DEN/ES072007003/TRACY_1_10-03-08.DOC 

# BART Analysis for Tracy Unit 1

Prepared For: 

# NV Energy

6100 Neil Road Reno, NV 89520-0024



### Revised Report October 2008

Prepared By:

2285 Corporate Circle Henderson, NV 89074DEN/ES072007003/TRACY_1_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 1 (hereafter referred to as Tracy 1). A BAR T analysis has been conducted for the following criteria pollutants: oxides of nitrogen (NO x ), sulfur dioxide (SO 2 ), and particulate matter less than 10 microns in aerodynamic diamet er (PM 10 ). The Tracy Station consists of three BART eligible units with a tot al nominal generating capacity of 251 megawatts (MW ), and Tracy 1 is a nominal 55 MW unit. The Title V permit allows burning Pipeline Quality Natural Gas (PNG) or No. 2 fuel oil (Tracy 1 is not currently physically configured to allow burning No. 2 fuel oil). BAR T must be implemented within 5 years after the State Implementation Plan (SIP) is approved by the U.S. Environmental Protection Agency (EPA), and a compliance date of 2015 was assumed f or this analysis. In completing the BART analysis, technology alternatives were i nvestigated and potential reductions in NO x , SO 2 , and PM 10 emissions rates were identified during times when the unit is burning 1) 100 percent PNG, and 2) 100 percent No. 2 fuel oil. No . 6 fuel oil was not considered because it is not allowed by the Title V permit . The following technology alternatives were investigated for the PNG and the fuel oil alt ernative, and are listed by pollutant:
NO x emission controls:

• Low NO x Burners (LNB)

• Low NO x Burners (LNB) with Flue Gas Recirculation (FGR)

• Low NO x Burners (LNB) with selective non-catalytic reduction syst em (SNCR)

• Rotating opposed fire air (ROFA) with Rotamix

• LNB with selective catalytic reduction (SCR) system
SO 2 emission controls:

• Use of low sulfur fuel
PM 10 emission controls:

• No PM 10 emissions controls analysis is requiredEXECUTIVE SUMMARY

DEN/ES072007003/TRACY_1_10-03-08.DOC ES-2 

# BART Engineering Analysis
The specific steps in a BART engineering analysis are identifie d 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 c ontrol 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 com pliance
6. The degree of visibility improvement which may reasonably b e 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 c ontrol 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 Technol ogies

• Costs associated with control technologies are summarized in the economic analysis presented in Appendix A. For clarity, Appendix A also inclu des sample economic analysis spreadsheet calculations and explanation of assumption s 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 com pliance Step 5 – Evaluate Visibility Impacts

• The degree of visibility improvement that may reasonably be ant icipated from the use of BART Separate analyses have been conducted for NO x , SO 2 , and PM 10 emissions. All costs included in the BART analyses are in 2007 dollars, and costs have not be en escalated to the assumed 2013 BART implementation date.EXECUTIVE SUMMARY

DEN/ES072007003/TRACY_1_10-03-08.DOC ES-3 

## Establishing Emission Reduction Levels from BART An alysis Results As an integral part of the BART analysis process, cost and expect ed emission information was developed for NO x , SO 2 , and PM 10 . This information is assembled from various sources including emission reduction equipment vendors, NV Energy o perating and engineering data, and internal CH2M HILL historical information. The level of accuracy of the cost estimate can be broadly classifi ed as American Association of Cost Engineers (AACE) Class V or “Order of Magnitude,” which c an be categorized as +50 percent/-30 percent. There are several reasons for selecting t his range of cost estimates to be included in the BART analysis. They are primarily a result of t he difficulty in receiving detailed and accurate information from equipment vendors base d on limited available data provided to the vendors. Because of the active power industr y marketplace, obtaining engineering and construction information is restricted du e to vendor workload. Material and construction labor costs also change rapidly in today’s activ e economy. However, this level of cost estimate precision is adequate for comparison of c ontrol 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 i s exemplified by the difficulty in obtaining background information, and the vendo r time required to develop accurate emission projections for study purposes in comparis on to their response to actual project request for proposals. Also, variance in expected emi ssions can be dependent upon the pollutant under consideration (i.e., particulate emission s can generally be more accurately predicted than NO x emissions). Therefore, when establishing emission limitatio ns in permits, consideration of variability in cost and expected e missions information must be considered. 

