Final Report 

BART Analysis for 

Jim Bridger Unit 3 

Prepared For: 

PacifiCorp 

1407 West North Temple 

Salt Lake City, Utah 84116 

December 2007 

Prepared By: 

215 South State Street, Suite 1000 

Salt Lake City, Utah 84111 
Final Report 

BART Analysis for 

Jim Bridger Unit 3 

Submitted to 

PacifiCorp 

December 2007 
Executive Summary 

Background 

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

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

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

Retrofit Technology 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 emission limits apply to 

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

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

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

for this analysis. 

In completing the BART analysis, technology 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 (LNB) with over-fire air (OFA) 

− Rotating opposed fire air (ROFA) 

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

− LNB with selective catalytic reduction (SCR) system 

• 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 lb per 

MMBtu 

− New dry FGD system 

• PM10 emission controls: 

− Sulfur trioxide (SO3) injection flue gas conditioning system on existing electrostatic 

precipitator (ESP) 

− Polishing fabric filter 

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BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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 3 will be the Bridger Underground Mine. 

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

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

characteristics to bituminous coal in many of the parameters influencing NOx formation. 

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-2
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

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

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

qualities on NOx formation and achievable emission rates. 

Recommendations 

CH2M HILL recommends these BART selections, which include installing low NOx burners 

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

precipitator 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 low-NOx burners with over-fire air (LNB with OFA) as BART for 

Jim Bridger 3, 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. NOx 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 3, 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 3, 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. 

BART Modeling Analysis 

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

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

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-3
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

• Bridger WA 

• Fitzpatrick WA 

• Mt. Zirkel WA 

Because Jim Bridger 3 will simultaneously control NOx, SO2, and PM10 emissions, four 

post-control 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 CH2M HILL 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. 

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

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

Workshop Manual.1

Least-cost Envelope Analysis 

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

for selecting the most reasonable, cost-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 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 deltadeciview (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 

 

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

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BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC ES-5

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

and flue gas conditioning for 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 half a dV, and the projected costs are excessive. Therefore, 

Scenario 1 represents BART for Jim Bridger 3. 

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 only minimal 

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

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

entire fleet of coal-fired power plants. 
Contents 

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

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

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

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

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

3.2.1 BART 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............................................................... 4-4 

4.2.3 Validation of CALMET Wind Field ....................................... 4-6 

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

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

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

4.3.3 Emission Rates........................................................................ 4-7 

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

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

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

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

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

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

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

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

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

5.1.2 Analysis Results...................................................................... 5-9 

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

5.2.1 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\DAVEJOHNSTON3_FINALSUBMITTAL\BART_JB3_OCT2007_FINAL.DOC iii
CONTENTS (CONTINUED) 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC iv

Tables 

2-1 Unit Operation and Study Assumptions 

2-2 Coal Sources and Characteristics 

3-1 Coal Characteristics Comparison 

3-2 NOx Control Technology Projected Emission Rates 

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 1 Wilderness Area 

5-2 Control Scenario Results for the Fitzpatrick Class 1 Wilderness Area 

5-3 Control Scenario Results for the Mt. Zirkel Class 1 Wilderness Area 

5-4 Bridger Class I Wilderness Area Incremental Analysis Data 

5-5 Fitzpatrick Class I Wilderness Area Incremental Analysis Data 

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

Figures 

3-1 Illustration of the Effect of 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 Class I 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 Degree Fahrenheit 

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 

COHPAC Compact Hybrid Particulate Collector 

dV Deciview 

ΔdV Delta Deciview, Change in Deciview 

DEQ Department of Environmental Quality 

ESP Electrostatic Precipitator 

EPA United States Environmental Protection Agency 

FGC Flue Gas Conditioning 

FGD Flue Gas Desulfurization 

kW Kilowatt 

kW-Hr Kilowatt-hour 

LNB Low-NOx Burner 

lb Pound 

MMBtu Million British Thermal Units 

MM5 Mesoscale Meteorological Model, Version 5 

MW Megawatts 

NOx Nitrogen Oxides 

OFA Over Fire Air 

PM Particulate Matter 

PM2.5 Particulate Matter less than 2.5 Micrometers in Aerodynamic Diameter 

PM10 Particulate Matter less than 10 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 

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ACRONYMS AND ABBREVIATIONS (CONTINUED) 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC vi

SNCR Selective Non-catalytic Reduction 

SO2 Sulfur Dioxide 

SO3 Sulfur Trioxide 

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 United 

States 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 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 (DEQ) 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 Wyoming DEQ to submit the 

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

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

analysis, and a proposal and 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 3 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. References are provided in 

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

BART Protocol. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 1-1
2.0 Present Unit Operation 

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

2,120 megawatts (MW). Jim Bridger 3 is a nominal 530 net MW unit located approximately 

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

pulverized coal boiler with low NOx burners manufactured by Combustion Engineering. The 

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

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

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

was installed in 2003. 

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

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

extension costs needed to allow the unit and these control devices at Jim Bridger 3 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 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 3 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 use 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 3, 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 3.2.1, the data from all the coal 

sources were used. 

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BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 2-2

TABLE 2-1 

Unit Operation and Study Assumptions 

Jim Bridger 3 

General Plant Data 

Site Elevation feet above MSL 6669 

Stack Height (feet) 500 

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

Stack Exit Temperature (degrees Fahrenheit) 140 

Stack Exit Velocity (feet per second) 84.04 

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

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

Longitude (degree: minute: second) 108:47:12.82 west 

Annual Unit Capacity Factor (percentage) 90 

Net Unit Output (megawatts) 530 

Net Unit Heat Rate (British thermal unit [Btu]/kilowatthour)(100% load) 10,400 (as measured by fuel throughput) 

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

hour)(100% load) 

6,000 (as measured by continuous 

emission monitoring) 

Type of Boiler Tangentially fired 

Boiler Fuel Coal 

Coal Sources 

Bridger Mine, Black Butte Mine, Leucite 

Hills Mine 

Coal Heating Value (Btu/ per pound [lb]) (a) 9,660 

Coal Sulfur Content (percentage by weight [wt. %]) (a) 0.58 

Coal Ash Content (wt. %)(a) 10.3 

Coal Moisture Content (wt. %)(a) 19.3 

Coal Nitrogen Content (wt. %)(a) 0.98 

Current Nitrogen Oxide (NOx) Controls Low NOx burners 

NOx Emission Rate (lb per MMBtu) 0.45 

Current Sulfur Dioxide (SO2) Controls Sodium based wet scrubber 

SO2 Emission Rate (lb per MMBtu) 0.267 

Current PM10 Controls Electrostatic Precipitator 

PM10(c) Emission Rate (lb per MMBtu) (b) 0.057 

NOTES: 

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

(b) Based on maximum historic emission rate from 1999-2001, prior to installation of the SO3 injection 

system. (c) PM10 refers to particulate matter less than 10 micrometers in aerodynamic diameter 
BAR

TABLE 2-2 Coal Sources and Characteristics Jim Bridger 3 

Ultimate Analysi

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 sepaMaximum 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_JB3_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 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, and 

• 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 

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BART ANALYSIS FOR JIM BRIDGER UNIT 3 

• Step 5 – Evaluate Visibility Impacts 

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

of BART 

In order to minimize costs in the BART 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. 

