DEN/ES072007003/TRACY_3_10-03-08.DOC 

BART Analysis for 

Tracy Unit 3 

Prepared For: 

NV Energy 

6100 Neil Road 

Reno, NV 89520-0024 

Revised Report 

October 2008 

Prepared By: 

2285 Corporate Circle 

Henderson, NV 89074 
DEN/ES072007003/TRACY_3_10-03-08.DOC ES-1 

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 NV 

Energy (NVE) Tracy Unit 3 (hereafter referred to as Tracy 3). A BART analysis has been 

conducted for the following criteria pollutants: oxides of nitrogen (NOx), sulfur dioxide 

(SO2), and particulate matter less than 10 microns in aerodynamic diameter (PM10). The Tracy 

Station consists of three BART eligible units with a total nominal generating capacity of 

251 megawatt (MW), of which Tracy 3 is a nominal 113-MW unit. The Title V permit allows 

burning Pipeline Quality Natural Gas (PNG) or blended residual (No. 2 and No. 6 and 

non-PCB mineral oil) fuel oil (Tracy 3 is not currently physically configured to allow burning 

No. 2 fuel oil). BART must be implemented within 5 years after the State Implementation 

Plan (SIP) is approved by the United States Environmental Protection Agency (EPA), and a 

compliance date of 2015 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 for when the unit is 

burning 1) 100 percent PNG, 2) 100 percent No. 6 fuel oil, and 3) 100 percent No. 2 fuel oil. 

The following technology alternatives were investigated for the PNG and both fuel oil 

alternatives and are listed below by pollutant: 

NOx emission controls: 

• Low NOx Burners (LNB) 

• Low NOx Burners (LNG) with Flue Gas Recirculation (FGR) 

• Low NOx Burners (LNB) with selective non-catalytic reduction system (SNCR) 

• Rotating opposed fire air (ROFA) with Rotamix 

• LNB with selective catalytic reduction (SCR) system 

SO2 emission controls: 

• Use of low sulfur fuel 

• Spray Dryer Absorber (SDA) 

PM10 emission controls: 

• Use of low sulfur fuel oil (No. 2 fuel oil) and LNB 

• Dry Electrostatic Precipitator (ESP) 

• Wet Electrostatic Precipitator 

• Fabric filter 
EXECUTIVE SUMMARY 

DEN/ES072007003/TRACY_3_10-03-08.DOC ES-2 

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 

following: 

1. The identification of available, technically feasible, retrofit control options 

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

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance 

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

BART 

These steps are incorporated into the BART analysis as follows: 

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 

• Costs associated with control technologies are summarized in the economic analysis 

presented in Appendix A. For clarity, Appendix A also includes sample economic 

analysis spreadsheet calculations and explanation of assumptions used. 

Step 4 – Evaluate Energy and Non-Air Quality 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 

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 2007 dollars, and costs have not been escalated to the 

assumed 2015 BART implementation date. 
EXECUTIVE SUMMARY 

DEN/ES072007003/TRACY_3_10-03-08.DOC ES-3 

Establishing Emission Reduction Levels from BART Analysis Results 

As an integral part of the BART analysis process, cost and expected emission information 

was developed for NOx, SO2, and PM10. This information is assembled from various sources 

including emission reduction equipment vendors, NV Energy operating and engineering 

data, and internal CH2M HILL historical information. 

The level of accuracy of the cost estimate can be broadly classified as American Association 

of Cost Engineers (AACE) Class V or “Order of Magnitude,” which can be categorized as 

+50 percent/-30 percent. There are several reasons for selecting this range of cost estimates 

to be included in the BART analysis. They are primarily a result of the difficulty in receiving 

detailed and accurate information from equipment vendors based on limited available data 

provided to the vendors. Because of the active power industry marketplace, obtaining 

engineering and construction information is restricted due to vendor workload. Material 

and construction labor costs also change rapidly in today’s active economy. However, this 

level of cost estimate precision is adequate for comparison of control technology 

alternatives. The accuracy of expected emissions may also be questionable, and is also 

attributable to the inability to gain timely and accurate vendor information. This is 

exemplified by the difficulty in obtaining background information, and the vendor time 

required to develop accurate emission projections for study purposes in comparison to their 

response to actual project request for proposals. Also, variance in expected emissions can be 

dependent upon the pollutant under consideration (i.e., particulate emissions can generally 

be more accurately predicted than NOx emissions). Therefore, when establishing emission 

limitations in permits, consideration of variability in cost and expected emissions 

information must be considered. 

Fuel Characteristics 

From the Title V Operating Permit, the primary fuel burned at Tracy 3 will be PNG. The 

secondary fuel source is blended fuel oil (blended fuel oil is defined as the blending of No. 6 

residual oil and No. 2 distillate fuel oil), and a third fuel option is co-fired PNG and blended 

fuel oil. Only the 100 percent PNG and 100 percent fuel oil options will be examined, and no 

co-firing or blended fuel alternatives will be reviewed. The capability to exclusively burn 

No. 2 fuel oil does not currently exist, and capital expenditures would be required to allow 

this fuel option. This BART analysis has considered the higher nitrogen content and the 

different combustion characteristics of fuel oil as compared to PNG used at Tracy 3, and has 

evaluated the effect of these qualities on NOx formation and achievable emission rates. 

The Nevada Public Utilities Commission has mandated that Tracy Unit 3 maintain the 

capability to use both PNG and fuel oil. However, as a first step in the BART 

implementation plan, NV Energy has committed to use only low-sulfur No. 2 fuel oil. Thus, 

the listing of No. 6 fuel oil in the BART engineering analysis is for historical and comparison 

purposes only. 
EXECUTIVE SUMMARY 

DEN/ES072007003/TRACY_3_10-03-08.DOC ES-4 

Recommendations 

NOx Emission Control 

New LNB has been selected as the NOx reduction technology with a NV Energy BART Limit 

(NVEBL) of 0.27 lb/MMBtu averaged on an annual basis. There is significant uncertainty 

involved in obtaining vendor emission guarantees and associated equipment/construction 

costs at this stage of analysis when retrofitting older boiler units. Site specific engineering is 

required on a “unit by unit” basis to determine the most effective control technology. 

SO2 Emission Control 

The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART for Tracy 3 with an NVEBL 

of 0.05 lb/MMBtu averaged on a 24-hour basis. No additional SO2 emission control is 

required. No. 6 fuel oil will no longer be burned at the facility. 

PM10 Emission Control 

The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART for Tracy 3 with an NVEBL 

of 0.03 lb/MMBtu averaged on a 3-hour basis. No additional PM10 emission control is 

required. No. 6 fuel oil will no longer be burned at the facility. 

Control Recommendation 

The BART selections include the utilization of LNB with PNG and/or low-sulfur No. 2 fuel 

oil, and are supported by cost and visibility analyses. 

BART Modeling Analysis 

CH2M HILL is using the Gaussian puff dispersion model (CALPUFF) modeling system to 

assess the visibility impacts of emissions from Tracy 3 at Class I areas. The Class I areas 

potentially affected are located more than 50 kilometers, but less than 300 kilometers, from 

the Tracy Plant. 

The Class I areas include the following wilderness areas (WA) and National Parks (NP): 

• Ansel Adams Wilderness (Minarets Wilderness) 

• Caribou WA 

• Desolation WA 

• Emigrant WA 

• Hoover WA 

• John Muir WA 

• Kaiser WA 

• Kings Canyon NP 

• Lava Beds NM 

• Lassen Volcanic NP 

• Mokelumne WA 

• South Warner WA 

• Thousand Lakes WA 

• Yolla Bolly Middle Eel WA 
EXECUTIVE SUMMARY 

DEN/ES072007003/TRACY_3_10-03-08.DOC ES-5 

• Yosemite NP 

Visibility impacts were determined for the 1) WRAP baseline, 2) the current Title V emission 

permit limits, and 3) at an emission rate higher than the proposed NVEBL. 
DEN/ES072007003/TRACY_3_10-03-08.DOC ii 

Contents 

Section Page 

Executive Summary......................................................................................................................ES-1

Background .................................................................................................................................... ES-1

BART Engineering Analysis ........................................................................................................ ES-2

Establishing Emission Reduction Levels from BART Analysis Results ................... ES-3

Fuel Characteristics ....................................................................................................................... ES-3

Recommendations......................................................................................................................... ES-4

NOx Emission Control ..................................................................................................... ES-4

SO2 Emission Control....................................................................................................... ES-4

PM10 Emission Control .................................................................................................... ES-4

Control Recommendation ............................................................................................... ES-4

BART Modeling Analysis............................................................................................................. ES-4

Acronyms and Abbreviations .........................................................................................................iv

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 ...............................................................................................3-3

3.2.2 BART SO2 Analysis ..............................................................................................3-12

3.2.3 BART PM10 Analysis ............................................................................................3-14

3.3 Summary.............................................................................................................................3-17

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

4.1 Introduction..........................................................................................................................4-1

4.2 Model Selection....................................................................................................................4-1

4.3 CALMET Methodology......................................................................................................4-2

4.3.1 Dimensions of the Modeling Domain .................................................................4-2

4.3.2 CALMET Input Data..............................................................................................4-4

4.3.3 Validation of CALMET Wind Field.....................................................................4-5

4.4 CALPUFF Methodology.....................................................................................................4-6

4.4.1 CALPUFF Modeling ..............................................................................................4-6

4.4.2 Receptor Grids and Coordinate Conversion ......................................................4-7

4.5 Visibility Post-processing...................................................................................................4-8

4.5.1 CALPOST ................................................................................................................4-8

4.6 Results ...................................................................................................................................4-8