# Fuel Characteristics
From the Title V Operating Permit, the primary fuel burned at Tracy 1 will be PNG. The secondary fuel source is No. 2 distillate fuel oil. Only the 100 pe rcent PNG and 100 percent No. 2 fuel oil option will be examined, and no co-firing or blend ed fuel alternatives will be reviewed. The capability to burn No. 6 fuel oil does not currentl y exist, and capital expenditures would be required to allow this fuel option. Th is BART analysis has considered the higher nitrogen content and different co mbustion characteristics of fuel oil as compared to PNG used at Tracy 1, and has evaluated the effect of these qualities on NO x formation and achievable emission rates. The Nevada Public Utilities Commission has mandated that Tracy U nit 1 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-s ulfur No. 2 fuel oil.EXECUTIVE SUMMARY

DEN/ES072007003/TRACY_1_10-03-08.DOC ES-4 

# Recommendations

NO x 

## Emission Control LNB with FGR has been selected as the NO x reduction technology with a NV Energy BART Limit (NVEBL) of 0.25 lb/MMBtu averaged on an annual basis. There is sig nificant uncertainty involved in obtaining vendor emission guarantees and associated equipment/construction costs at this stage of analysis when re trofitting older boiler units. Site specific engineering is required on a “unit by unit” bas is to determine the most effective control technology. The estimated vendor NOx emission rate for LNB with FGR is 0.16 lb/ MMBtu, which was based on burning PNG or No. 2 fuel oil. The BART analysis was comple ted utilizing this emission rate, and the technology selection of LNB and FGR was made accordingly. The BART NO x NVEBL for other similar NVE units burning PNG and fuel oil was determined from a vendor estimate while burning the worst case No. 6 fuel o il. Therefore, due to uncertainties in complying with a permit limit based on prel iminary vendor information, and to be consistent with the basis of selection for other s imilar NVE units, the Tracy 1 NVEBL of 0.25 lb/MMBtu on an annual basis was established. This value is based on the vendor estimate for Tracy 1 while burning No. 6 fuel oil with LNG and FGR.


## SO 2 

## Emission Control The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART fo r Tracy 1 with an NVEBL of 0.05 lb/MMBtu averaged on a 24-hour basis. No additional SO 2 emission control is required.


## PM 10 

## Emission Control The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART fo r Tracy 1 with an NVEBL of 0.03 lb/MMBtu averaged on a 3-hour basis. No additional PM 10 emission control is required.


## Control Recommendation The BART selections include the utilization of LNB with FGR wi th 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 (CALPUF F) modeling system to assess the visibility impacts of emissions from Tracy 1 at Clas s I areas. The Class I areas potentially affected are located more than 50 kilometers, but les s than 300 kilometers, from the Tracy Plant. The Class I areas include the following wilderness areas (WA) and N ational Parks (NP):

• Ansel Adams W A (Minarets Wilderness)

• Caribou W A

• Desolation W AEXECUTIVE SUMMARY

DEN/ES072007003/TRACY_1_10-03-08.DOC ES-5 • Emigrant W A

• Hoover W A

• John Muir W A

• Kaiser W A

• Kings Canyon NP

• Lava Beds NM

• Lassen Volcanic NP

• Mokelumne W A

• South Warner W A

• Thousand Lakes W A

• Yolla Bolly Middle Eel W A

• Yosemite NP Visibility impacts were determined for the 1) WRAP baseli ne, 2) the current Title V emission permit limits, and 3) at an emission rate higher than the propose d NV Energy BART Limits (NVEBL).DEN/ES072007003/TRACY_1_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 R esults ................... ES-3 Fuel Characteristics .......................................................................................................... ES-3 Recommendations............................................................................................................ ES-4 NO x Emission Control ..................................................................................................... ES-4 SO 2 Emission Control....................................................................................................... ES-4 PM 10 Emission Control .................................................................................................... ES-4 Control Recommendation ............................................................................................... ES-4 BART Modeling Analysis................................................................................................ ES-4 Contents ..................................................................................................................................... ii 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 NO x Analysis ...............................................................................................3-3 3.2.2 BART SO 2 Analysis ..............................................................................................3-12 3.2.3 BART PM 10 Analysis ............................................................................................3-14 3.3 Summary................................................................................................................3-14 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 5.1.1 NOx Control Scenario Visibility Modeling.........................................................5-6 5.2 Recommendations..................................................................................................5-8CONTENTS