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

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

the combustion air. 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 lowNOx burners (LNBs), sub-bituminous coals create a longer time for the kinetics to promote 

more stable molecular nitrogen, and hence result in lower NOx emissions. 

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, 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 subJMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-2
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

due to its dominant market 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 3 as sub-bituminous rather than 

bituminous – that is, 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°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 by Figure 3-1, the increased porosity provides more particle 

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

property assists in making sub-bituminous coals more amenable to controlling 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 for the Bridger blends of coals. 

FIGURE 3-1 

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

Jim Bridger 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-3
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

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

bituminous coal. 

TABLE 3-1 

Coal Characteristics Comparison 

Jim Bridger 3 

Parameter 

Typical 

Powder 

River 

Basin 

Bridger 

Mine 

Black 

Butte 

Leucite 

Hills Twentymile 

Nitrogen (percentage dry) 1.10 1.26 1.47 1.48 1.85 

Oxygen (percentage dry) 16.2 13.2 13.4 13.2 7.19 

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

volatility B 

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

sub-bituminous, they all 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 low NOx

burners 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 3, and indicates the average NOx

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

same blend of coals as Jim Bridger 3, 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 3 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 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-4
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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 of these factors are consistent with the 

observed sustainable rate of 0.24 lb per MMBtu. 

FIGURE 3-2 

Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Jim Bridger 3 

PRB Subbituminous

Bridger Blend

Jim Bridger 2

Twentymile Bituminous 

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00

Typical Nitrogen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-5
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

FIGURE 3-3 

Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART NOx Limits 

Jim Bridger 3 

PRB Subbituminous

Twentymile Bituminous

Bridger Blend

Jim Bridger 2

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00

Typical Oxygen Content (%-Dry Basis)

NOx Limit (lb/MMBtu)

Subbituminous Presumptive Limit - 0.15lb/MMBtu

Bituminous Presumptive Limit - 0.28 lb/MMBtu

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 equipment changes. 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 3. In addition to burning 

coal from Black Butte and Leucite Hills, Jim Bridger 3 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 and between 

other performance issues can result. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-6
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

lower at this elevation, 11.5 pounds per square 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 reduce NOx emissions using LNB and OFA, original boiler design 

restrictions again limit the modifications that can be made while still achieving satisfactory 

combustion performance. 

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

burners. Fineness is influenced by the Hardgrove Grindability Index of the coal. Finer coal 

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

exposed to air. NOx 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 3, 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 3, the more applicable presumptive BART 

limit for NOx emissions is 0.28 lb per MMBtu. The BART analysis for NOx emissions from 

Jim Bridger 3 is further described below. 

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 3, 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. NOx 

emissions at Jim Bridger 3 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 3, 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 NOx per MMBtu. 

Jim Bridger 3 has an uncontrolled NOx emission rate of 0.45 lb per MMBtu. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-7
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

For this BART analysis, information 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 & 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. NOx reductions of up to 40 to 60 percent have been 

achieved, although 15 to 30 percent is more realistic for most applications. SNCR 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. 

TABLE 3-2 

NOx Control Technology Projected Emission Rates 

Jim Bridger 3 

Technology Projected Emission Rate (pounds per 

million British thermal units) 

Presumptive Best Available 

Retrofit Technology (BART) Limit 

0.28 

Low-NOx burners (LNBs) with 

over-fire air (OFA) 

0.24 

Rotating Opposed Fire Air 0.22 

LNB with OFA and Selective 

Non-catalytic Reduction (SNCR) 

0.20 

LNB with OFA and Selective 

Catalytic Reduction (SCR) 

0.07 

Step 3: Evaluate Control 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 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-8
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

the conversion of fuel nitrogen to nitrogen 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 3, 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 a new LNB and OFA retrofit at Jim Bridger 3 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. 

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

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

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

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

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

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

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

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

Mobotec proposes to achieve a 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, which is primarily based on ROFA equipment, the operation of existing LNB and 

OFA ports would 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 would determine the quantity and location of new ROFA ports. The 

Mobotec proposal includes bent tube assemblies for OFA port installation. 

Mobotec would not provide installation services, because they believe that the Owner can more 

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

construction supervisor during installation and startup. 

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

NOx reductions on smaller units—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. NOx 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 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-9
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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, capable of 

achieving a projected NOx emission rate of 0.24 lb per MMBtu. At 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. 

Selective Catalytic Reduction. While working on the same chemical principle as SNCR, SCR 

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

where it reduces 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 3. In a full-scale SCR, the flue ducts are 

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

located in 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 3. 

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

SNCR, it is generally more cost effective to reduce 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 3. 

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

operation including excess air, boiler slagging, burner equipment condition, coal mill fineness, 

and so forth. 

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

follows: 

• Establish expected NOx emissions value from vendor. 

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-10
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

• Review and evaluate unit physical and 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 would require installation and operation of two 4,000 to 

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

approximately 520 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 increase. Total additional power requirements for SCR installation at Jim Bridger 3 are 

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

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

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

prior levels for the ROFA system. 

