7% $1,541,451 51.7% $3,130,970 51.7% $1,541,451 51.7% $1,541,451 51.7% $0 51.7% Electrical (Allowance) 0.0% $0 30.0% $1,817,087 0.0% $0 0.0% $0 0.0% $0 0.0% 

Owner's Costs 13.2% $395,063 13.2% $802,446 13.2% $395,063 13.2% $395,063 13.2% $0 13.2% 

Surcharge 16.4% $489,805 16.4% $994,884 16.4% $489,805 16.4% $489,805 16.4% $0 16.4% AFUDC 12.2% $364,352 12.2% $740,067 12.2% $364,352 12.2% $364,352 12.2% $0 12.2% Subtotal $8,317,291 $18,711,036 $8,317,291 $8,317,291 $0 

Contingency 12.8% $382,709 30.0% $1,817,087 12.8% $382,709 12.8% $382,709 12.8% $0 12.8% 

Total Capital Cost for LNB w/OFA or ROFA $8,700,001 $20,528,122 $8,700,001 $8,700,001 $0 

SNCR or SCR SNCR SCR

Major Materials Design and Supply S&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 ReporContingency 20.0% $0 20.0% $0 20.0% $1,905,600 20.0% $16,184,600 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $532,901 5.6% $4,526,023 5.6% $0 5.6% EPC Premium 0.0% $0 0.0% $0 0.0% $0 8.4% $6,835,566 8.4% $0 8.4% Boiler Reinforcement (Allowance) 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% Sales Tax 1.1% $0 1.1% $0 1.1% $104,999 1.1% $891,771 1.1% $0 1.1% 

Escalation 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% $0 0.0% Contingency on Adders 2.8% $0 2.8% $0 2.8% $267,451 2.8% $2,271,509 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $1,088,288 11.4% $9,243,025 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $13,427,239 $120,875,494 $0 

Dry or Wet FGD, FGC or Fabric Filter Dry FGD 

Major Materials Design and Supply S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% $0 5.6% 

EPC Premium 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% $0 8.4% 

Boiler Reinforcement (Allowance) 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% 

Sales Tax 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% $0 1.1% 

Escalation 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% $0 10.1% 

Contingency on Adders 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% $0 11.4% 

Total Capital Cost for Dry/Wet FGD, FGC or FF $0 $0 $0 $0 $0 

NOx Control

2 3 45 

6 

LNB w/OFA & SNCR

Wet FGD

ESP ESP

LNB w/OFA & SCR

Wet FGD

LNCFS-1 & Windbox Mods.

N/A

ESP

Parameter

LNB w/OFA ROFA LNB w/OFA & SCR

LNB w/OFA

Wet FGD

ESP ESP

ROFA

Wet FGD

LNCFS-1 

LNB w/OFA & SNCR N/A 

SO2 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 1 LNB w/OFA

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 70,000 - - - - - - 

 

2 2015 71,400 - - - - - - 

 

3 2016 72,828 - - - - - - 

 

4 2017 74,285 - - - - - - 

 

5 2018 75,770 - - - - - - 

 

6 2019 77,286 - - - - - - 

 

7 2020 78,831 - - - - - - 

 

8 2021 80,408 - - - - - - 

 

9 2022 82,016 - - - - - - 

 

10 2023 83,656 - - - - - - 

 

11 2024 85,330 - - - - - - 

 

12 2025 87,036 - - - - - - 

 

13 2026 88,777 - - - - - - 

 

14 2027 90,552 - - - - - - 

 

15 2028 92,364 - - - - - - 

 

16 2029 94,211 - - - - - - 

 

17 2030 96,095 - - - - - - 

 

18 2031 98,017 - - - - - - 

 

19 2032 99,977 - - - - - - 

 

20 2033 101,977 - - - - - - 

 

Present Worth - 855,250 - - - - - 

 

(% of PW) 9.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Jim Bridger Unit 1 ROFA

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 105,000 - - - - 2,528,012 2,528,012 

 

2 2015 107,100 - - - - 2,578,573 2,578,573 

 

3 2016 109,242 - - - - 2,630,144 2,630,144 

 