DEN/ES072007003/TRACY_1_10-03-08.DOC iii 5.2.1 NO x Emission Control ...........................................................................................5-8 5.2.2 PM 10 Emission Control...........................................................................................5-8 5.3 Just-Noticeable Differences in Atmospheric Haze ............................................5-8 6.0 References............................................................................................................................6-1

Appendices A Economic Analysis B BART ProtocolDEN/ES072007003/TRACY_1_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 CALPU FF 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 NO x oxidation of fuel bound nitrogen FGC flue gas conditioning FGD flue gas desulfurization f (RH) relative humidity factors hp horsepower H 2 S 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 unitACRONYMS AND ABBREVIATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC v LNB low-NO x burner LOI loss on ignition MMBtu Million British thermal unit MM5 Mesoscale Meteorological Model, Version 5 MSL mean sea level MW megawatt N 2 nitrogen NDEP Nevada Department of Environmental Protection NO nitric oxide
NO x oxides of nitrogen NP National Park NVE NV Energy NWS National Weather Service
OFA over-fire air O&M operation and maintenance PM 10 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 SO 2 sulfur dioxide SO 3 sulfur trioxide sq. ft. square feet Thermal NO x high temperature fixation of atmospheric nitrogen in combust ion air Tracy 1 Tracy Unit 1 USGS U.S. Geological Survey WA Wilderness AreaDEN/ES072007003/TRACY_1_10-03-08.DOC 1-1 

# 1.0 Introduction

Best Available Retrofit Technology (BART) guidelines wer e established as a result of United States Environmental Protection Agency (EPA) regulations i ntended to reduce the occurrence of regional haze in national parks and other Class I p rotected air quality areas in the United States 1 . These guidelines provide guidance for states when determ ining which facilities must install additional controls, and the type of cont rols 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-impair ing pollutants. The State of Nevada has identified those eligible in-state f acilities that are required to reduce emissions under BART, and will set BART emissions limits fo r those facilities. This information will be included in the State of Nevada State Impleme ntation Plan (SIP), which the State has estimated will be formally submitted to the EPA b y December 1, 2008. The EPA BART guidelines also state that the BART emission limits mus t be fully implemented within 5 years of EPA’s approval of the SIP. There are five basic elements related to BART, when addressing th e issue of emissions for the identified facilities:

• Any existing pollution control technology in use at the sou rce

• 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 b e anticipated from the use of such technology This report documents the BART analysis that was performed on T racy Unit 1 (Tracy 1) by CH2M HILL for NV Energy. The analysis was performed for nitrogen oxides (NO x ), sulfur dioxide (SO 2 ), and particulate matter less than 10 microns in aerodynamic diam eter (PM 10 ), because they are the primary criteria pollutants that affect visib ility 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 model ing methodology and Section 5.0 discusses the BART analysis and recommendations. R eferences are provided in Section 6.0. Appendices A and B provide supporting informati on on the Economic Analysis and BART modeling protocol.

1 40 CFR Part 51: Regional Haze Regulations and Guid elines for Best Available Retrofit Technology (BART ) Determinations; Final Rule. 70 Federal Register, 39103-39172, July 6, 2005.DEN/ES072007003/TRACY_1_10-03-08.DOC 2-1 