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

due to ammonia levels, and could potentially 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 presented in 

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-11
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-12

TABLE 3-3 

NOx Control Cost Comparison 

Jim Bridger 3 

Factor 

Low-NOx

Burners 

(LNBs) with 

Over-fire Air 

(OFA) 

Mobotec 

Rotating 

Opposed Fire 

Air (ROFA) 

LNB with 

OFA and 

Selective 

NonCatalytic 

Reduction 

(SNCR) 

LNB with OFA 

and Selective 

Catalytic 

Reduction 

(SCR) 

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

Total First Year Fixed and Variable 

Operation and Maintenance Costs 

$0.1 million $2.6 million $1.5 million $3.3 million 

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

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

Annual Power Usage 

(million MW-hours per year) 

0 50.6 4.1 25.4 

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 

Nitrogen Oxide (NOx) Design Control 

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

Incremental Control Cost 

(dollars per ton [$/ton] of NOx Removed) $181/ton $7,797/ton $2,863/ton $3,896/ton 

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

for Jim Bridger 3 based on its significant reduction in NOx emissions, reasonable control cost, 

and no additional power requirements or environmental impacts. Low-NOx burners with OFA 

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

does meet an emission rate that falls between the presumptive limit of 0.28 lb per MMBtu for 

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

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

deemed appropriate as BART for NOx emissions from the coals combusted at Jim Bridger 3. 

Step 5: Evaluate Visibility Impacts 

Please see Section 4, BART Modeling Analysis. 
B

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

Jim Bridger 3 

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_JB3_OCT2007_FINAL.DOC 
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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 3 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 3. 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 3 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. 

TABLE 3-4 

SO2 Control Technology Emission Rates 

Jim Bridger 3 

Technology 

Projected Sulfur Dioxide (SO2) 

Emission Rate (pound per million 

British thermal units) 

Presumptive Best Available Retrofit 

Technology Limit 

0.15 

Upgrade Existing Wet Sodium System 0.10 

Optimize Existing Wet Sodium System 0.20 

New Dry Flue Gas Desulfurization 

System 

0.21 

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

scrubber vessels with a soda ash solution. The 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. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-14
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

The wet sodium FGD system at Jim Bridger 3 currently 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 would achieve an SO2 outlet emission rate of 0.20 lb per MMBtu 

(83.3 percent SO2 removal) by partially closing the bypass damper to reduce routine bypass 

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

monitor, and modifying the system to minimize scaling problems. 

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

MMBtu (91.7 percent SO2 removal) by closing the bypass damper to eliminate routine bypass 

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

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

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

achieve 95 percent 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 SO2

per MMBtu. 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 SO2 per MMBtu for Jim Bridger 3. 

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

absorber vessel with a rapidly rotating 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 3, this dry particulate matter would be captured downstream in the 

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

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 3. 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 SO2 per MMBtu, and is eliminated from further analysis as 

technically infeasible. 

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 3 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 3 would 

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

MMBtu. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-15
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

Step 4: Evaluate Impacts and Document the Results 

This step involves the 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 

520 kW of power. 

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

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

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

provided approximately 20°F of reheat. 

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. 

TABLE 3-5 

SO2 Control Cost Comparison (Incremental to Existing FGD System) 

Jim Bridger Unit 3 

Factor Upgraded Wet Flue Gas Desulfurization (FGD) 

Total Installed Capital Costs $13.0 million 

Total First Year Fixed and Variable Operation and 

Maintenance Costs 

$1.3 million 

Total First Year Annualized Cost $2.5 million 

Additional Power Consumption (megawatts [MW]) 0.5 

Additional Annual Power Usage (1000 MW-hours 

per year) 

4.1 

Incremental Sulfur Dioxide (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 

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

system as BART for Jim Bridger 3 based on its significant reduction in 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_JB3_OCT2007_FINAL.DOC 3-16
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

3.2.3 BART PM10 Analysis 

Jim Bridger 3 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 3 has 

controlled PM10 emissions to levels below 0.057 lb per MMBtu. 

The BART analysis for PM10 emissions at Jim Bridger 3 is described in this section. 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. 

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

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

installation of a full fabric filter was not considered in the analysis. 

Step 2: Eliminate Technically Infeasible Options 

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

sub-bituminous coal, the ash is not collected 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. 

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

at Jim Bridger 3. 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). 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

The existing ESP at Jim Bridger 3 is achieving a controlled PM emission rate of 0.057 lb per 

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

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

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-17
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

TABLE 3-6 

PM10 Control Technology Emission Rates 

Jim Bridger 3 

Control Technology 

Short-term Projected PM10(a)

Emission Rate (pound 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. 

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

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

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

conditioning. 

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

COHPAC polishing fabric filter or flue gas conditioning system. 

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

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

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

contained in Appendix A. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-18
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 3-19

TABLE 3-7 

PM10 Control Cost Comparison (Incremental to Existing ESP) 

Jim Bridger 3 

Factor 

Flue Gas 

Conditioning Polishing Fabric Filter 

Total Installed Capital Costs $0 $48.4 million 

Total First Year Fixed and Variable Operations and 

Maintenance Costs 

$0.2 million $1.7 million 

Total First Year Annualized Cost $0.2 million $ 6.3 million 

Additional Power Consumption (MW) 0.05 3.43 

Annual Power Usage (million kilowatt-hours per 

year) 

0.4 26.3 

Incremental Particulate Matter (PM) Design Control 

Efficiency 

47.4% 73.7% 

Incremental Tons PM Removed per Year 639 993 

First Year Average Control Cost 

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

Incremental Control Cost 

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

Preliminary BART Selection. CH2M HILL recommends selection of flue gas conditioning 

upstream of the existing ESP as BART for Jim Bridger 3 based on the significant reduction in 

PM emissions, reasonable control costs, and advantages of minimal 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 3 

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 Cost

JMS EY102007001SLC\BART_JB3_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 3 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 3 facility. The 

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

• Bridger WA 

• Fitzpatrick WA 

• Mt. Zirkel WA 

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

puff dispersion model (CALPUFF) with 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 3 facility and allow for a 50-kilometer buffer around 

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

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

instructed otherwise by the Wyoming 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 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_JB3_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 3 

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 3 

CALMET Input Parameter Value 

CALMET Input Group 2 

Map projection (PMAP) Lambert Conformal 

Grid spacing (DGRIDKM) 4 

Number vertical layers (NZ) 10 

Top of lowest layer (m) 20 

Top of highest layer (m) 3500 

CALMET Input Group 4 

Observation mode (NOOBS) 0 

CALMET Input Group 5 

Prog. Wind data (IPROG) 14 

 (RMAX1) 30 

 (RMAX2) 50 

Terrain influence (TERRAD) 15 

 (R1) 5 

 (R2) 25 

CALMET Input Group 6 

Max mixing ht (ZIMAX) 3500 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-3
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-4

4.2.2 CALMET Input Data 

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

2003. WDEQ-AQD provided 12-km 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 

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 1 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. 
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 3 

4.2.3 Validation of CALMET Wind Field 

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

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

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

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

Atmospheric Administration, 2006). 