4.6.1 WRAP Verification Runs Results .........................................................................4-9

4.6.2 BART Modeling Analysis....................................................................................4-10

5.0 BART Analysis and Recommendations.........................................................................5-1

5.1 Recommended BART Controls .........................................................................................5-1

5.2 Dispersion Modeling Results.............................................................................................5-2

5.2.1 NOx Control Scenario Visibility Modeling .........................................................5-6

5.3 Recommendations...............................................................................................................5-8

5.3.1 NOx Emission Control ...........................................................................................5-8

5.3.2 SO2 Emission Control.............................................................................................5-8
CONTENTS 

DEN/ES072007003/TRACY_3_10-03-08.DOC iii 

5.3.3 PM10 Emission Control...........................................................................................5-8

5.4 Just-Noticeable Differences in Atmospheric Haze .........................................................5-8

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

Appendices 

A Economic Analysis 

B BART Protocol 
DEN/ES072007003/TRACY_3_10-03-08.DOC iv 

Acronyms and Abbreviations 

ACFM actual cubic feet per minute 

BACT Best Available Control Technology 

BAQP Bureau of Air Quality Planning 

BART Best Available Retrofit Technology 

Btu/gal British thermal unit per gallon 

Btu/kW-hr British thermal unit per kilowatt-hour 

Btu/scf British thermal unit per standard cubic foot 

CALDESK Program to display data and results 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing program for calculating visibility impacts 

CALPUFF Gaussian puff dispersion model 

CFR Code of Federal Regulations 

COHPAC Compact Hybrid Particulate Collector 

dV deciview 

∆dV delta deciview, change in deciview 

ESP electrostatic precipitator 

EPA United States Environmental Protection Agency 

°F degree Fahrenheit 

Fuel NOx oxidation of fuel bound nitrogen 

FGC flue gas conditioning 

FGD flue gas desulfurization 

f (RH) relative humidity factors 

hp horsepower 

H2S hydrogen sulfide 

ID internal diameter 

kW kilowatt 

kW-Hr kilowatt-hour 

kW-Hr/Yr kilowatt-hour per year 

LAER lowest achievable emission rate 

lb pound 

lb/MMBtu pound per million British thermal unit 

LNB low-NOx burner 
ACRONYMS AND ABBREVIAITONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC v 

LOI loss on ignition 

MMBtu Million British thermal unit 

MM5 Mesoscale Meteorological Model, Version 5 

MSL mean sea level 

MW megawatt 

N2 nitrogen 

NDEP Nevada Department of Environmental Protection 

NO nitric oxide 

NOx oxides of nitrogen 

NP National Park 

NVE NV Energy 

NWS National Weather Service 

OFA over-fire air 

O&M operation and maintenance 

PM10 particulate matter less than 10 microns in aerodynamic diameter 

PNG Pipeline Quality Natural Gas 

RACT reasonably available control technology 

ROFA rotating opposed fire air 

NVEBL NV Energy BART Limit 

SCR selective catalytic reduction system 

SDA Spray Dryer Absorber 

SIP State Implementation Plan 

SNCR selective non-catalytic reduction system 

SO2 sulfur dioxide 

SO3 sulfur trioxide 

sq. ft. square feet 

Thermal NOx high temperature fixation of atmospheric nitrogen in combustion air 

Tracy 3 Tracy Unit 3 

USGS U.S. Geological Survey 

WA Wilderness Area 
DEN/ES072007003/TRACY_3_10-03-08.DOC 1-1 

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 States1. 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/year of visibility-impairing pollutants. 

The State of Nevada 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 Nevada State Implementation Plan (SIP), which 

the State has estimated will be formally submitted to the EPA by December 1, 2008. The 

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

within five years of EPA’s approval of the SIP. 

There are five basic elements related to BART, when addressing 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 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 Tracy 3 by CH2M HILL 

for NV Energy. The analysis was performed for nitrogen oxides (NOx), sulfur dioxide (SO2), 

and particulate matter less than 10 microns in aerodynamic diameter (PM10), because they 

are the primary criteria pollutants that affect visibility for unit operation while burning both 

natural gas and fuel oil. 

Section 2.0 of this report provides a description of the present unit operation, including a 

discussion of fuel sources and analysis. The BART Engineering Analysis is provided in 

Section 3.0, by pollutant type. Section 4.0 provides the BART modeling methodology and 

Section 5.0 discusses the BART analysis and recommendations. References are provided in 

Section 6.0. Appendices A and B provide supporting information on the Economic Analysis, 

and BART modeling protocol. 

 

1 40 CFR Part 51: Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; 

Final Rule. 70 Federal Register, 39103-39172, July 6, 2005. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 2-1 

2.0 Present Unit Operation 

Tracy 3 is a nominal 113-megawatt (MW) unit located in Storey County, Nevada. The unit is 

equipped with a front wall-fired boiler manufactured by Babcock and Wilcox. In accordance 

with the Title V Operating Permit, the unit can currently be fired using 1) pipeline quality 

natural gas (PNG), 2) blended fuel oil (blended fuel oil is defined as the blending of No. 6 

residual oil and No. 2 distillate fuel oil), or 3) co-fired PNG and blended fuel oil. 

Tracy 3 began operation in 1974. This analysis is based on a 23-year life for BART control 

technologies. Assuming a BART implementation date of 2015, this will result in an 

approximate remaining useful life for Tracy 3 of 23 years from the installation date of any 

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

extension costs needed to allow the unit at Tracy 3 to operate until 2038. 

Determining current operating NOx levels before any potential emissions control equipment 

installation is difficult, especially because higher NOx emissions can be expected at higher 

unit operating loads. Therefore, PNG current NOx level is approximated by averaging the 

highest 75 percent load 24-hour NOx emission levels for the year 2006 EPA Acid Rain 

Database. As a simplifying assumption, No. 2 fuel oil NOx emissions are assumed to be 

equal to PNG. The No. 6 fuel oil NOx emissions were estimated by averaging the 24-hour 

NOx values for the year 2001 EPA Acid Rain Database. Tracy Unit 3 burned No. 6 fuel oil for 

a few months during the Western energy crisis in 2001. The SO2 emissions were also 

estimated from the EPA Acid Rain Database. PM10 values were determined either by test 

results or AP-42 calculations. 

The BART regulations state that the baseline emissions utilized for visibility modeling be 

established by identifying the highest 24-hour average actual emission rate from the period 

modeled for the pre-control scenario. Modeling would then consider the expected emissions 

rate after the installation of BART controls to establish the level of visibility improvement. 

For the pre-control scenario, modeling was conducted at the WRAP 24-hour maximum 

values and at the Title V permit limits for the unit. The post-control scenario was modeled at 

the proposed NVEBL (discussed in Sections 3, 4, and 5), with the exception of the NOx

emission rate which is higher than the NVEBL. 

Table 2-1 lists unit information and emission rates for this analysis. 
2.0 PRESENT UNIT OPERATION 

DEN/ES072007003/TRACY_3_10-03-08.DOC 2-2 

TABLE 2-1 

Unit Operation and Study Assumptions 

Tracy Unit 3 

General Plant Data 

Site Elevation (feet above MSL) 4,262 

Stack Height (feet) 300 

Stack Exit ID (feet) /Exit Area (sq. ft.) 9.0 /63.62 

Stack Exit Temperature (°F) 312 

Stack Exit Velocity (ft/sec) 77.8 

Annual Unit Capacity Factor (%) 58 

Net Unit Output (Nominal MW) 113 

Net Unit Heat Rate (Btu/kW-Hr)(100% load) 10,177 

Boiler Heat Input (MMBtu/Hr)(100% load) 1,150 

Type of Boiler Front Wall fired 

Boiler Fuel PNG, Blended Fuel Oil 

NOx Emissions Data (24-hour Average Maximum) 

Current NOx Controls None: Good combustion practices 

Title V NOx Permit Limit (lb/MMBtu) 0.45 

WRAP NOx Emission Rate (lb/MMBtu) 0.315 

NOx Emission Rate (lb/MMBtu) (PNG)d 0.292 

NOx Emission Rate (lb/MMBtu) (No.6 Fuel Oil) a 0.323 

NOx Emission Rate (lb/MMBtu) (No.2 Fuel Oil) d 0.292 

SO2 Emissions Data (24-hour Average Maximum) 

Current SO2 Controls None 

Title V SO2 Permit Limit (lb/MMBtu) (3-hr average) 0.76 

WRAP SO2 Emission Rate (lb/MMBtu) 0.540 

SO2 Emission Rate (lb/MMBtu) (PNG) e 0.0006 

SO2 Emission Rate (lb/MMBtu) (No.6 Fuel Oil) a 0.445 

SO2 Emission Rate (lb/MMBtu) (No.2 Fuel Oil) b 0.051 

PM10 Emissions Data (24-hour Average Maximum) 

Current PM10 Controls None 

Title V PM10 Permit Limit (lb/MMBtu) (1-hr average) 0.20 

WRAP PM10 Emission Rate (lb/MMBtu) 0.053 

PM10 Emission Rate (lb/MMBtu) (PNG)e 0.008 

PM10 Emission Rate (lb/MMBtu) (No.6 Fuel Oil) c 0.065 

PM10 Emission Rate (lb/MMBtu) (No.2 Fuel Oil) b 0.014 

a

 - Highest 24-hr averages from 2001 CEM data. 

b

 - Calculated from EPA AP-42 Table 1.3-1 assuming No. 2 fuel oil sulfur content of 0.05 percent and 

heating value of 140,000 Btu/gal 

c

 - Calculated from EPA AP-42 Table 1.3-1 assuming No. 6 fuel oil sulfur content of 0.75 percent and 

heating value of 156,000 Btu/gal 

d

 – Highest 24-hr averages 

from 2006 CEM data. 

e

 – Calculated from EPA AP-42 Table 1-4.2 

EPA did not establish a NOx presumptive limit for oil- and gas-fired units, but indicates that 

the states should consider the installation of combustion control technology on these units. 