4 2017 111,427 - - - - 2,682,747 2,682,747 

 

5 2018 113,655 - - - - 2,736,402 2,736,402 

 

6 2019 115,928 - - - - 2,791,130 2,791,130 

 

7 2020 118,247 - - - - 2,846,953 2,846,953 

 

8 2021 120,612 - - - - 2,903,892 2,903,892 

 

9 2022 123,024 - - - - 2,961,970 2,961,970 

 

10 2023 125,485 - - - - 3,021,209 3,021,209 

 

11 2024 127,994 - - - - 3,081,633 3,081,633 

 

12 2025 130,554 - - - - 3,143,266 3,143,266 

 

13 2026 133,165 - - - - 3,206,131 3,206,131 

 

14 2027 135,829 - - - - 3,270,254 3,270,254 

 

15 2028 138,545 - - - - 3,335,659 3,335,659 

 

16 2029 141,316 - - - - 3,402,372 3,402,372 

 

17 2030 144,142 - - - - 3,470,419 3,470,419 

 

18 2031 147,025 - - - - 3,539,828 3,539,828 

 

19 2032 149,966 - - - - 3,610,624 3,610,624 

 

20 2033 152,965 - - - - 3,682,837 3,682,837 

 

Present Worth - 1,282,875 - - - 30,886,886 30,886,886 2

 

(% of PW) 2.4% 0.0% 0.0% 0.0% 0.0% 58.6% 58.6% 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 1 LNB w/OFA & SNCR

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 307,500 - 1,005,811 - - 208,926 1,214,737 

 

2 2015 313,650 - 1,025,927 - - 213,105 1,239,032 

 

3 2016 319,923 - 1,046,446 - - 217,367 1,263,812 

 

4 2017 326,321 - 1,067,375 - - 221,714 1,289,088 

 

5 2018 332,848 - 1,088,722 - - 226,148 1,314,870 

 

6 2019 339,505 - 1,110,496 - - 230,671 1,341,168 

 

7 2020 346,295 - 1,132,706 - - 235,285 1,367,991 

 

8 2021 353,221 - 1,155,361 - - 239,990 1,395,351 

 

9 2022 360,285 - 1,178,468 - - 244,790 1,423,258 

 

10 2023 367,491 - 1,202,037 - - 249,686 1,451,723 

 

11 2024 374,841 - 1,226,078 - - 254,680 1,480,757 

 

12 2025 382,338 - 1,250,599 - - 259,773 1,510,373 

 

13 2026 389,984 - 1,275,611 - - 264,969 1,540,580 

 

14 2027 397,784 - 1,301,124 - - 270,268 1,571,392 

 

15 2028 405,740 - 1,327,146 - - 275,673 1,602,819 

 

16 2029 413,855 - 1,353,689 - - 281,187 1,634,876 

 

17 2030 422,132 - 1,380,763 - - 286,811 1,667,573 

 

18 2031 430,574 - 1,408,378 - - 292,547 1,700,925 

 

19 2032 439,186 - 1,436,546 - - 298,398 1,734,943 

 

20 2033 447,969 - 1,465,276 - - 304,366 1,769,642 

 

Present Worth - 3,756,990 12,288,849 - - 2,552,627 14,841,477 2

 

(% of PW) 9.2% 0.0% 30.2% 0.0% 0.0% 6.3% 36.4% 

Jim Bridger Unit 1 LNB w/OFA & SCR

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 475,000 - 912,848 594,000 - 1,291,005 2,797,853 1

 

2 2015 484,500 - 931,105 605,880 - 1,316,825 2,853,810 1

 

3 2016 494,190 - 949,727 617,998 - 1,343,162 2,910,886 1

 

4 2017 504,074 - 968,722 630,358 - 1,370,025 2,969,104 1

 

5 2018 514,155 - 988,096 642,965 - 1,397,425 3,028,486 1

 

6 2019 524,438 - 1,007,858 655,824 - 1,425,374 3,089,056 1

 

7 2020 534,927 - 1,028,015 668,940 - 1,453,881 3,150,837 1

 

8 2021 545,626 - 1,048,575 682,319 - 1,482,959 3,213,854 1

 