4.3 CALPUFF Modeling Approach 

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

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

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

over the modeling domain described earlier. The CALPUFF model 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 3. 

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 3. 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. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-6
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

4.3.3 Emission Rates 

Pre-control emission rates for Jim Bridger 3 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) 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 & 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. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-7
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-8

Table 4-2 presents the stack parameters and emission rates used for the Jim Bridger 3 

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. 

4.3.5 Modeling Process 

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

sequence: 

• Model pre-control (baseline) emissions 

• Model preferred post-control scenario (if applicable) 

• Determine degree of visibility improvement 

• Model other control scenarios 

• Determine degree of visibility improvement 

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

4.3.6 Receptor Grids 

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

along the boundary and in the interior of each 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. 
TABLE 4-2 

BART Model Input Data Jim Bridger 3 

Baseline Post-control Scenario 1 Po

Model Input Data 

Current Operations with wet Flue 

Gas Desulfurization (FGD) and 

Electrostatic Precipitator (ESP) 

LNB with Over Fire Air (OFA), 

Upgrade Wet FGD & Flue Gas 

Conditioning (FGC) for 

Enhanced ESP Performance 

LNB w

FG

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) 342 180 

Coarse Particulates (PM2.5<diameter<PM10) Stack Emissions (lb/hr) (a) 147 77.4 

Fine Particulates (diameter<PM2.5) Stack Emissions (lb/hr) (a) 195 103 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) 25.6 24.8 NOTES: 

(a) Based on AP-42, Table 1.1-6, 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 particu(b) Based on AP-42, Table 1.1-6, fine particulates are counted as a percentage of PM10. This equates to 57 percent ESP and 43 percent baghouse. PM10 and PM2.5 refer to particulat

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) 

Scenarios 2, 3, and 4 were not remodeled at the lower, correct velocity of 81.24 fps due to lack of time and the fact that the conclusions to select Scenario 1 would not have changed
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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 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 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 relative humidity 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 delta-deciview (ΔdV) 

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 days. Species 

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

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

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule 

(EPA, 2003). A separate scaling factor was 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). The Wyoming BART Air Modeling Protocol (see Appendix B) did provide 

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

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

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-10
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 4-11

TABLE 4-3 

Average Natural Levels of Aerosol Components 

Jim Bridger 3 

Aerosol Component 

Average Natural Concentration 

(micrograms per cubic meter) 

for Mt. Zirkel Class I 

Wilderness Area 

Average Natural Concentration 

(micrograms per cubic meter) 

for Fitzpatrick and Bridger Class I 

Wilderness Areas 

Ammonium Sulfate 0.046 0.045 

Ammonium Nitrate 0.038 0.038 

Organic Carbon 0.179 0.178 

Elemental Carbon 0.008 0.008 

Soil 0.190 0.189 

Coarse Mass 1.141 1.136 

NOTES: 

Source: Table 6 of the Wyoming BART Air Modeling Protocol 

4.5 Presentation of Modeling Results 

This section presents the results of the CALPUFF visibility improvement modeling analysis 

for Jim Bridger 3. 

4.5.1 Visibility Changes for Baseline vs. Preferred Scenario 

CH2M HILL modeled Jim Bridger 3 for the baseline conditions and post-control scenarios. 

The post-control scenarios included emission rates for NOx, SO2, and PM10 that would be 

achieved if BART technology were installed on Jim Bridger 3. 

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 3

Modeling Results 

Scenario 

Total First Year 

Annualized Cost 

Class I 

Wilderness Area 

Highest Change 

in Deciview 

(ΔdV) 

98th Percentile 

(ΔdV) 

Number (No.) 

of Days Above

0.5 dV 

2001 

Bridger 2.506 0.741 15 

Fitzpatrick 2.178 0.418 7 

Baseline: current operation with wet Flue Gas Desulfurization (FGD), Electrostatic Precipitator (ESP) 

Mt. Zirkel 1.945 1.226 27 

$3,387,923 Bridger 1.366 0.386 7 

$3,387,923 Fitzpatrick 1.386 0.223 3 

Scenario 1: Low-NOx Burners (LNBs) with Over Fire Air (OFA), 

upgrade wet FGD, Flue Gas Conditioning (FGC) for enhanced ESP performance $3,387,923 Mt. Zirkel 1.168 0.733 16 

$9,726,040 Bridger 1.393 0.376 6 

$9,726,040 Fitzpatrick 1.182 0.214 3 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter 

$9,726,040 Mt. Zirkel 1.102 0.677 15 

$18,074,111 Bridger 0.875 0.279 3 

$18,074,111 Fitzpatrick 0.681 0.128 1 

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

$18,074,111 Mt. Zirkel 0.758 0.451 5 

$24,412,229 Bridger 0.837 0.268 3 

$24,412,229 Fitzpatrick 0.66 0.126 1 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter 

$24,412,229 Mt. Zirkel 0.731 0.437 2 

2002 

Bridger 4.103 1.447 27 

Baseline: current operation with wet FGD, ESP Fitzpatrick 1.906 0.713 11 

Mt. Zirkel 2.801 1.498 34 

$3,387,923 Bridger 2.447 0.854 14 

$3,387,923 Fitzpatrick 1.074 0.377 4 

Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance 

$3,387,923 Mt. Zirkel 1.541 0.815 13 

$9,726,040 Bridger 2.318 0.782 13 $9,726,040 Fitzpatrick 1.005 0.349 6 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter 

$9,726,040 Mt. Zirkel 1.484 0.778 13 

$18,074,111 Bridger 1.316 0.509 9 

$18,074,111 Fitzpatrick 0.551 0.226 1 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance 

$18,074,111 Mt. Zirkel 0.882 0.473 4 

$24,412,229 Bridger 1.290 0.498 7 

$24,412,229 Fitzpatrick 0.541 0.222 1 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter 

$24,412,229 Mt. Zirkel 0.860 0.464 4 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 
JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 

TABLE 4-4 Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I Areas Jim Bridger 3