Similarly, EPA also did not establish a presumptive BART limit for SO2 from gas and 
2.0 PRESENT UNIT OPERATION 

DEN/ES072007003/TRACY_3_10-03-08.DOC 2-3 

oil-fired units. The EPA guidelines suggest that a cost effective SO2 control option for oilfired units is to consider switching to a low-sulfur fuel oil (No.2 fuel oil—0.05 percent sulfur 

diesel). EPA also stated that it was unable to find a flue gas desulfurization (FGD) 

application in the U.S. electric industry on an oil-fired unit.

According to 40 CFR Parts 72 and 75, in order for a gaseous fuel to qualify as “natural gas,” 

the fuel must be either greater than or equal to 70 percent methane by volume, or must have 

a gross calorific value between 950 and 1,100 British thermal units (Btu)/standard cubic foot 

(scf). For PNG, the hydrogen sulfide (H2S) content must be less than or equal to 

0.3 grain/100 scf, and H2S must constitute at least 50 percent (by weight) of the total sulfur 

in the fuel. 

No fuel specification was provided for No. 2 fuel oil, therefore a heating value of 

140,000 Btu/gal and a sulfur limit of 0.05 percent were assumed. Heating value for No. 6 

fuel oil was assumed at 155,000 Btu/gal. 

Specification values for No. 6 fuel oil are listed below: 

• 6.1 to 6.45 MMBtu/barrel heating value 

• 0.39 lb of sulfur/MMBtu 

• Less than 0.1 percent ash by weight 

• Less than 50 parts per million (ppm) vanadium 

• Less than 50 ppm sodium 

• Less than 9.7 percent carbon residue by weight 

The BART analysis for Tracy 3 includes a review of PNG, No. 2 fuel oil, and No. 6 fuel oil 

operation. The WRAP baseline modeling included 2001 operation when No. 6 fuel oil was 

burned. Therefore, this fuel option is shown in the analysis. 

The Nevada Public Utilities Commission has mandated that Tracy Unit 3 maintain the 

capability to use both PNG and fuel oil. However, as a first step in the BART 

implementation plan, NV Energy has committed to use only low-sulfur No. 2 fuel oil. Thus, 

the listing of No. 6 fuel oil in the BART engineering analysis is for historical and comparison 

purposes only. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 3-1 

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 Nevada must prepare and 

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

submittal of the SIPs to EPA will occur by December 1, 2008. The first phase of the regional 

haze program is the implementation of BART emission controls on all BART eligible units, 

within 5 years after EPA approval of the SIP. 

3.2 BART Process 

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

Section IV. The evaluation must include the following: 

1. The identification of available, technically feasible, retrofit control options 

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

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance, and 

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

BART. 

These steps are incorporated into the BART analysis as follows: 

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 

• Costs associated with control technologies are summarized in the economic analysis 

presented in Appendix A. For clarity, Appendix A also includes sample economic 

analysis spreadsheet calculations and explanation of assumptions used. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-2 

Step 4 – Evaluate Energy and Non-Air Quality 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 

Step 5 – Evaluate Visibility Impacts 

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

use. 

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

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

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

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

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

developed. 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. Because Tracy 3 

currently has the option to burn PNG, No. 2 fuel oil, or a blended No. 6 fuel oil, a separate 

analysis will be completed for each case. The option to switch to low sulfur fuel oil (No. 2) 

will be examined, as required by the BART regulations. 

For Tracy 3, baseline NOx, SO2, PM10 emissions were examined to determine whether 

completion of the five-step BART process is required for each of the three fuel alternatives 

(100 percent PNG, 100 percent No. 6 fuel oil, and 100 percent No. 2 fuel oil).

Table 3-1 below is a summary of the baseline emissions for Tracy 3. 

TABLE 3-1 

Current Tracy 3 Baseline Emissions 

Baseline Emissions 

(lb/MMBtu) PNG No. 6 Fuel Oil No. 2 Fuel Oil 

NOx 0.292 0.323 0.292 

SO2 0.0006 0.445 0.051 

PM10 0.008 0.065 0.014 

A BART NOx analysis was completed for all fuels. An SO2 analysis and a PM10 analysis for 

No. 6 fuel oil were completed for comparison purposes (as stated in Section 2 of this report. 

NV Energy has made a commitment to only use low-sulfur No. 2 fuel oil). The baseline PM10

and SO2 emissions when burning No. 2 fuel oil are considered BART, based on EPA BART 

guidelines. 

All costs included in the BART analysis are in 2007 dollars, and costs have not been 

escalated to the assumed 2015 BART implementation date. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-3 

Establishing Permit Emission Reduction Levels from BART Analysis Results 

As an integral part of the BART analysis process, cost, and expected emission information 

was developed for NOx, SO2, and PM10. This information is assembled from various sources 

including emission reduction equipment vendors, NV Energy operating and engineering 

data, and internal CH2M HILL historical information. 

The level of accuracy of the cost estimate can be broadly classified as “Order of Magnitude,” 

which can be categorized as -30/+50 percent. There are several reasons for the wide range of 

cost estimates included in the BART analysis, however are primarily caused by the difficulty 

in receiving detailed and accurate information from equipment vendors. Because of the 

extremely active power industry marketplace, obtaining engineering and construction 

information is severely restricted due to vendor workload. Material and construction labor 

costs are also widely fluctuating in today’s active economy. 

The accuracy of expected emissions may also be questionable, and is also attributable to the 

inability to gain timely and accurate information. This is exemplified by the difficulty in 

obtaining background information, and the vendor time required to develop accurate 

emission projections for study purposes as opposed to their response to actual project 

request for proposals. Also, variance in expected emissions can be dependent upon the 

pollutant under consideration (i.e., particulate emissions can generally be more accurately 

predicted than NOx emissions). 

Therefore, when selecting emissions control technologies and establishing emission 

permitting levels, consideration of variability in cost and expected emissions information 

must be considered. 

3.2.1 BART NOx Analysis 

NOx formation in natural gas-fired boilers is a complex process that is dependent on a 

number of variables, including operating conditions, equipment design, and fuel 

characteristics. A NOx BART analysis will be completed for the cases when Tracy 3 burns 

100 percent PNG, 100 percent No. 6 fuel oil, and 100 percent No. 2 fuel oil. 

3.2.1.1 Formation of NOx 

During combustion NOx is formed in three different ways; thermal NOx, fuel NOx, and 

prompt NOx. When combusting PNG, the most dominant source of NOx is from thermal 

NOx, which is due to high temperature fixation of atmospheric nitrogen in the combustion 

air. Because PNG generally contains small quantities of nitrogen the overall contribution 

from fuel NOx is small, while fuel NOx can be generated from fuel oil combustion. A very 

small amount of NOx is called “prompt” NOx. Prompt NOx results from an interaction of 

hydrocarbon radicals, nitrogen, and oxygen. 

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

performance requirement such as NOx emission limits is changed, conflicts with other 

performance issues can result. 

When adjusting air flows and distribution to lower NOx using LNB and over-fire air (OFA), 

original boiler design restrictions may limit the changes that can be made and still achieve 

satisfactory combustion performance. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-4 

3.2.1.2 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 Tracy 3, including those control technologies identified as BACT 

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

been reviewed in an effort to identify potentially applicable and demonstrated in practice 

emission control technologies. Tracy 3 NOx emissions are currently controlled through the 

use of good combustion practices. There is no BART presumptive NOx level for PNG and 

oil-fired units. 

The following potential NOx control technology options were considered: 

• Low NOx Burners (LNB) 

• Low NOx Burners (LNB) with Flue Gas Recirculation (FGR) 

• Low NOx Burners (LNB with Selective non-catalytic reduction system (SNCR) 

• Rotating Opposed Fire Air (ROFA) with Rotamix 

• LNB with selective catalytic reduction system (SCR) 

3.2.1.3 Step 2: Eliminate Technically Infeasible Options 

For Tracy 3, a front wall-fired configuration burning PNG and fuel oil, technical feasibility 

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

of the technology to achieve NOx emissions reduction. Current NOx emissions for Tracy 3 are 

shown in Table 3-1 while burning PNG, No. 6 fuel oil, and No. 2 fuel oil. 

For this BART analysis, information received from Coen ws used as the basis for new LNB 

and LNB w/FGR. Coen did not propose the installation of OFA due to the cost of boiler 

water wall changes. The cost estimates for SCR and SNCR were updated from previous 

CH2M HILL file information and Fuel Tech budgetary proposal respectively. Also, 

CH2M HILL received a proposal from Mobotec for their ROFA and Rotomix technologies. 