# 2.0 Present Unit Operation

Tracy 1 is a nominal 55 megawatts (MW) unit located in Storey County, Nevada. The unit is equipped with a front wall-fired boiler manufactured by Riley Stoker. In accordance with the Title V Operating Permit, the unit can currently be fired u sing 1) pipeline quality natural gas (PNG), 2) No. 2 distillate fuel oil, or 3) co-fired PNG and No. 2 fuel o il. However, even though No. 2 fuel oil is allowed by permit, the unit cannot curren tly burn this fuel without fuel storage, delivery, and burner changes. Tracy 1 began operation in 1963. This analysis is based on a 23-year life for BART control technologies. Assuming a BART implementation date of 2015, this w ill result in an approximate remaining useful life for Tracy 1 of 23 years from the i nstallation date of any BART-related equipment. This report does not attempt to quant ify any additional life extension costs needed to allow the unit at Tracy 1 to operate u ntil 2038. Determining current operating NO x levels before any potential emissions control equipment installation is difficult, especially because higher NO x emissions can be expected at higher unit operating loads. Therefore, PNG current NO x level is approximated by averaging the highest 75 percent load 24-hour NO x emission levels for the year 2006 EPA Acid Rain Database. As a simplifying assumption, No. 2 fuel oil NO x emissions are assumed to be equal to PNG. According to the Title V Operating Permit, No. 6 fue l oil NO x is not an allowable fuel therefore no analysis was completed for this f uel. The SO 2 emissions were also estimated from the EPA Acid Rain Database. PM 10 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 e mission rate from the period modeled for the pre-control scenario. Modeling would then co nsider the expected emissions rate after the installation of BART controls to establish the l evel of visibility improvement. For the pre-control scenario, modeling was conducted at the WRA P 24-hour maximum values and at the Title V permit limits for the unit. The post-con trol scenario was modeled at the proposed NV Energy BART Limits (discussed in Sections 3, 4, and 5), with the exception of the NO x emission rate which is higher than the NVEBL. Table 2-1 lists unit information and emission rates for this analys is.2.0 PRESENT UNIT OPERATION

DEN/ES072007003/TRACY_1_10-03-08.DOC 2-2 TABLE 2-1 Unit Operation and Study Assumptions Tracy Unit 1 General Plant Data Site Elevation (feet above MSL) 4,261 Stack Height (feet) 200 Stack Exit ID (feet) /Exit Area (sq. ft.) 9.0 /63.6 Stack Exit Temperature (°F) 350 Stack Exit Velocity (ft/sec) 69.6 Stack Flow (ACFM) 254,215 Annual Unit Capacity Factor (%) 21 Net Unit Output (Nominal MW) 55 Net Unit Heat Rate (Btu/kW-Hr)(100% load) 13,291 Boiler Heat Input (MMBtu/Hr)(100% load) 731 Type of Boiler Front Wall fired Boiler Fuel PNG or No.2 Fuel Oil NO x Emissions Data (24-hour Average Maximum) Current NO x Controls None: Good combustion practices Title V NO x Permit Limit (lb/MMBtu) 0.63 WRAP NO x Emission Rate (lb/MMBtu) 0.425 NO x Emission Rate (lb/MMBtu) (PNG & No. 2 Fuel Oil) a 0.275 SO 2 Emissions Data (24-hour Average maximum) Current SO 2 Controls None Title V SO 2 Permit Limit (lb/MMBtu) (3-hr average) 0.05 WRAP SO 2 Emission Rate (lb/MMBtu) 0.001 SO 2 Emission Rate (lb/MMBtu) (PNG) a 0.0006 SO 2 Emission Rate (lb/MMBtu) (No.2 Fuel Oil) b 0.051 PM 10 Emissions Data (24-hour Average Maximum) Current PM 10 Controls None Title V PM 10 Permit Limit (lb/MMBtu) (1-hr average) 0.23 WRAP PM 10 Emission Rate (lb/MMBtu) 0.002 PM 10 Emission Rate (lb/MMBtu) (PNG) c 0.008 PM 10 Emission Rate (lb/MMBtu) (No.2 Fuel Oil) b 0.014

a – From CEM data from the year 2006, This time peri od was considered most indicative of the current average emission rate, with significant variances i n emission rates observed in previous years b - Calculated from EPA AP-42 assuming No. 2 fuel oi l heating value of 140,000 Btu/gal
c - Calculated from EPA AP-42 for total particulate
EPA did not establish a NO x presumptive limit for oil and gas fired units, but indicates th at the states should consider the installation of combustion cont rol technology on these units. Similarly, EPA also did not establish a presumptive BART limit fo r SO 2 from gas and oilfired units. The EPA guidelines suggest that a cost effective S O 2 control option for oil-fired units is to consider switching to a low sulfur fuel oil (No.2 fu el oil—0.05 percent sulfur diesel). EPA also stated that it was unable to find a flue gas desulfu rization (FGD) application in the U.S. electric industry on an oil-fired unit.2.0 PRESENT UNIT OPERATION

DEN/ES072007003/TRACY_1_10-03-08.DOC 2-3 According to 40 CFR Parts 72 and 75, in order for a gaseous fuel to qualif y as “natural gas,” the fuel must be either greater than or equal to 70 percent methan e by volume, or must have a gross calorific value between 950 and 1,100 Btu/standard cubic foot ( scf). For PNG, the hydrogen sulfide (H 2 S) content must be less than or equal to 0.3 grain/100 scf, and H 2 S 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. The Nevada Public Utilities Commission has mandated that Tracy U nit 1 maintain the capability to use both PNG and fuel oil. Therefore, this BART analys is includes a review of PNG and No. 2 fuel oil operation.DEN/ES072007003/TRACY_1_10-03-08.DOC 3-1 

# 3.0 BART Engineering Analysis

This section presents the required BART engineering analys is. 