 Modeling Results 

Scenario 

Total First Year 

Annualized Cost 

Class I 

Wilderness Area 

Highest Change 

in Deciview 

(ΔdV) 

98th Percentile 

(ΔdV) 

Number (No.) 

of Days Above

0.5 dV 

2003 

Bridger 1.703 0.759 16 

Baseline: current operation with wet FGD, ESP Fitzpatrick 1.943 0.378 7 

Mt. Zirkel 1.952 1.228 35 

$3,387,923 Bridger 0.983 0.414 5 

$3,387,923 Fitzpatrick 1.105 0.192 2 

Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance 

$3,387,923 Mt. Zirkel 1.041 0.734 16 

$9,726,040 Bridger 0.983 0.410 5 $9,726,040 Fitzpatrick 1.088 0.188 2 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter 

$9,726,040 Mt. Zirkel 1.053 0.686 15 

$18,074,111 Bridger 0.852 0.258 3 

$18,074,111 Fitzpatrick 0.682 0.118 2 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance 

$18,074,111 Mt. Zirkel 0.666 0.432 5 

$24,412,229 Bridger 0.808 0.248 3 

$24,412,229 Fitzpatrick 0.663 0.115 2 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter 

$24,412,229 Mt. Zirkel 0.633 0.42 5 

3-year Averages 

Bridger 0.982 19.3 

Baseline: Current Operation with wet FGD, ESP Fitzpatrick 0.503 8.3 

Mt. Zirkel 1.317 32.0 

$3,387,923 Bridger 0.551 8.7 

$3,387,923 Fitzpatrick 0.264 3.0 

Scenario 1: LNB with OFA, upgrade wet FGD, FGC for enhanced ESP performance 

$3,387,923 Mt. Zirkel 0.761 15.0 

$9,726,040 Bridger 0.523 8.0 $9,726,040 Fitzpatrick 0.250 3.7 

Scenario 2: LNB with OFA, upgrade wet FGD, polishing fabric filter 

$9,726,040 Mt. Zirkel 0.714 14.3 

$18,074,111 Bridger 0.349 5.0 

$18,074,111 Fitzpatrick 0.157 1.3 

Scenario 3: LNB with OFA and SCR, upgrade wet FGD, FGC for enhanced ESP performance 

$18,074,111 Mt. Zirkel 0.452 4.7 $24,412,229 Bridger 0.338 4.3 

$24,412,229 Fitzpatrick 0.154 1.3 

Scenario 4: LNB with OFA and SCR, upgrade wet FGD, polishing fabric filter 

$24,412,229 Mt. Zirkel 0.440 3.7 

NOTES: Sample Calculations: Cost per dV Reduction for Scenario 1 for 2001: = $3,387,923 / (0.8968 - 0.492) = $8,845,751 

Sample Calculations: Cost per Reduction in No. of Days Exceeding 0.5 dV for 2001: = $3,387,923 / (20 -7) = $260,609 
5.0 Preliminary Assessment and 

Recommendations 

As a result of the completed technical and economic evaluations, and consideration of the 

modeling analysis for Jim Bridger 3, 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).The purpose of this analysis is to use 

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

BART control technology. 

5.1 Least-cost Envelope Analysis 

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

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

0.5 dV for each of the three Class I areas. A comparison of the incremental results between 

selected scenarios is provided in Tables 5-4 through 5-6. Figures 5-1 to 5-6 show the total 

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

98th percentile ΔdV reduction, for the three Class I areas. 

5.1.1 Analysis Methodology 

On page B-41 of the New Source Review Workshop Manual, the EPA states that: 

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

reduction differences between 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 cost 

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

scenarios, and is summarized in Tables 5-4 through 5-6 for each of the three wilderness 

areas. Then the most reasonable smooth curve of least-cost control option scenarios is plotted 

for each analysis. Figures 5-1 through 5-6 present the two analyses (cost per dV reduction 

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

impacted by the operation of Jim Bridger 3. 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-1
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

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

number of days above 0.5 dV. EPA states that “in calculating 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 inferior controls, 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 3 

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), 

Electrostatic 

Precipitator (ESP) 

0.00 0.0 0.0 0.0 0.0 

1 Low-NOx Burners 

(LNBs) with Over Fire 

Air (OFA), upgraded 

wet FGD system, flue 

Gas Conditioning 

(FGC) for enhanced 

ESP performance 

0.43 10.7 3.4 7.9 0.3 

2 LNB with OFA, 

upgraded wet FGD 

system, and new 

polishing fabric filter 

0.46 11.3 9.7 21.2 0.9 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), 

upgraded wet FGD 

system, FGC for 

enhanced ESP 

performance 

0.63 14.3 18.1 28.5 1.3 

4 LNB with OFA and 

SCR, upgraded wet 

FGD system, new 

polishing fabric filter 

0.64 15.0 24.4 37.9 1.6 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-2
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

TABLE 5-2 

Control Scenario Results for the Fitzpatrick Class I Wilderness Area 

Jim Bridger 3 

Scenario Controls 

98th

Percentile 

dV 

Reduction 

Average 

Number of 

Days 

Above 

0.5 dV 

(Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per dV 

Reduction 

(Million$/dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Above 0.5 dV 

(Million$/Day 

Reduced) 

Base Current Operation with 

Wet Flue Gas 

Desulfurization (FGD), 

Electrostatic 

Precipitator (ESP) 

0.00 0.0 0.0 0.0 0.0 

1 Low-NOx Burners 

(LNBs) with Over Fire 

Air (OFA), upgraded 

wet FGD system, flue 

Gas Conditioning 

(FGC) for enhanced 

ESP performance 

0.24 5.3 3.4 14.2 0.6 

2 LNB with OFA, 

upgraded wet FGD 

system, and new 

polishing fabric filter 

0.25 4.7 9.7 38.5 2.1 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR),, 

upgraded wet FGD 

system, FGC for 

enhanced ESP 

performance 

0.35 7.0 18.1 52.3 2.6 

4 LNB with OFA and 

SCR, upgraded wet 

FGD system, new 

polishing fabric filter 

0.35 7.0 24.4 70.0 3.5 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-3
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

TABLE 5-3 

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

Jim Bridger 3 

Scenario Controls 

98th

Percentile 

dV 

Reduction 

Average 

Number of 

Days 

Above 

0.5 dV 

(Days) 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

dV 

Reduction 

(Million$/dV 

Reduced) 