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

with projected NOx emission rates. It should be noted that estimated emissions information 

from NOx technologies presented represent design targets. With a significant potential for 

variability in emissions due to changes in unit operation, a longer averaging period results 

in a higher probability in meeting the permit emissions value. Emissions based on a 24-hour 

averaging period are not directly comparable to emissions targets based on a longer 

averaging time. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-5 

TABLE 3-2 

NOx Control Technology Emission Rate Ranking 

Tracy Unit 3 

Technology 

Source of 

Estimated 

Emissions 

Estimated 

Emission Rate 

(lb/MMBtu) 

(PNG) 

Estimated 

Emission Rate 

(lb/MMBtu) 

 (No.6 Fuel Oil) 

Estimated 

Emission Rate 

(lb/MMBtu) 

(No.2 Fuel Oil) 

Current Permit Limits 

(converted to lb/MMBtu 

for comparison) 

Title V 0.45 0.45 0.45 

NV Energy (NVE) BART 

Limits 

NVEBLd 0.27 (Annual) N/A 0.27 (Annual) 

LNB Coen 0.25 0.27 0.25 

LNB w/FGR Coen 0.11 0.23 0.13 

LNB w/ SNCR Coen & Fuel 

Tech 

0.19 c 0.20 c 0.19 c

ROFA w/Rotamix Mobotec 0.16 0.18 b 0.16 

LNB w/SCR a CH2M HILL 0.07 0.07 0.07 

a

 - SCR estimated NOx emissions rate is the same for all scenarios. Operating cost would be affected by inlet 

NOx levels. 

b

 - Calculated from Mobotec proposal information and No. 6 fuel oil baseline NOx. Estimated percent reduction 

for PNG from proposal and applied to fuel oil No. 6 

c

 - From Coen and Fuel Tech Proposal, a 25 percent reduction of LNB emission rate

d – NVEBL – Based on Coen information for LNB and FGR. 

3.2.1.4 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 emission rates; however, they 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. Also, emission rates are typically based on a 

design average value (i.e., 30-day rolling average) versus a maximum 24-hour value. The 

following subsections describe the control technologies and the control effectiveness 

evaluated in this BART analysis. 

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 natural gas-fired generating units was completed. 

As a result of this review, it was noted that NOx emissions can vary around an average 

emissions level. This variance can be attributed to many reasons, including fuel 

characteristics, unit load, boiler operation including excess air, burner equipment condition, 

and so forth. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-6 

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

follows: 

1. Establish expected NOx emissions value from vendor. 

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

3. Review and evaluate unit physical and operational characteristics and restrictions. The 

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

variant the NOx emissions are. 

4. 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. 

The following subsections describe the control technologies and the control effectiveness 

evaluated in this NOx BART analysis. 

New LNB The mechanism used to lower NOx with LNB is to stage the combustion process 

and provide a fuel rich condition initially; this is so oxygen needed for combustion is not 

diverted to combine with nitrogen and form NOx. Fuel-rich conditions favor the conversion 

of fuel nitrogen to N2 instead of NOx. LNB is considered to be a capital cost, combustion 

technology retrofit that may require water wall tube replacement. 

FGR. Flue Gas Recirculation (FGR) generally extracts flue gas from downstream of the 

economizer or air heater, and is mixed into the combustion air duct. This recirculation can 

be achieved with a new FGR fan, or by using the existing forced draft (FD) fan to inject the 

flue gas into the combustion air (induced flue gas recirculation). FGR adds oxygen-lean 

heat-absorbing mass to the combustion air, thus lowering the combustion temperature and 

reducing NOx emissions. 

Neural Net Controls. Information regarding neural net controls was received from NeuCo, 

Inc. While NeuCo offers several neural net products, CombustionOpt and SootOpt provide 

the potential for NOx reduction. NeuCo stated these products can be utilized on most 

control systems, and can be effective even in conjunction with other NOx reduction 

technologies. NeuCo predicts that CombustionOpt can reduce NOx by 15 percent, and 

SootOpt can provide an additional 5 to 10 percent. Because NeuCo does not offer guarantees 

on this projected emission reduction, a nominal reduction of 15 percent was assumed for 

evaluation purposes. The budgetary price for CombustionOpt and SootOpt were $150,000 

and $175,000, respectively, with an additional $200,000 for a process link to the unit control 

system. Because NeuCo does not guarantee NOx reduction, the estimated emission 

reduction levels provided cannot be considered as reliable projections. Therefore, neural net 

should be considered as a supplementary or “polishing” technology, but not on a “standalone” basis. 

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

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

nozzles. Rotation is reported to prevent laminar flow, so that the entire volume of the 

furnace can be used more effectively for the combustion process. In addition, the swirling 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-7 

action reduces the maximum temperature of the flames and increases heat absorption. The 

combustion air is also mixed more effectively”. A typical ROFA installation will have a 

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

propose one 320 horsepower (hp) fan for Tracy 3. 

Mobotec’s budgetary proposals included expected NOx emission rates for PNG and No. 2 

and No. 6 fuel oils, and are presented in Table 3-2 above. While a typical installation does 

not require changes to the existing LNB system, , results of computational fluid dynamics 

modeling will determine the quantity and location of new ROFA ports. Although not 

specifically identified, Mobotec generally includes bent tube assemblies for ROFA port 

installation if required. Mobotec does not provide installation services, because they believe 

that the owner can more cost effectively contract for these services. However, they do 

provide one onsite construction supervisor during installation and startup. 

Due to previous experience with ROFA, NVE does not consider ROFA as a stand-alone 

technology option. 

ROFA w/Rotamix. As described above, ROFA is marketed as an improved OFA system.

Rotamix is Mobotec’s technology for adding selective non-catalytic reduction using an 

ammonia or urea based reagent. 

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

reductions on smaller units. With SNCR, an amine-based reagent such as ammonia – or 

more commonly urea – is injected into the furnace within a temperature range of 1,600 

degrees Fahrenheit (°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 downstream. The ammonia may react with sulfur to foul heat exchange 

surfaces and/or create a visible stack plume. Reagent utilization can have an 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. A budgetary proposal 

was received from Fuel Tech. 

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

promote the chemical reaction. Ammonia is injected into the flue-gas stream, where it 

reduces NOx to nitrogen and water. Unlike the high temperatures required for SNCR, in 

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

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

efficient than SNCR and results in lower NOx emissions. The most common type of SCR is 

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

economizer and upstream of the air heater and any particulate control equipment. In this 

location, the SCR is exposed to the full concentration of any particulate in the flue gas that 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-8 

leaves the boiler. 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. Because of the higher removal rate, a full-scale SCR was 

used as the basis for analysis at Tracy 2. From previous SCR design experience, a projected 

NOx emission rate of 0.07 lb/MMBtu is projected for all emissions control equipment 

scenarios assuming current equipment can meet retrofit requirements. 

3.2.1.5 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. The installation of LNB is not expected to greatly impact the boiler 

efficiency or FD fan power usage. Therefore, these technologies will not have energy 

impacts. 

The Mobotec ROFA system requires installation and operation of one 320 hp ROFA fan 

(239 kilowatts [kW] total). An estimated auxiliary power requirement for an SNCR system 

for a nominal 83-MW unit is estimated at 83 kW. The same estimate was used for Rotamix. 

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

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

The energy impacts summarized above are included in the economic analysis presented in 

Appendix A. 

Environmental Impacts. SNCR, Rotamix, and SCR installation 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. 

These environmental impacts have not been quantified in the economic analysis presented 

in Appendix A. 

Economic Impacts. Costs and emissions estimates for LNB, LNB w/FGR, SNCR, and SCR 

were obtained from equipment vendors. Costs for the ROFA and Rotamix systems were 

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 in Figure 3-1. 

The capital costs shown in Table 3-3 are applicable for all of the fuels under consideration. 

For example, if LNB are installed for PNG, the burner costs include the capability to burn 

both PNG and No. 2 and 6 fuel oils (with only minor equipment changes, atomization 

changes, and burner control revisions). Similarly, the cost information for any of the NOx

reduction technologies listed in Table 3-3 will apply for the fuel alternatives under 

consideration. 

The complete Economic Analysis is contained in Appendix A. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-9 

3.2.1.6 Step 5: Evaluate Visibility Impacts 

Please see Section 4.0, BART Modeling Analysis. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 3-10 

TABLE 3-3 NOx Control Cost Comparison using Fuel Oil #6 Tracy Unit 3 

Factor LNB 

LNB w/ 

FGR 

LNB 

w/SNCR 

ROFA 

w/Rotamix LN

Total Installed Capital Costs $704,000 $1,184,000 $2,532,500b $5,250,940a $28Total Installed Capital Costs with Additional Owner Costs $1,232,000 $2,072,000 $4,431,875 $9,189,145 $35Total First Year Fixed & Variable O&M Costs $45,200 $354,865 $236,432 $548,326 $5Total First Year Annualized Cost $175,861 $574,613 $706,459 $1,522,890 $4Power Consumption (MW) - 1.13 0.11 1.24 Annual Power Usage (Million kW-Hr/Yr) - 5.7 0.6 6.3 NOx Design Control Efficiency 16.4% 28.8% 37.3% 45.2% 7

Tons NOx Removed per Year 155 272 352 427 First Year Ave Control Cost ($/Ton NOx Removed) 1,136 2,115 2,007 3,570 

Incremental Control Cost ($/Ton NOx Removed) 1,136 3,412 1,641 10,959 

a Based on 75/25 installation cost split between ROFA and Rotamix b Fuel Tech equipment estimate plus 50 percent installation cost 
DEN/ES072007003/TRACY_3_10-03-08.DOC 3-11 FIGURE 3-1 First Year Control Cost for NOX Air Pollution Control Options Tracy Unit 3 

First Year NOx Control Cost

0

2,0004,0006,0008,000

10,00012,000

LNB LNB w/ FGR LNB w/SNCR ROFA w/Rotamix 

Air Pollution Control Option

First Year Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-12 

3.2.2 BART SO2 Analysis 

SO2 forms in the boiler during the combustion process, and is primarily dependent on 

natural gas and fuel oil sulfur content. The BART analysis for SO2 emissions on Tracy 3 is 

described below. The analysis completed in Section 3.2 is for the case when burning No. 6 

fuel oil. 