9 2022 556,538 - 1,069,547 695,966 - 1,512,618 3,278,131 1

 

10 2023 567,669 - 1,090,938 709,885 - 1,542,870 3,343,693 1

 

11 2024 579,022 - 1,112,757 724,083 - 1,573,728 3,410,567 1

 

12 2025 590,603 - 1,135,012 738,564 - 1,605,202 3,478,779 1

 

13 2026 602,415 - 1,157,712 753,336 - 1,637,306 3,548,354 1

 

14 2027 614,463 - 1,180,866 768,402 - 1,670,053 3,619,321 1

 

15 2028 626,752 - 1,204,484 783,770 - 1,703,454 3,691,708 1

 

16 2029 639,287 - 1,228,573 799,446 - 1,737,523 3,765,542 1

 

17 2030 652,073 - 1,253,145 815,435 - 1,772,273 3,840,853 1

 

18 2031 665,115 - 1,278,208 831,743 - 1,807,719 3,917,670 1

 

19 2032 678,417 - 1,303,772 848,378 - 1,843,873 3,996,023 1

 

20 2033 691,985 - 1,329,847 865,346 - 1,880,751 4,075,944 1

 

Present Worth - 5,803,480 11,153,043 7,257,405 - 15,773,310 34,183,758 12

 

(% of PW) 3.4% 0.0% 6.6% 4.3% 0.0% 9.3% 20.2% 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 1 Upgraded Wet FGD

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 42,583 30,503 533,206 - 442,958 208,926 1,215,593 

 

2 2015 43,435 31,113 543,870 - 451,818 213,105 1,239,905 

 

3 2016 44,303 31,735 554,747 - 460,854 217,367 1,264,703 

 

4 2017 45,189 32,370 565,842 - 470,071 221,714 1,289,997 

 

5 2018 46,093 33,017 577,159 - 479,472 226,148 1,315,797 

 

6 2019 47,015 33,678 588,702 - 489,062 230,671 1,342,113 

 

7 2020 47,955 34,351 600,476 - 498,843 235,285 1,368,955 

 

8 2021 48,914 35,038 612,486 - 508,820 239,990 1,396,334 

 

9 2022 49,893 35,739 624,735 - 518,996 244,790 1,424,261 

 

10 2023 50,890 36,454 637,230 - 529,376 249,686 1,452,746 

 

11 2024 51,908 37,183 649,975 - 539,964 254,680 1,481,801 

 

12 2025 52,946 37,926 662,974 - 550,763 259,773 1,511,437 

 

13 2026 54,005 38,685 676,234 - 561,778 264,969 1,541,666 

 

14 2027 55,085 39,459 689,758 - 573,014 270,268 1,572,499 

 

15 2028 56,187 40,248 703,554 - 584,474 275,673 1,603,949 

 

16 2029 57,311 41,053 717,625 - 596,164 281,187 1,636,028 

 

17 2030 58,457 41,874 731,977 - 608,087 286,811 1,668,749 

 

18 2031 59,626 42,711 746,617 - 620,249 292,547 1,702,123 

 

19 2032 60,819 43,566 761,549 - 632,654 298,398 1,736,166 

 

20 2033 62,035 44,437 776,780 - 645,307 304,366 1,770,889 

 

Present Worth 372,679 520,271 6,514,628 - 5,412,000 2,552,627 14,851,935 1

 

(% of PW) 1.8% 1.3% 23.0% 0.0% 19.1% 9.0% 52.3% 

Jim Bridger Unit 1 Flue Gas Conditioning

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 10,000 - 145,854 - - 19,710 165,564 

 

2 2015 10,200 - 148,771 - - 20,104 168,875 

 

3 2016 10,404 - 151,747 - - 20,506 172,253 

 

4 2017 10,612 - 154,781 - - 20,916 175,698 

 

5 2018 10,824 - 157,877 - - 21,335 179,212 

 

6 2019 11,041 - 161,035 - - 21,761 182,796 

 

7 2020 11,262 - 164,255 - - 22,197 186,452 

 