Cost per 

Reduction in No. 

of Days Above 

0.5 dV 

(Million$/Day 

Reduced) 

Base Current Operation with 

Wet Flue Gas 

Desulfurization (FGD), 

Electrostatic 

Precipitator (ESP) 

0.00 0.0 $0.0 $0.0 $0.0 

1 Low-NOx Burners 

(LNBs) with Over Fire 

Air (OFA), upgraded 

wet FGD system, flue 

Gas Conditioning 

(FGC) for enhanced 

ESP performance 

0.56 17.0 $3.4 $6.1 $0.2 

2 LNB with OFA, 

upgraded wet FGD 

system, and new 

polishing fabric filter 

0.60 17.7 $9.7 $16.1 $0.6 

3 LNB with OFA and 

Selective Catalytic 

Reduction (SCR), 

upgraded wet FGD 

system, FGC for 

enhanced ESP 

performance 

0.87 27.3 $18.1 $20.9 $0.7 

4 LNB with OFA and 

SCR, upgraded wet 

FGD system, new 

polishing fabric filter 

0.88 28.3 $24.4 $27.8 $0.9 

TABLE 5-4 

Bridger Class I Wilderness Area Incremental Analysis Data 

Jim Bridger 3 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 Deciview 

(dV) (Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(Million$/Days) 

Incremental 

Cost 

Effectiveness 

(Million$/dV) 

Baseline and Scenario 1 10.7 0.43 $0.32 $7.9 

Scenario 1 and Scenario 2 0.7 0.03 $9.5 $221.1 

Scenario 1 and Scenario 3 3.7 0.20 $4.0 $72.5 

Scenario 1 and Scenario 4 4.3 0.21 $4.9 $98.6 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-4
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

TABLE 5-5 

Fitzpatrick Class I Wilderness Area Incremental Analysis Data 

Jim Bridger 3 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 Deciview 

(dV) (Days)) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(Million$/Days) 

Incremental 

Cost 

Effectiveness 

(Million$/dV) 

Baseline and Scenario 1 5.3 0.24 $0.64 $14.2 

Scenario 1 and Scenario 2 NA 0.01 NA $463.8 

Scenario 1 and Scenario 3 1.7 0.11 $8.8 $137.7 

Scenario 1 and Scenario 4 1.7 0.11 $12.6 $191.7 

TABLE 5-6 

Mt. Zirkel Class I Wilderness Area Incremental Analysis Data 

Jim Bridger 3 

Options Compared 

Incremental 

Reduction in 

Days Above 

0.5 Deciview 

(dV) (Days) 

Incremental dV 

Reductions 

(dV) 

Incremental Cost 

Effectiveness 

(Million$/Days) 

Incremental 

Cost 

Effectiveness 

(Million$/dV) 

Baseline and Scenario 1 17.0 0.56 $0.20 $6.09 

Scenario 1 and Scenario 2 0.7 0.05 $9.5 $134.9 

Scenario 1 and Scenario 3 10.3 0.31 $1.4 $47.6 

Scenario 1 and Scenario 4 11.3 0.32 $1.9 $65.6 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-5
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

FIGURE 5-1 

Least-cost Envelope Bridger Class I WA Days Reduction 

Jim Bridger 3 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0 2 4 6 810 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 3 

Scenario 3

Scenario 2

Scenario 1 Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-6
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

FIGURE 5-3 

Least-cost Envelope Fitzpatrick Class I WA Days Reduction 

Jim Bridger 3 

Scenario 3

Scenario 2

Scenario 1

Baseline

Scenario 4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

01234567

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

8

FIGURE 5-4 

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

Jim Bridger 3 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-7
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

FIGURE 5-5 

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

Jim Bridger 3 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0 5 10 15 20 25 30

Reduction in Days of Exceeding 0.5 dV (days)

Total Annualized Cost (Mil $)

FIGURE 5-6 

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

Jim Bridger 3 

Scenario 4

Baseline

Scenario 1

Scenario 2

Scenario 3

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

98th Percentile Delta-Deciview Reduction (dV)

Total Annualized Cost (Mil $)

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-8
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

5.1.2 Analysis Results 

Results of the least-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 for 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 Class I WA in Tables 5-1 and 5-4 and Figures 5-1 

and 5-2 illustrates these conclusions. The greatest reduction in 98th percentile dV and number of 

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

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

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

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

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

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

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, and 

have been assigned a presumptive BART NOx limit of 0.28 lb per MMBtu. 

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

projected significant reduction in NOx emissions, reasonable control costs, and the 

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

NOx 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 3, based on the significant reduction in SO2 emissions, reasonable control costs, 

and the advantages of both minimal additional power requirements and 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 3, 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_JB3_OCT2007_FINAL.DOC 5-9
BART ANALYSIS FOR JIM BRIDGER UNIT 3 

JMS EY102007001SLC\BART_JB3_OCT2007_FINAL.DOC 5-10

5.3 Just-Noticeable Differences in Atmospheric Haze 

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

Haze” by Dr. Ronald Henry (2002), state that 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 scenarios. Thus the results indicate that even though many 

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

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

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

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

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

visibility in these Class I areas. If natural obscuration lessens the achievable reduction on 

visibility impacts modeled for BART controls at the Jim Bridger 3 facility, the overall 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, 2003. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

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

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

and Nonattainment Area Permitting. Draft. October 1990. 

Henry, Ronald, 2002. “Just-Noticeable 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_JB3_OCT2007_FINAL.DOC 6-1
APPENDIX A 

Economic Analysis 
PacifiCorp BART Analysis Scenarios

5

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

 N/A N/A $ 3,387,923 

 N/A N/A $ 3,387,923  N/A N/A $ 3,387,923 

 N/A N/A $ 9,726,040 

 N/A N/A $ 9,726,040 

 N/A N/A $ 9,726,040 

 N/A N/A $ 18,074,111 

 N/A N/A $ 18,074,111  N/A N/A $ 18,074,111 

 N/A N/A $ 24,412,229 

 N/A N/A $ 24,412,229  N/A N/A $ 24,412,229 

Jim Bridger Unit 3

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

Scenario 4 - LNB witSCR, Wet FGD, ESP

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

Scenario 3 - LNB witSCR, Dry FGD, New 

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

Baseline - Current Operation with ESP

Baseline - Current OESP

NTN Unit 1 

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

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

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

JB Unit 1 JB Unit 2 JB Unit 3 

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 

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

EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 
ECONOMIC ANALYSIS SUMMARY