However, the EPA BART guidelines require that oil-fired units consider limiting the sulfur 

content of the fuel oil burned. Because current requirements for low sulfur diesel fuel limits 

sulfur content to 0.05 percent, fuel switching will be analyzed as an SO2 option for this 

study. A flue gas desulphurization system (a spray dryer absorber) with similar SO2

reduction capability as the fuel switch option will be considered. It should be noted that the 

Nevada Public Utilities Commission has mandated that the Tracy units have both PNG and 

fuel oil capability. 

3.2.2.1 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 Tracy 3; this included control 

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

The following potential SO2 control technology options were considered: 

• Use of low sulfur distillate oil (No. 2 fuel oil) 

• Spray Dryer Absorber (SDA) 

3.2.2.2 Step 2: Eliminate Technically Infeasible Options 

Technical feasibility will primarily be determined by fuel storage delivery constraints, boiler 

configuration, and on the ability of low sulfur fuel oil to achieve SO2 emissions reduction. 

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

TABLE 3-4 

Control Technology Options Evaluated 

Tracy Unit 3 

Technology 

Estimated SO2 

Removal Efficiency 

(%) 

Estimated Emission 

Rate 

(lb/MMBtu) 

Current Title V Permit Limitation 

(converted to lb/MMBtu for 

comparison) 

N/A 0.76 

NVE BART Limit 

(Low Sulfur No. 2 Fuel Oil) 

93% 0.05 

(24-hr average) 

Spray Dryer Absorber 90% 0.10 

PNG 99% 0.0006 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-13 

3.2.2.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

When evaluating the control effectiveness of SO2 reduction technologies, each option can be 

compared to the proposed NVE BART Limit. With a fuel switch to low sulfur diesel, the 

expected SO2 emissions are estimated at this level. While an SDA is estimated to achieve 

approximately a 90 percent reduction in SO2, with an anticipated emission rate of 

0.10 lb/MMBtu. Because Tracy 3 is not currently capable of burning 100% No. 2 fuel oil, 

capital improvements would be required. 

The following describe the control technologies and the control effectiveness evaluated in 

this BART analysis. 

Use of low sulfur distillate oil (No. 2 fuel oil) 

This alternative entails the use of a low sulfur (0.05 % sulfur) diesel in lieu of No. 6 fuel oil. 

Spray Dryer Absorber (SDA) 

A spray dryer absorber 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. For Tracy 

3, this dry particulate matter would be captured downstream in a baghouse which would be 

required in conjunction with the SDA. A lime spray dryer system typically produces a dry 

waste product suitable for landfill disposal. Emissions from an SDA are estimated to meet 

an emissions level of 0.10 lb/MMBtu. 

3.2.2.4 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. There is no energy impact associated with switching to low sulfur diesel 

fuel, however additional system pressure drop will result from an installation of an SDA. 

No energy impact costs are included in the economic analysis presented in Appendix A. 

Environmental Impacts. There is no environmental impact associated with switching to low 

sulfur diesel fuel or installation of an SDA. 

No environmental impact costs have been quantified in the economic analysis presented in 

Appendix A.

Economic Impacts. A summary of the costs and amount of SO2 removed for fuel switching is 

provided in Table 3-5. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-14 

TABLE 3-5 

SO2 Control Cost 

Tracy Unit 3 

Factor 

Spray Dryer 

Absorber 

Switch to Low 

Sulfur Fuel 

Total Installed Capital Costs $22,000,000 $500,000a

Total First Year Fixed & Variable Operations & 

Maintenance Costs $544,154 - 

Total First Year Annualized Cost $2,877,386 - 

Power Consumption (MW) 0.40 - 

Annual Power Usage (kW-Hr/Yr) 2.0 - 

SO2 Design Control Efficiency 84.8% 93% 

Tons SO2 Removed per Year 1,633 - 

First Year Average Control Cost ($/Ton of SO2 Removed) 1,762 - 

Incremental Control Cost ($/Ton of SO2 Removed) 1,762 - 

a

 Per unit cost based on Zachry study for fuel switch to No. 2 fuel oil for Tracy Station. Does not include 

fuel cost differential. 

The complete Economic Analysis is contained in Appendix A.

3.2.2.5 Step 5: Evaluate Visibility Impacts 

Please see Section 4.0, BART Modeling Analysis. 

3.2.3 BART PM10 Analysis 

Tracy 3 currently is not equipped with a PM10 control device. The BART analysis for PM10

emissions at Tracy 2 is described below. From the analysis completed in Section 3.2, a PM10

BART analysis will only be completed for the case when Tracy 3 burns 100 percent No. 6 

fuel oil. The current baseline PM10 emissions, while burning PNG or No. 2 fuel oil, already 

meets the BACT emissions level. 

3.2.3.1 Step 1: Identify All Available Retrofit Control Technologies 

The following retrofit control technologies have been identified for additional PM10 control: 

• Use of low sulfur fuel oil (No. 2 fuel oil) and LNB 

• Dry Electrostatic Precipitator 

• Wet Electrostatic Precipitator 

• Fabric filter 

3.2.3.2 Step 2: Eliminate Technically Infeasible Options 

Low Sulfur Distillate Oil andLNB. PM10 emissions would be reduced with the switching of fuel 

oil grades from No. 6 to No. 2 and the utilization of LNB. PM10 emissions while burning No. 

2 fuel oil are estimated to meet the NVE BART Limit of 0.03 lb/MMBtu. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-15 

Dry Electrostatic Precipitator. A dry ESP operates by first placing a charge on the particulates 

though a series of electrodes, and then capturing the charged particulates on collection 

plates. While an ESP can be designed for high-particulate removal, operation is susceptible 

to particle resistivity, which denotes a collected particle’s ability to ultimately discharge to 

the collection plate. Low-resistivity particles can be easily charged but may quickly lose 

their charge at the collection plate and tend to be re-entrained into the flue gas stream. 

Higher resistivity particles may form a “back corona,” which is caused by a layer of nonconductive particles being formed on the collection plate. Back corona may prevent other 

charged gas stream particles from migrating to the collection plate. Particle resistivity is also 

influenced by flue gas temperature. ESP sizing is in large part determined by particulate 

size, with larger ESP size required when smaller particulates are expected. In addition, the 

particulates from an oil-fired unit tend to be small and sticky, and if an SDA is utilized for 

SO2 reduction, there will be a greatly increased inlet particulate loading to the ESP. 

Because of the uncertainty in chemical and physical characteristics of the oil-fired 

particulate, and the increased loading from a SDA, a dry ESP is not a good technological 

match for Tracy 3. 

Wet Electrostatic Precipitator. While wet ESP operation is similar to the dry ESP through the 

charging and collection of flue gas particulates, the wet technology has advantages. The wet 

ESP is not sensitive to particulate resistivity and can accommodate changes in particulate 

loading more easily than a dry ESP. Collection plates can be fabricated from metal or fabric, 

and the collected particulate is washed off the plates with water. 

Wet ESPs have successfully been demonstrated on similar oil particulate or chemical mist 

applications. However, flue gas leaving the wet ESP will be saturated and may result in a 

visual steam plume exiting the stack. The wet ESP will utilize water to collect and remove 

the particulates, and will produce a wastewater byproduct. 

While the wet ESP PM10 emission level is estimated to be similar to a fabric filter without 

SDA operation, increased particulate loading from an SDA may not allow a wet ESP to meet 

required collection efficiency. Therefore, a wet ESP is not a technically acceptable alternative 

when matched with an SDA. 

Fabric Filter. Fabric filter technology achieves particulate reduction through the filtration of 

the flue gas through filter bags. The collected particles are periodically removed from the 

bag through a pulse-jet or reverse-flow mechanism. A pulse jet filtration system would 

likely be selected for installation on Tracy 3 because this fabric filter technology results in 

lower capital cost and a smaller required footprint. 

Because of the somewhat sticky particles produced during oil firing, appropriate fabric 

and/or coating bags with a suitable pre-coat material are imperative. If fabric bags become 

“blinded” due to allowing hard-to-removal particulates to become embedded in the fabric 

structure, total bag replacement may be necessary. Blinded bags will continue to provide 

excellent filtration efficiencies; however, the pressure drop across the fabric may exceed 

system draft capability. 

While a fabric filter is not an acceptable alternative for PM10 emissions control for an oilfired unit without utilization of coating material, it is anticipated to function satisfactorily 

with a pre-coat and the increased particulate loading from the SDA operation. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-16 

3.2.3.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

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

TABLE 3-6 

PM10 Control Technology Emission Rates 

Tracy Unit 3 

Control Technology 

Expected PM10 Emission Rate 

 (Lb/MMBtu) 

Current Title V Permit Limit (converted to 

lb/MMBtu for comparison) 

0.20 

(1-hr average) 

NVE BART Limit 

(Switch to No. 2 Fuel Oil w/LNG) 

0.03 

(3-hr average) 

Fabric Filter 0.015 

3.2.3.4 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. No additional energy impact is expected from PM10 reduction as a result of 

new LNB or burning of low sulfur fuel oil. A fabric filter and ductwork will add an 

estimated 6 to 8 inches of H2O pressure drop to the system, and additional electrical load 

requirements for No. 6 fuel oil combustion. 

No energy impact costs are included in the economic analysis presented in Appendix A. 

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

new LNB switching to low sulfur diesel fuel, or utilizing a fabric filter. 

No environmental impact costs have been quantified in the economic analysis presented in 

Appendix A.