# 3.1 Applicability In compliance with regional haze requirements, the State of Nev ada 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 ph ase of the regional haze program is the implementation of BART emission controls on all BART eligible units, within five years after EPA approval of the SIP. 

# 3.2 BART Process The specific steps in a BART engineering analysis are identifie d 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 c ontrol 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 com pliance, and
6. The degree of visibility improvement that may reasonably be ant icipated 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 c ontrol 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 Technol ogies

• Costs associated with control technologies are summarized in the economic analysis presented in Appendix A. For clarity, Appendix A also inclu des sample economic analysis spreadsheet calculations and explanation of assumption s used.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_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 com pliance Step 5 – Evaluate Visibility Impacts

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

use. In order to minimize costs in the BART analysis, consideration was m ade of any pollution control equipment in use at the source, the costs of complianc e associated with the control options, and the energy and non-air quality environmental imp acts of compliance using these existing control devices. In some cases, enhancing the performance of the existing control equipment was considered. Other scenarios with new c ontrol equipment were also developed. Separate analyses have been conducted for NO x , SO 2 , and PM 10 emissions. Because Tracy 1 has the option to burn PNG or No. 2 fuel oil, a separate analysis will be completed for each

case. For Tracy 1, baseline NO x , SO 2, PM 10 emissions were examined to determine whether completion of the five-step BART process is required for eac h of the two fuel alternatives (100 percent PNG and 100 percent No. 2 fuel oil). Table 3-1 below is a summary of the baseline emissions for Tracy 1.

TABLE 3-1 Current Tracy 1 Baseline Emissions Baseline Emissions (lb/MMBtu) PNG No. 2 Fuel Oil
NO x 0.275 0.275
SO 2 0.0006 0.051
PM 10 0.008 0.014

A BART NO x analysis was completed for both PNG and No. 2 Fuel Oil.
The baseline PM 10 and SO 2 emissions when burning No. 2 fuel oil is considered BART, based on EPA BART guidelines. All costs included in the BART analysis are in 2007 dollars, and co sts have not been escalated to the assumed 2013 BART implementation date.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_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 expect ed emission information was developed for NO x , but were not required for SO 2 and PM 10 . This information is assembled from various sources including emission reducti on equipment vendors, NV Energy operating and engineering data, and internal CH2M HILL his torical information. The level of accuracy of the cost estimate can be broadly classifi ed as “Order of Magnitude”, which can be categorized as -30/+50 percent. There are several reason s for the wide range of cost estimates included in the BART analysis; however, they are primarily caused by the difficulty in receiving detailed and accurate information fro m equipment vendors. Due to the extremely active power industry marketplace, obtaining e ngineering 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 exempl ified 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 c an be dependent upon the pollutant under consideration (i.e., particulate emissions can g enerally be more accurately predicted than NO x emissions). Therefore, when selecting emissions control technologies an d establishing emission permitting levels, consideration of variability in cost and ex pected emissions information must be considered.


## 3.2.1 BART NO x 

## Analysis
NO x formation in natural gas-fired boilers is a complex process t hat is dependent on a number of variables, including operating conditions, equipment design, and fuel characteristics. A NO x BART analysis will be completed for the cases when Tracy 1 bur ns 100 percent PNG and 100 percent No. 2 fuel oil.