Jim Bridger Unit 3 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 ($) 0 8,700,001 20,528,122 21,973,632 129,575,495 FIRST YEAR O&M COST ($)

Operating Labor ($) 0 0 0 0 0 Maintenance Material ($) 0 28,000 42,000 122,000 190,000 Maintenance Labor ($) 0 42,000 63,000 183,000 285,000 Administrative Labor ($) 0 0 0 0 0 TOTAL FIXED O&M COST 0 70,000 105,000 305,000 475,000 

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 0 600,000 Waste Disposal Cost 0 0 0 0 0 Electric Power Cost 0 0 2,528,012 204,984 1,269,718 TOTAL VARIABLE O&M COST 0 0 2,528,012 1,210,795 2,782,566 

TOTAL FIRST YEAR O&M COST 0 70,000 2,633,012 1,515,795 3,257,566 

FIRST YEAR DEBT SERVICE ($) 0 827,612 1,952,796 2,090,304 12,326,235 TOTAL FIRST YEAR COST ($) 0 897,612 4,585,808 3,606,099 15,583,801 

Power Consumption (MW) 0.0 0.0 6.4 0.5 3.2 Annual Power Usage (Million kW-Hr/Yr) 0.0 0.0 50.6 4.1 25.4 

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.) 0 181 843 610 1,734 

Incremental Control Cost ($/Ton NOx Removed) 0 181 7,797 2,863 3,896 

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 (%) 99.33% 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 40,493,391 169,375,961 

NOx Control 

Parameter Current Operation

SO

EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 
INPUT CALCULATIONS

Jim Bridger Unit 3 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) 51,177 342 342 342 342 342  (Lb/MMBtu) 8.530 0.057 0.057 0.057 0.057 0.057  (Lb Moles/Hr) 1,705.3 11.4 11.4 11.4 11.4 11.4  (Tons/Yr) 201,739 1,348 1,348 1,348 1,348 1,348 Fly Ash Removal Rate (%) 99.33% 0.00% 0.00% 0.00% 0.00% 0.00% 

 (Lb/Hr) 50,835 0 0 0 0 0  (Ton/Yr) 200,391 0 0 0 0 0 Fly Ash Emission Rate (Lb/Hr) 342 342 342 342 342 342  (Lb/MMBtu) 0.057 0.057 0.057 0.057 0.057 0.057 

 (Ton/Yr) 1,348 1,348 1,348 1,348 1,348 1,348 

Parameter 

Current Operation NOx Control 

SO2 Con

EY102007001SLC\App A_PCorp JB3 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 21,973,632 129,575,495 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 21,973,632 129,575,495 12,999,9

NOx Emission Control System ($/kW) 0 16 39 41 244 0 SO2 Emission Control System ($/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 41 244 25 

Total Fixed Operating & Maintenance Costs

Operating Labor ($) 00000 0 Maintenance Material ($) 0 28,000 42,000 122,000 190,000 25,550 Maintenance Labor ($) 0 42,000 63,000 183,000 285,000 17,033 Administrative Labor ($) 00000 0 

Total Fixed O&M Cost ($) 0 70,000 105,000 305,000 475,000 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 52 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 29,927 

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 200 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 0 600,000 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% 0.61% 0.10%  (MW) 0.00 0.00 6.41 0.52 3.22 0.52 Unit Cost ($2006/MW-Hr) 50.00 50.00 50.00 50.00 50.00 50.00 

First Year Auxiliary Power Cost ($) 0 0 2,528,012 204,984 1,269,718 204,98

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

EY102007001SLC\App A_PCorp JB3 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 JB3 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 JB3 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 JB3 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 JB3 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 JB3 BART Economic Analysis_01-11-07.xls 
CAPITAL COST

Jim Bridger Unit 3

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 $9,419,000 S&L Report $80,923,000 S&L Report $0 S&L ReporContingency 20.0% $0 20.0% $0 20.0% $1,883,800 20.0% $16,184,600 20.0% $0 20.0% 

Labor Premium 5.6% $0 5.6% $0 5.6% $526,805 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% $103,797 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% $264,391 2.8% $2,271,509 2.8% $0 2.8% 

Surcharge and AFUDC 11.4% $0 11.4% $0 11.4% $1,075,838 11.4% $9,243,025 11.4% $0 11.4% 

Total Capital Cost for SNCR or SCR $0 $0 $13,273,632 $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 JB3 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 3 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 3 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 JB3 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 3 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 305,000 - 1,005,811 - - 204,984 1,210,795 

 

2 2015 311,100 - 1,025,927 - - 209,084 1,235,011 

 

3 2016 317,322 - 1,046,446 - - 213,265 1,259,711 

 

4 2017 323,668 - 1,067,375 - - 217,531 1,284,905 

 

5 2018 330,142 - 1,088,722 - - 221,881 1,310,603 

 

6 2019 336,745 - 1,110,496 - - 226,319 1,336,815 

 

7 2020 343,480 - 1,132,706 - - 230,845 1,363,552 

 

8 2021 350,349 - 1,155,361 - - 235,462 1,390,823 

 

9 2022 357,356 - 1,178,468 - - 240,171 1,418,639 

 

10 2023 364,503 - 1,202,037 - - 244,975 1,447,012 

 

11 2024 371,793 - 1,226,078 - - 249,874 1,475,952 

 

12 2025 379,229 - 1,250,599 - - 254,872 1,505,471 

 

13 2026 386,814 - 1,275,611 - - 259,969 1,535,581 

 

14 2027 394,550 - 1,301,124 - - 265,169 1,566,292 

 

15 2028 402,441 - 1,327,146 - - 270,472 1,597,618 

 

16 2029 410,490 - 1,353,689 - - 275,881 1,629,570 

 

17 2030 418,700 - 1,380,763 - - 281,399 1,662,162 

 

18 2031 427,074 - 1,408,378 - - 287,027 1,695,405 

 

19 2032 435,615 - 1,436,546 - - 292,768 1,729,313 

 

20 2033 444,327 - 1,465,276 - - 298,623 1,763,899 

 

Present Worth - 3,726,445 12,288,849 - - 2,504,464 14,793,314 2

 