Economic Impacts. A summary of the costs and PM10 removed for the alternatives are 

recorded in Table 3-7. The complete Economic Analysis is contained in Appendix A. 
3.0 BART ENGINEERING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 3-17 

TABLE 3-7 

PM10 Control Cost Comparison 

Tracy Unit 3 

Factor Fabric Filter 

Switch to Low 

Sulfur Fuel 

Total Installed Capital Costs $22,000,000 $500,000 

Total First Year Fixed & Variable O&M Costs $344,816 - 

Total First Year Annualized Cost $2,678,048 - 

Power Consumption (MW) 0.40 - 

Annual Power Usage (Million kW-Hr/Yr) 2.0 - 

PM10 Design Control Efficiency 76.9% - 

Tons PM10 Removed per Year 145 - 

First Year Ave Control Cost ($/Ton PM10

Removed) 18,407 - 

Incremental Control Cost ($/Ton PM10

Removed) 18,407 - 

The complete Economic Analysis is contained in Appendix A.

3.2.3.5 Step 5: Evaluate Visibility Impacts 

Please see Section 4.0, BART Modeling Analysis. 

3.3 Summary 

The most cost-effective emissions control scenario includes the utilization of LNB with PNG 

and/or low-sulfur No. 2 fuel oil. The Nevada Public Utilities Commission has mandated 

that Tracy Unit 3 maintain the capability to use both PNG and fuel oil. However, as a first 

step in the BART implementation plan, NV Energy has committed to use only low-sulfur 

No. 2 fuel oil. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 4-1 

4.0 BART Modeling Analysis 

4.1 Introduction 

This section presents the dispersion modeling methods and results for estimating the degree 

of visibility improvement from BART control technology options for the NV Energy Tracy 

Power Plant Unit 3. 

To a large extent, the modeling followed the methodology outlined in the Western Regional 

Air Partnership (WRAP) protocol for performing BART analyses (WRAP, 2006). Any 

proposed deviations from that methodology are documented in the modeling protocol that 

is included as Appendix B to this report. 

4.2 Model Selection 

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

assess the visibility impacts at Class I areas. Work groups that represent the interests of the 

Federal Land Managers (FLM) recommend that an analysis of Class I area air quality and air 

quality related values (AQRVs) be performed for major sources located more than 50 km 

from these areas (EPA, 1998). The CALPUFF model is routinely recommended for these 

types of regulatory analyses. 

The CALPUFF modeling system includes the meteorological data preprocessing program 

for CALPUFF (CALMET) 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. 

CH2M HILL used the latest version (Version 6) of the CALPUFF modeling system 

preprocessors and models in lieu of the EPA-approved versions (Version 5). The FLMs and 

others have noted that the EPA-approved Version 5 contained errors and that a newer 

version should be used. Consequently, it was decided to use the latest (as of April 2006) 

version of the CALPUFF modeling system (available at www.src.com): 

• CALMET Version 6.211 Level 060414 

• CALPUFF Version 6.112 Level 060412 

CALMET, CALPUFF, CALPOST, and POSTUTIL were recompiled with the Lahey/Fujitsu 

Fortran 95 Compiler (Release 7.10.02) to accommodate the large CALMET domain. The 

recompiled processors were tested against the test case results provided with the source 

code (TRC, 2007), and the difference between the results was 0.03 percent. 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-2 

4.3 CALMET Methodology 

4.3.1 Dimensions of the Modeling Domain 

CH2M HILL defined domains for Mesoscale Meteorological Model, Version 5 (MM5), 

CALMET, and CALPUFF that were slightly different than those established for the Nevada 

BART modeling in WRAP (2006). In addition, the CALMET and CALPUFF Lambert 

Conformal Conic (LCC) map projection is based on a central meridian of 117° W rather than 

97° W. This puts the central meridian near the center of the domain. 

CH2M HILL used the CALMET model to generate three-dimensional wind fields and other 

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

domain has been defined to allow for at least a 50-km buffer around all Class I areas within 

300 km of the Tracy Power Plant. Grid resolution for this domain was 4 km. Figure 4-1 

shows the extent of the modeling domain. 

The technical options recommended in WRAP (2006) were used for CALMET. Vertical 

resolution of the wind field included 11 layers, with vertical cell face heights as follows (in 

meters): 

• 0, 20, 100, 200, 350, 500, 750, 1000, 2000, 3000, 4000, 5000 

Also, following WRAP (2006), ZIMAX were set to 4,500 meters based on the Colorado 

Department of Health and Environment (CDPHE) analyses of soundings for summer ozone 

events in the Denver area (CDPHE, 2005). The CDPHE analysis suggests mixing heights in 

the Denver area are often well above the CALMET default value of 3,000 meters during the 

summer. For example, on some summer days, ozone levels are elevated all the way to 

6,000 meters mean sea level (MSL) or beyond during some meteorological regimes, 

including some regimes associated with high-ozone episodes. It is assumed that, as in 

Denver, mixing heights in excess of the 3,000 m AGL CALMET default maximum would 

occur in the domain used for this analysis. 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-3 

FIGURE 4-1 

Tracy Power Plant, CALMET/CALPUFF Domain 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-4 

Table 4-1 lists the key user-specified options. 

TABLE 4-1 

User-Specified CALMET Options 

Tracy Unit 3 

Description CALMET Input Parameter Value 

CALMET Input Group 2 

Map projection PMAP Lambert Conformal Conic (LCC) 

Grid spacing DGRIDKM 4 

Number vertical layers NZ 11 

Top of lowest layer (m) 20 

Top of highest layer (m) 5000 

CALMET Input Group 4 

Observation mode NOOBS 1 

CALMET Input Group 5 

Prognostic or MM-FDDA data 

switch 

IPROG 14 

Max surface over-land 

extrapolation radius (km) 

RMAX1 50 

Max aloft over-land extrapolations 

radius (km) 

RMAX2 100 

Radius of influence of terrain 

features (km) 

TERRAD 10 

Relative weight at surface of Step 1 

field and obs 

R1 100 

Relative weight aloft of Step 1 field 

and obs 

R2 200 

CALMET Input Group 6 

Maximum over-land mixing height 

(m) 

ZIMAX 4500 

4.3.2 CALMET Input Data 

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

CH2M HILL used MM5 data as the basis for the CALMET wind fields. The horizontal 

resolution of the MM5 data is 36 km. 

For 2001, CH2M HILL used MM5 data at 36-km resolution that were obtained from the 

contractor (Alpine Geophysics) who developed the nationwide data for the EPA. For 2002, 

CH2M HILL used 36-km MM5 data obtained from Alpine Geophysics, originally developed 

for the WRAP. Data for 2003 (also from Alpine Geophysics), at 36-km resolution, were 

developed by the Wisconsin Department of Natural Resources, the Illinois Environmental 

Protection Agency, and the Lake Michigan Air Directors Consortium (Midwest RPO). 

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

guess field was adjusted by CALMET for local terrain and land use effects to generate a 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-5 

Step 1 wind field, and then further refined using local surface observations to create a final 

Step 2 wind field. 

Surface data for 2001-2003 were obtained from the National Climatic Data Center (NCDC). 

CH2M HILL processed data for all stations from the National Weather Service’s (NWS) 

Automated Surface Observing System (ASOS) network that are in the domain. The surface 

data were obtained in abbreviated DATSAV3 format. A conversion routine available from 

the TRC website was used to convert the DATSAV3 files to CD 144 format for input to 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 (CTG) format from the USGS, and the Level I 

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

Surface properties, such as albedo, Bowen ratio, roughness length, and leaf area index, were 

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

Elevation Model (DEM) data, which are primarily derived from USGS 1:250,000 scale 

topographic maps. Missing land use data were filled with a value that is appropriate for the 

missing area. 

Precipitation data were ordered from the NCDC. All available data in fixed-length, TD-3240 

format were ordered for the modeling domain. The list of available stations and 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. 

Following the methodology recommended in WRAP (2006), no observed upper-air 

meteorological observations were used as they are redundant to the MM5 data and may 

introduce spurious artifacts in the wind fields. In the development of the MM5 data, the 

twice daily upper-air meteorological observations were used as input with the MM5 model. 

The MM5 estimates were nudged to the upper-air observations as part of the Four 

Dimensional Data Assimilation (FDDA). This results in higher temporal (hourly vs. 12 hour) 

and spatial (36 km vs. ~300 km) resolution for the upper-air meteorology in the MM5 field. 

These MM5 data are more dynamically balanced than those contained in the upper-air 

observations. Therefore, the use of the upper-air observations with CALMET is not needed, 

and, in fact, will upset the dynamic balance of the meteorological fields potentially 

producing spurious vertical velocities. 

4.3.3 Validation of CALMET Wind Field 

CH2M HILL used the CalDESK (program to display data and results) data display and 

analysis system (v2.97, Enviromodeling Ltda.) to view plots of wind vectors and other 

meteorological parameters to evaluate the CALMET wind fields. We used observed weather 

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

and Atmospheric Administration (NOAA) Central Library U.S. Daily Weather Maps Project 

(http://docs.lib.noaa.gov/rescue/dwm/data_rescue_daily_weather_maps.html), to 

compare to the CalDESK displays. 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-6 

4.4 CALPUFF Methodology 

4.4.1 CALPUFF Modeling 

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

the CALPUFF modeling domain (Figure 4-1). 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. 

4.4.1.1 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 used the hourly ozone data generated for the WRAP BART analysis 

for 2001, 2002, and 2003. 

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

default value of 80 parts per billion (ppb). Background ammonia was set to 1 ppb as 

recommended in WRAP (2006). 

4.4.1.2 Stack Parameters 

The baseline stack parameters for the baseline and post-control scenarios were the same as 

those used the WRAP Regional Modeling Center (RMC) analyses. None of the emission 

controls included in this BART analysis would greatly affect the exhaust exit flows or 

temperatures. 