### 3.2.1.1 Formation of NO x During combustion NO x is formed in three different ways; thermal NO x , fuel NO x , and prompt NO x . When combusting PNG, the most dominant source of NO x is from thermal NO x, which is due to high temperature fixation of atmospheric nitro gen in the combustion air. Because PNG generally contains small quantities of nitro gen the overall contribution from fuel NO x is small, while fuel NO x can be generated from fuel oil combustion. A very small amount of NO x is called “prompt” NO x . Prompt NO x results from an interaction of hydrocarbon radicals, nitrogen, and oxygen. Good combustion is based on the “three Ts”: time, temperature and tu rbulence. If a performance requirement such as NO x emission limits is changed, conflicts with other performance issues can result. When adjusting air flows and distribution to lower NO x using LNB and OFA, original boiler design restrictions may limit the changes that can be made an d still achieve satisfactory combustion performance.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-4 

### 3.2.1.2 Step 1: Identify All Available Retrofit Control Tec hnologies The first step of the BART process is to evaluate NO x control technologies with practical potential for application to Tracy 1, including those control technologies identified as BACT by permitting agencies across the United States. A broad rang e of information sources have been reviewed in an effort to identify potentially applicab le and demonstrated in practice emission control technologies. Tracy 1 NO x emissions are currently controlled through the use of good combustion practices. There is no BART presumpti ve NO x level for PNG and oil-fired units. The following potential NO x control technology options were considered:

• Low NO x Burners (LNG)

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

• Low NO x Burners (LNB) with Selective non-catalytic reduction syst em (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 1, a front wall-fired configuration permitted to burn P NG and No. 2 fuel oil, technical feasibility will primarily be determined by physi cal constraints, boiler configuration, and on the ability of the technology to achieve NO x emissions reduction. Current NO x emissions for Tracy 1 are shown in Table 3-1 below while burning P NG and No. 2 fuel oil. For this BART analysis, information received from Coen was use d as the basis for new LNB and LNB w/FGR. Coen did not propose the installation of OFA due t o the cost of boiler water wall changes. The cost estimates for SCR and SNCR were u pdated from previous CH2M HILL file information. Also, CH2M HILL received a proposa l from Mobotec for their ROFA and Rotomix technologies. Table 3-2 summarizes the control technology options evaluated in t his BART analysis, along with projected NO x emission rates. It should be noted that estimated emissions in formation from NO x technologies presented represent design targets. With a signi ficant potential for variability in emissions due to changes in unit operation, a long er averaging period results in a higher probability in meeting the permit emissions val ue. 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_1_10-03-08.DOC 3-5 TABLE 3-2 NO x Control Technology Emission Rate Ranking Tracy Unit 1

Technology Source of Estimated Emissions Estimated Emission Rate (lb/MMBtu) (PNG) Estimated Emission Rate (lb/MMBtu) (No.2 Fuel Oil)
Current Permit Limits (converted to lb/MMBtu for comparison) Title V 0.63 0.63

NV Energy (NVE) BART Limits NVEBL e 0..25 (Annual) 0.25 (Annual)

LNB d Coen 0.25 0.25
LNB w/FGR d Coen 0.12 0.16
LNB w/ SNCR Coen & CH2M HILL 0.19 c 0.19 c
ROFA w/Rotamix Mobotec 0.14 0.14 b

LNB w/ SCR a CH2M HILL 0.07 0.07

a - SCR estimated NO x emissions rate is the same for all scenarios. Oper ating cost would be affected by inlet NO x levels.
b - Calculated from Mobotec proposal information and No.2 fuel oil baseline NO x c - From Coen and Fuel Tech proposal, a 25% reductio n of the LNB emission rate d - Represents an assumed 10% reduction from Coen pr oposal figures
e 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 por tions of this BART analysis, may be technically feasible and provide expected emission rat es; however, they include inherent uncertainties. These proposals are usually prepared i n a limited time frame, may be based on incomplete information, may contain over-optimistic conclusions, and are nonbinding. Therefore, emission rate values obtained in such preli minary proposals must be qualified, and it must be recognized that contractual guarantees ar e established only after more detailed analysis has been completed. Also, emission rate s are typically based on a design average value (i.e., 30-day rolling average) versus a maximum 24-ho ur value. The following subsections describe the control technologies an d the control effectiveness evaluated in this BART analysis.


### Level of Confidence for Vendor Post-Control Emissio ns Estimates. In order to determine the level of NO x emissions needed to consistently achieve compliance with an established goal, a review of typical NO x emissions from oil and natural gas-fired generating units was completed. As a result of this review, it was noted that NO x emissions can vary around an average emissions level. This variance can be attributed to many r easons, including fuel characteristics, unit load, boiler operation including excess a ir, burner equipment condition, and so forth.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-6 The steps utilized for determining a level of confidence fo r the vendor expected value are as follows:
1. Establish expected NO x emissions value from vendor.
2. Evaluate vendor experience and historical basis for meeting e xpected values.
3. Review and evaluate unit physical and operational characteristic s and restrictions. The fewer variations there are in operations, fuel supply, etc., the mor e predictable and less variant the NO x emissions are.
4. For each technology expected value, there is a corresponding pot ential for actual NO x emissions to vary from this expected value. From the vendor inf ormation presented, along with anticipated unit operational data, an adjustment to th e expected value can be made. The following subsections describe the control technolog ies and the control effectiveness evaluated in this NO x BART analysis.