(% of PW) 9.2% 0.0% 30.3% 0.0% 0.0% 6.2% 36.5% 

Jim Bridger Unit 3 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 - 912,848 600,000 - 1,269,718 2,782,566 1

 

2 2015 484,500 - 931,105 612,000 - 1,295,113 2,838,218 1

 

3 2016 494,190 - 949,727 624,240 - 1,321,015 2,894,982 1

 

4 2017 504,074 - 968,722 636,725 - 1,347,435 2,952,882 1

 

5 2018 514,155 - 988,096 649,459 - 1,374,384 3,011,939 1

 

6 2019 524,438 - 1,007,858 662,448 - 1,401,871 3,072,178 1

 

7 2020 534,927 - 1,028,015 675,697 - 1,429,909 3,133,622 1

 

8 2021 545,626 - 1,048,575 689,211 - 1,458,507 3,196,294 1

 

9 2022 556,538 - 1,069,547 702,996 - 1,487,677 3,260,220 1

 

10 2023 567,669 - 1,090,938 717,056 - 1,517,431 3,325,424 1

 

11 2024 579,022 - 1,112,757 731,397 - 1,547,779 3,391,933 1

 

12 2025 590,603 - 1,135,012 746,025 - 1,578,735 3,459,771 1

 

13 2026 602,415 - 1,157,712 760,945 - 1,610,310 3,528,967 1

 

14 2027 614,463 - 1,180,866 776,164 - 1,642,516 3,599,546 1

 

15 2028 626,752 - 1,204,484 791,687 - 1,675,366 3,671,537 1

 

16 2029 639,287 - 1,228,573 807,521 - 1,708,874 3,744,968 1

 

17 2030 652,073 - 1,253,145 823,671 - 1,743,051 3,819,867 1

 

18 2031 665,115 - 1,278,208 840,145 - 1,777,912 3,896,264 1

 

19 2032 678,417 - 1,303,772 856,948 - 1,813,470 3,974,190 1

 

20 2033 691,985 - 1,329,847 874,087 - 1,849,740 4,053,674 1

 

Present Worth - 5,803,480 11,153,043 7,330,712 - 15,513,231 33,996,986 12

 

(% of PW) 3.4% 0.0% 6.6% 4.3% 0.0% 9.2% 20.1% 

EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 3 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 29,927 533,206 - 442,958 204,984 1,211,075 

 

2 2015 43,435 30,526 543,870 - 451,818 209,084 1,235,297 

 

3 2016 44,303 31,136 554,747 - 460,854 213,265 1,260,003 

 

4 2017 45,189 31,759 565,842 - 470,071 217,531 1,285,203 

 

5 2018 46,093 32,394 577,159 - 479,472 221,881 1,310,907 

 

6 2019 47,015 33,042 588,702 - 489,062 226,319 1,337,125 

 

7 2020 47,955 33,703 600,476 - 498,843 230,845 1,363,868 

 

8 2021 48,914 34,377 612,486 - 508,820 235,462 1,391,145 

 

9 2022 49,893 35,065 624,735 - 518,996 240,171 1,418,968 

 

10 2023 50,890 35,766 637,230 - 529,376 244,975 1,447,347 

 

11 2024 51,908 36,481 649,975 - 539,964 249,874 1,476,294 

 

12 2025 52,946 37,211 662,974 - 550,763 254,872 1,505,820 

 

13 2026 54,005 37,955 676,234 - 561,778 259,969 1,535,936 

 

14 2027 55,085 38,714 689,758 - 573,014 265,169 1,566,655 

 

15 2028 56,187 39,488 703,554 - 584,474 270,472 1,597,988 

 

16 2029 57,311 40,278 717,625 - 596,164 275,881 1,629,948 

 

17 2030 58,457 41,084 731,977 - 608,087 281,399 1,662,547 

 

18 2031 59,626 41,905 746,617 - 620,249 287,027 1,695,798 

 

19 2032 60,819 42,744 761,549 - 632,654 292,768 1,729,714 

 

20 2033 62,035 43,598 776,780 - 645,307 298,623 1,764,308 

 

Present Worth 365,648 520,271 6,514,628 - 5,412,000 2,504,464 14,796,741 1

 

(% of PW) 1.8% 1.3% 23.0% 0.0% 19.1% 8.8% 52.3% 

Jim Bridger Unit 3 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 JB3 BART Economic Analysis_01-11-07.xls 
Jim Bridger Unit 3 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 - - 294,008 - 1,313,474 1,607,482 

 

2 2015 130,304 - - 299,888 - 1,339,744 1,639,632 

 

3 2016 132,910 - - 305,886 - 1,366,539 1,672,425 

 

4 2017 135,568 - - 312,004 - 1,393,870 1,705,873 

 

5 2018 138,279 - - 318,244 - 1,421,747 1,739,991 

 

6 2019 141,045 - - 324,609 - 1,450,182 1,774,790 

 

7 2020 143,866 - - 331,101 - 1,479,186 1,810,286 

 

8 2021 146,743 - - 337,723 - 1,508,769 1,846,492 

 

9 2022 149,678 - - 344,477 - 1,538,945 1,883,422 

 

10 2023 152,671 - - 351,367 - 1,569,723 1,921,090 

 

11 2024 155,725 - - 358,394 - 1,601,118 1,959,512 

 

12 2025 158,839 - - 365,562 - 1,633,140 1,998,702 

 

13 2026 162,016 - - 372,873 - 1,665,803 2,038,676 

 

14 2027 165,256 - - 380,331 - 1,699,119 2,079,450 

 

15 2028 168,562 - - 387,937 - 1,733,102 2,121,039 

 

16 2029 171,933 - - 395,696 - 1,767,764 2,163,460 

 

17 2030 175,371 - - 403,610 - 1,803,119 2,206,729 

 

18 2031 178,879 - - 411,682 - 1,839,181 2,250,863 

 

19 2032 182,456 - - 419,916 - 1,875,965 2,295,881 

 

20 2033 186,106 - - 428,314 - 1,913,484 2,341,798 

 

Present Worth - 1,560,813 - 3,592,147 - 16,047,838 19,639,984 4

 

(% of PW) 2.2% 0.0% 0.0% 5.2% 0.0% 23.1% 28.2% 

EY102007001SLC\App A_PCorp JB3 BART Economic Analysis_01-11-07.xls 
EY102007001SLC\App A_PCorp JB3 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 JB3 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