4.4.1.3 Pre-Control Emission Rates 

Pre-control emission rates reflect normal maximum capacity 24-hour 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 BART Determinations; Final Rule (40 CFR Part 51; July 6, 2005, 

pg 39129): 

“The emissions estimates used in the models are intended to reflect steady-state operating 

conditions during periods of high-capacity utilization. We do not generally recommend that 

emissions reflecting periods of start-up, shutdown, and malfunction be used...” 

CH2M HILL selected the emissions rates used in the WRAP RMC modeling as the Precontrol (baseline) emission rates. The WRAP PM10 and SO2 were speciated to determine 

emission rates for coarse particulate, fine particulate, elemental carbon, organic aerosols, 

and sulfates. 

Emissions were modeled for the following species: 

• Sulfur dioxide (SO2) 

• Nitrogen oxides (NOx) 

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

• Fine particulate (diameter ≤ PM2.5) 

• Elemental carbon (EC) 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-7 

• Organic aerosols (SOA) 

• Sulfates (SO4) 

4.4.1.4 Post-control Emission Rates 

Post-control emission rates represent the NVE BART Limit emission levels presented in 

Table 5-1, with the exception of the NOx emission rate which is in excess of the NVEBL. 

4.4.1.5 Modeling Process 

The CALPUFF modeling for the control technology options followed this sequence: 

• Model WRAP-RMC parameters to verify results 

• Model Title V Permit Limits 

• Model Scenario 1 (NVE BART Limit) emissions, with the exception of the NOx emission 

rate which is in excess of the NVEBL. 

• Determine the degree of visibility improvement 

4.4.2 Receptor Grids and Coordinate Conversion 

The TRC COORDS program was used to convert the latitude/longitude coordinates to LCC 

coordinates for the meteorological stations and source locations. The USGS conversion 

program PROJ (version 4.4.6) was used to convert the National Park Service (NPS) receptor 

location data from latitude/longitude to LCC. 

For the Class I areas that are within 300 km of the Tracy Power Plant, discrete receptors for 

the CALPUFF modeling were taken from the NPS database for Class I area modeling 

receptors. The entire area of each Class I area that is within or intersects the 300-km circle 

(Figure 3-1) were included in the modeling analysis. The following Class I areas were 

modeled for the Tracy facility: 

• Ansel Adams Wilderness (Minarets Wilderness) (anad) 

• Caribou Wilderness (cari) 

• Desolation Wilderness (deso) 

• Emigrant Wilderness (emig) 

• Hoover Wilderness (hoov) 

• John Muir Wilderness (jomu) 

• Kaiser Wilderness (kais) 

• Kings Canyon NP (kica) 

• Lava Beds NM (labe) 

• Lassen Volcanic NP (lavo) 

• Mokelumne Wilderness (moke) 

• South Warner Wilderness (sowa) 

• Thousand Lakes Wilderness (thla) 

• Yolla Boly Middle Eel Wilderness (yobo) 

• Yosemite NP (yose) 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-8 

4.5 Visibility Post-processing 

4.5.1 CALPOST 

The CALPOST processor was used to determine 24-hour average visibility results. Output is 

specified in deciview (dv) units. 

Calculations of light extinction were made for each pollutant modeled. The sum of all 

extinction values was used to calculate the delta-dv (∆dv) change relative to natural 

background. Default extinction coefficients for each species, as shown below, were used: 

• Ammonium sulfate 3.0 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

CALPOST visibility Method 6 (MVISBK=6) was used for the determination of visibility 

impacts. Monthly average relative humidity factors [f(RH)] were used in the light extinction 

calculations to account for the hygroscopic characteristic of sulfate and nitrate particles. 

Monthly f(RH) values, from the WRAP_RMC BART modeling, were used in CALPOST for 

the particular Class I area being modeled. 

The natural background conditions used in the post-processing to determine the change in 

visual range background - or delta-deciview (∆dv) - represent the average natural 

background concentration for western Class I areas. 

Table 4-2 lists the annual average species concentrations from the EPA Guidance. 

TABLE 4-2 

Average Natural Levels of Aerosol Components 

Tracy Unit 3 

Aerosol Component 

Average Natural Concentration 

(μg/m3) for Western Class I Areas 

Ammonium Sulfate 0.12 

Ammonium Nitrate 0.10 

Organic Carbon 0.47 

Elemental Carbon 0.02 

Soil 0.50 

Coarse Mass 3.0 

Note: Taken from Table 2-1 of Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. EPA454/B-03-005, September 2003. 

4.6 Results 

Input and output files for the CALMET/CALPUFF modeling and post-processing will be 

provided upon request. 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-9 

4.6.1 WRAP Verification Runs Results 

Tables 4-3 and 4-4 present the results of WRAP-RMC model verification runs. The results 

show good correlation in estimated maximum ∆dv. Much of the difference between these 

values is probably attributed to the different alignment of the LCC grids (reference 

discussion in Section 4.3.1). 

TABLE 4-3 

Results from WRAP-RMC CALPUFF Modeling for Tracy 1-3 (WRAP 2007) 

Tracy 3 

98th Percentile ∆dv for Each Year 

Class I 

Area 

Min 

Distance 

(km) 

Max 

Delta 

∆dv 

98th

Percentile 

∆dv 

Days > 0.5 

∆dv 2001 2002 2003 

98th

∆dv 

3-year 

Avg 

deso 81 2.33 0.83 47 0.83 1.20 0.64 0.89 

moke 101 2.27 0.60 32 0.47 0.88 0.51 0.62 

emig 138 1.39 0.35 10 0.22 0.49 0.27 0.33 

hoov 142 1.46 0.33 11 0.23 0.52 0.25 0.33 

yose 153 1.42 0.38 11 0.25 0.50 0.28 0.34 

cari 170 2.00 0.92 48 0.94 1.03 0.69 0.89 

lavo 175 1.99 0.80 44 0.75 0.94 0.71 0.80 

anad 182 1.46 0.26 8 0.26 0.43 0.23 0.31 

sowa 189 3.68 0.87 62 0.83 0.85 0.99 0.89 

thla 209 1.27 0.54 22 0.43 0.46 0.54 0.48 

jomu 221 1.13 0.27 6 0.23 0.32 0.23 0.26 

kais 249 0.77 0.18 5 0.16 0.21 0.16 0.18 

kica 265 1.22 0.20 2 0.20 0.26 0.18 0.21 

labe 286 1.26 0.54 25 0.74 0.34 0.54 0.54 
4.0 BART MODELING ANALYSIS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 4-10 

TABLE 4-4 

Verification CALPUFF Modeling Results 

Tracy Unit 3 

98th Percentile ∆dv for Each Year 

Class I 

Area 

Min 

Distance 

(km) 

Max 

Delta 

∆dv 

98th

Percentile 

∆dv 

Days > 0.5 

∆dv 2001 2002 2003 

98th

∆dv 

3-year 

Avg 

deso 81 3.58 0.99 38 0.65 1.08 1.04 0.92 

moke 101 2.46 0.84 23 0.80 0.87 0.86 0.84 

emig 139 1.75 0.51 9 0.56 0.46 0.49 0.51 

hoov 143 1.76 0.53 10 0.53 0.59 0.43 0.52 

yose 153 1.62 0.52 11 0.54 0.51 0.43 0.49 

cari 171 2.31 1.12 23 1.09 0.80 1.12 1.00 

lavo 176 2.34 1.12 24 1.15 0.82 1.12 1.03 

anad 182 1.29 0.37 6 0.35 0.45 0.32 0.38 

sowa 190 2.67 0.91 22 0.96 0.91 0.86 0.91 

thla 210 1.44 0.68 12 0.63 0.67 0.82 0.71 

jomu 221 1.01 0.41 7 0.37 0.46 0.39 0.41 

kais 249 0.82 0.30 1 0.30 0.32 0.28 0.30 

kica 265 0.88 0.40 5 0.40 0.37 0.38 0.38 

labe 286 1.09 0.49 9 0.52 0.35 0.46 0.45 

yobo 287 1.26 0.35 4 0.23 0.45 0.32 0.33 

4.6.2 BART Modeling Analysis 

The results and comparisons of the CALPUFF modeling for the baseline emission rates and 

those for the NVE BART Limit emission rates are provided in Section 5. As previously 

mentioned, the NOx emission rate modeled is in excess of the NVEBL. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 5-1 

5.0 BART Analysis and Recommendations 

5.1 Recommended BART Controls 

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

modeling analysis for Tracy 3, the recommended BART controls include installing LNB for 

NOx and utilizing PNG and/or low-sulfur No. 2 fuel oil for SO2 and PM10 emissions 

reduction. There are no presumptive limits assigned by the United States Environmental 

Protection Agency (EPA) for wall-fired boilers burning PNG or fuel oil. In the absence of a 

specific Federal guidance, Nevada has chosen to establish the NVEBL based on the control 

technology that meets the BART guidelines for each specific unit. 

Table 5-1 compares the WRAP baseline control scenario with the Title V Permit Limit and 

expected emission levels utilizing the NVE BART Limit emission levels. While the NOx

emission rate modeled is in excess of the current NVEBL, modeling results represent worst 

case visibility impacts. Because of the basis utilized to establish the estimated emissions rate 

for each of these cases, it is important to consider economic and dispersion modeling results 

for each scenario in making the overall BART recommendation. 

The WRAP baseline represents a snap-shot view of emissions based upon the year 2006, and 

does not necessarily represent worst case potential emission rates. The Title V permit limit 

offers a more representative view of maximum potential emission rates, since these are 

enforceable operating limits. Comparison of dispersion modeling results for the three 

scenarios are presented below. 