8 2021 11,487 - 167,540 - - 22,641 190,181 

 

9 2022 11,717 - 170,891 - - 23,093 193,985 

 

10 2023 11,951 - 174,309 - - 23,555 197,864 

 

11 2024 12,190 - 177,795 - - 24,026 201,822 

 

12 2025 12,434 - 181,351 - - 24,507 205,858 

 

13 2026 12,682 - 184,978 - - 24,997 209,975 

 

14 2027 12,936 - 188,678 - - 25,497 214,175 

 

15 2028 13,195 - 192,451 - - 26,007 218,458 

 

16 2029 13,459 - 196,300 - - 26,527 222,827 

 

17 2030 13,728 - 200,226 - - 27,058 227,284 

 

18 2031 14,002 - 204,231 - - 27,599 231,830 

 

19 2032 14,282 - 208,315 - - 28,151 236,466 

 

20 2033 14,568 - 212,482 - - 28,714 241,195 

 

Present Worth - 122,179 1,782,023 - - 240,814 2,022,837 

 

(% of PW) 5.7% 0.0% 83.1% 0.0% 0.0% 11.2% 94.3% 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 1 Fabric Filter

Year Date TOTAL FIXED O&M COST Makeup Water Cost Reagent Cost SCR Catalyst / FF Bag Cost Waste Disposal Cost Electric Power Cost TOTAL VARIABLE O&M COST DEBT 

0 20131 2014 127,749 - - 300,040 - 1,335,944 1,635,984 

 

2 2015 130,304 - - 306,041 - 1,362,663 1,668,703 

 

3 2016 132,910 - - 312,162 - 1,389,916 1,702,078 

 

4 2017 135,568 - - 318,405 - 1,417,714 1,736,119 

 

5 2018 138,279 - - 324,773 - 1,446,069 1,770,841 

 

6 2019 141,045 - - 331,268 - 1,474,990 1,806,258 

 

7 2020 143,866 - - 337,894 - 1,504,490 1,842,383 

 

8 2021 146,743 - - 344,652 - 1,534,579 1,879,231 

 

9 2022 149,678 - - 351,545 - 1,565,271 1,916,816 

 

10 2023 152,671 - - 358,576 - 1,596,577 1,955,152 

 

11 2024 155,725 - - 365,747 - 1,628,508 1,994,255 

 

12 2025 158,839 - - 373,062 - 1,661,078 2,034,140 

 

13 2026 162,016 - - 380,523 - 1,694,300 2,074,823 

 

14 2027 165,256 - - 388,134 - 1,728,186 2,116,319 

 

15 2028 168,562 - - 395,896 - 1,762,749 2,158,646 

 

16 2029 171,933 - - 403,814 - 1,798,004 2,201,819 

 

17 2030 175,371 - - 411,891 - 1,833,965 2,245,855 

 

18 2031 178,879 - - 420,128 - 1,870,644 2,290,772 

 

19 2032 182,456 - - 428,531 - 1,908,057 2,336,588 

 

20 2033 186,106 - - 437,102 - 1,946,218 2,383,319 

 

Present Worth - 1,560,813 - 3,665,845 - 16,322,365 19,988,210 4

 

(% of PW) 2.2% 0.0% 0.0% 5.2% 0.0% 23.3% 28.6% 

EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 
EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 

First Year Cost for Air Pollution Control Options

0

2,000,0004,000,0006,000,0008,000,000

10,000,00012,000,00014,000,00016,000,00018,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Upgraded Wet

FGD

Flue Ga

Condition

Air Pollution Control Option

First Year Cost ($)
EY102007001SLC\App A_PCorp JB1 BART Economic Analysis_01-11-07.xls 

Present Worth Cost for Air Pollution Control Options

0

20,000,00040,000,00060,000,00080,000,000

100,000,000120,000,000140,000,000160,000,000180,000,000

LNB w/OFA ROFA LNB w/OFA &

SNCR

LNB w/OFA &

SCR

Upgraded Wet

FGD

Flue Ga

Condition

Air Pollution Control Options

Present Worth Cost Over Year Plant Life ($)
APPENDIX B 

2006 Wyoming BART Protocol