TABLE 5-1 

Modeled Emission Control Scenarios 

Tracy Unit 3 

CASE 

Estimated NOx

Emissions 

(lb/MMBtu) 

Estimated SO2

Emissions 

(lb/MMBtu) 

Estimated PM10

Emissions 

(lb/MMBtu) 

WRAP Baseline 0.315 0.540 0.053 

Title V Emission Limit Baseline 0.45 0.76 0.20 

Scenario 1 – NVE BART Limit 0.40a 0.05 0.03 

a – NOx emission rate higher than NVEBL 

The ranking of the different NOx emission control scenarios based on annual costs, from 

lowest to highest cost, is presented on Table 5-2. 
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-2 

TABLE 5-2 

Ranking of NOx Control Scenarios by Cost 

Tracy Unit 3

Rank Scenario Total Annual Cost 

1 LNB $175,861 

2 LNB w/FGR $574,613 

3 New LNB with SNCR $706,459 

4 ROFA with Rotamix $1,522,890 

5 New LNB and SCR $4,397,281 

5.2 Dispersion Modeling Results 

The results of the dispersion modeling are shown below. In this analysis the WRAP 

emission rates are used as a historical baseline. Table 5-3 compares visibility impacts of the 

WRAP baseline, the current Title V permit limits and the NVEBART Limit emission rates. 

The NVE BART Limit emission rates for Tracy Unit 3 demonstrate an improvement in 

visibility. 

TABLE 5-3 

Comparison of Visibility Impacts by Class I Area 

Tracy Unit 3 

98th Percentile ∆dv Number of Days Exceeding 0.5 ∆dv

Area 

Distance 

(km) 

WRAP 

Baseline 

Title V 

Permit Limit 

NVE BART 

Limit 

WRAP 

Baseline 

Title V 

Permit Limit 

NVE BART 

Limit 

deso 81 0.57 0.78 0.33 13 28 5 

moke 101 0.44 0.61 0.28 6 13 1 

emig 139 0.27 0.37 0.16 2 5 1 

hoov 143 0.25 0.34 0.18 2 5 1 

yose 153 0.26 0.36 0.17 2 3 0 

cari 171 0.51 0.70 0.36 9 12 5 

lavo 176 0.45 0.61 0.28 6 13 1 

anad 182 0.19 0.26 0.095 1 2 0 

sowa 190 0.46 0.62 0.30 8 12 3 

thla 210 0.33 0.45 0.21 6 7 1 

jomu 221 0.21 0.28 0.11 0 4 0 

kais 249 0.15 0.21 0.07 0 1 0 

kica 265 0.20 0.28 0.10 0 1 0 

labe 286 0.24 0.34 0.14 1 4 0 

yobo 287 0.20 0.27 0.07 2 3 0 
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-3 

FIGURE 5-1 

Comparison of 98th Percentile Delta Deciview Visibility Impacts Part 1 

Tracy 3 

Comparison of 98th Percentile Delta Deciview Visibility Impacts

Tracy Unit 3

Part 1

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Desolation W Mokelumne

W

Emigrant W Hoover W Yosemite NP Caribou W Lassen

Volcanic NP

Ansel Adams

W

Class I Area

Delta Deciview

WRAP Basline

Title V Permit Limit

SPR BART Limit
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-4 

FIGURE 5-2 

Comparison of 98th Percentile Delta Deciview Visibility Impacts Part 2 

Tracy 3 

Comparison of 98th Percentile Delta Deciview Visibility Impacts

Tracy Unit 3

Part 2

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

South Warner

W

Thousand

Lakes W

John Muir W Kaiser W Kings Canyon

NP

Lava Beds NM Yolla Bolly

Middle Eel W

Class I Area

Delta Deciview

WRAP Baseline

Title V Permit Limit

SPR BART Limit
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-5 

FIGURE 5-3 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv Part 1 

Tracy 3 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv

Tracy Unit 3

Part 1

0

5

10

15

20

25

30

Desolation W Mokelumne

W

Emigrant W Hoover W Yosemite NP Caribou W Lassen

Volcanic NP

Ansel Adams

W

Class I Area

Days

WRAP Baseline

Title V Permit Limit

SPR BART Limit
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-6 

FIGURE 5-4 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv Part 2 

Tracy 3 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv

Tracy Unit 3

Part 2

0

5

10

15

20

25

30

South Warner

W

Thousand

Lakes W

John Muir W Kaiser W Kings Canyon

NP

Lava Beds NM Yolla Bolly

Middle Eel W

Class I Area

Days

WRAP Baseline

Title V Permit Limt

SPR BART Limit

As shown in Figures 5-1 through 5-4, there is a significant decrease in modeled visibility 

impact when reducing the modeled emission levels from the WRAP and Title V Permit 

values, to the NVEBL emission rates. 

5.2.1 NOx Control Scenario Visibility Modeling 

While visibility modeling has not been completed for the combination of NOx, SO2, and 

PM10 NBEBL values, Tables 5-4 and 5-5 below compare the results for the various NOx

control technologies. Results from two representative Class I areas are provided. 

Based on an evaluation of the cost per ∆dv reduction from Tables 5-4 and 5-5, new LNB is 

selected as BART for Tracy 3. 
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-7 

TABLE 5-4 

NOx Control Scenario Results for Desolation Wilderness

Tracy Unit 3 

Scenario Controls 

Average 

Number 

of Days 

Above 

0.5 ∆dV 

(Days) 

98th 

Percentile 

∆dV 

Reduction 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

∆dV 

Reduction 

(Million$/dV 

Reduced) 

Base 7 0 0 0 

1 New LNB 5 0.032 0.176 5.496 

2 New LNB and FGR 4 0.056 0.575 10.261 

3 

New LNB and 

SNCR 2 0.072 0.706 9.812 

4 ROFA w/Rotamix 2 0.087 1.523 17.504 

5 New LNB and SCR 2 0.15 4.397 29.315 

TABLE 5-5 

NOx Control Scenario Results for Yosemite NP 

Tracy Unit 3 

Scenario Controls 

Average 

Number 

of Days 

Above 

0.5 ∆dV 

(Days) 

98th 

Percentile 

∆dV 

Reduction 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

∆dV 

Reduction 

(Million$/dV 

Reduced) 

Base 2 0 0 0 

1 New LNB 1 0.014 0.176 12.562 

2 New LNB and FGR 1 0.025 0.575 22.985 

3 

New LNB and 

SNCR 1 0.036 0.706 19.624 

4 ROFA w/Rotamix 1 0.04 1.523 38.072 

5 New LNB and SCR 0 0.064 4.397 68.708 
5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/TRACY_3_10-03-08.DOC 5-8 

5.3 Recommendations 

5.3.1 NOx Emission Control 

New LNB has been selected as the NOx reduction technology with an NVEBL of 

0.27 lb/MMBtu averaged on an annual basis. New LNB is based on utilizing enhanced 

combustion to meet the proposed NVE BART Limit. There is significant uncertainty 

involved in obtaining vendor emission guarantees and associated equipment/construction 

costs at this stage of analysis when retrofitting older boiler units. Site specific engineering is 

required on a “unit by unit” basis to determine the most effective control technology. 

5.3.2 SO2 Emission Control 

The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART for Tracy 3 with an NVEBL 

of 0.05 lb/MMBtu averaged on a 24-hour basis. No additional SO2 emission control is 

required. No. 6 fuel oil will no longer be burned at the facility. 

5.3.3 PM10 Emission Control 

The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART for Tracy 3 with an NVEBL 

of 0.03 lb/MMBtu averaged on a 3-hour basis. No additional PM10 emission control is 

required. No. 6 fuel oil will no longer be burned at the facility. 

5.4 Just-Noticeable Differences in Atmospheric Haze 

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

Haze by Dr. Ronald Henry of the University of Southern California state that only dV 

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

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

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

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

Thus the results indicate that even though many millions of dollars will be spent, only 

minimal, if any, noticeable visibility improvements may result. 

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

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

obscure the atmosphere. During the period of 2001 through 2003, there were several megawildfires that lasted for many days and could have had an impact of background visibility 

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

impacts modeled for the Tracy 3 facility, the effect would be to increase the costs per ∆dV 

reduction that are presented in this report. 
DEN/ES072007003/TRACY_3_10-03-08.DOC 6-1 

6.0 References 

40 CFR Part 51. 2005. Regional Haze Regulations and Guidelines for Best Available Retrofit 

Technology Determinations; Final Rule (July 6, pg 39129). 

United States Environmental Protection Agency. 1990. New Source Review Workshop Manual –

Prevention of Significant Deterioration and Nonattainment Area Permitting. October. 

EPA. 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report 

and Recommendations for Modeling Long-Range Transport Impacts. Air Quality Modeling Group 

(MD-14), Research Triangle Park, North Carolina; National Park Service, Air Resources 

Division, Denver, Colorado; USDA Forest Service, Air Program, Fort Collins, Colorado; and 

U.S. Fish and Wildlife Service, Air Quality Branch, Denver, Colorado. December 1998. 

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. 

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

and Waste Management Association 52:1238-1243. October 2002 

Western Regional Air Partnership (WRAP). 2007. Summary of WRAP RMC BART Modeling 

for Nevada, Draft#8. May 14, 2007. 

WRAP. 2006. Draft Final Modeling Protocol, CALMET/CALPUFF Protocol for BART Exemption 

Screening Analysis for Class I Areas in the Western United States. Air Quality Modeling Forum. 

Regional Modeling Center. August 15, 2006. 
Appendices 
APPENDIX A 

Economic Analysis 
APPENDIX B 

BART Protocol