### New LNB The mechanism used to lower NO x 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 NO x . Fuel-rich conditions favor the conversion of fuel nitrogen to N 2 instead of NO x . LNB is considered to be a capital cost, combustion technology retrofit that may require water wall tube replaceme nt. 

### FGR. Flue Gas Recirculation (FGR) generally extracts flue gas from dow nstream of the economizer or air heater, and is mixed into the combustion air duc t. This recirculation can be achieved with a new FGR fan, or by using the existing forc ed draft (FD) fan to inject the flue gas into the combustion air (induced flue gas recirculati on). Flue gas adds oxygen-lean heat-absorbing mass to the combustion air, thus lowering the combustion temperature and reducing NO x emissions. 

### Neural Net Controls . Information regarding neural net controls was received from NeuCo, Inc. While NeuCo offers several neural net products, Combustio nOpt and SootOpt provide the potential for NO x reduction. NeuCo stated these products can be utilized on most control systems, and can be effective even in conjunction w ith other NOx reduction technologies. NeuCo predicts that CombustionOpt can reduce NO x by 15 percent, and SootOpt can provide an additional 5 to 10 percent. Because NeuCo doe s 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 u nit control system. Because NeuCo does not guarantee NO x reduction, the estimated emission reduction levels provided can not be considered as reliable p rojections. Therefore, neural net should be considered as a supplementary or “polishing” technol ogy, but not on a “standalone” basis.


### ROFA. Mobotec markets ROFA as an improved second generation OFA syst em. 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 ent ire volume of the furnace can be used more effectively for the combustion proc ess. In addition, the swirling3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-7 action reduces the maximum temperature of the flames and incre ases 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 bo xes, and Mobotec would propose one 230 horsepower (hp) fan for Tracy 1. Mobotec’s budgetary proposals included expected NO x 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 c omputational fluid dynamics modeling will determine the quantity and location of new R OFA ports. Although not specifically identified, Mobotec generally includes bent tube assemblies for ROFA port installation if required. Mobotec does not provide install ation services, because they believe that the owner can more cost effectively contract for these ser vices. However, they do provide one onsite construction supervisor during instal lation and startup. Due to previous experience with ROFA, NVE does not consider R OFA 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-cat alytic reduction using an ammonia or urea based reagent.


### SNCR. SNCR is generally utilized to achieve modest NO x reductions on smaller units. With SNCR, an amine-based reagent such as ammonia – or more commonly urea – is injected into the furnace within a temperature range of 1,600 degrees Fahrenheit (° F) to 2,100°F, where it reduces NO x to nitrogen and water. NO x reductions of up to 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 w hich the reagent reduces NO x , can range from 20 to 60 percent, depending on the amount of reducti on, unit size, operating conditions, and allowable ammonia slip. With low reagent ut ilization, low temperatures, or inadequate mixing, ammonia slip occurs, allowing u nreacted ammonia to create problems downstream. The ammonia may react with sulfur to fo ul heat exchange surfaces and/or create a visible stack plume. Reagent utilization can have an impact on economics, with higher levels of NO x reduction generally resulting in lower reagent utilization and higher operating cost. Reductions from higher baseline concentrations (inlet NO x ) are lower in cost per ton, but result in higher operating costs, due to greater reagent consum ption. A budgetary proposal was received from Fuel Tech for their SNCR system.


### SCR. SCR works on the same chemical principle as SNCR but SCR uses a c atalyst to promote the chemical reaction. Ammonia is injected into the fl ue-gas stream, where it reduces NO x to nitrogen and water. Unlike the high temperatures required fo r SNCR, in SCR the reaction takes place on the surface of a vanadium/titanium- based catalyst at a temperature range between 580° F to 750° F. Due to the catalyst, the SCR process is more efficient than SNCR and results in lower NO x emissions. The most common type of SCR is the high-dust configuration, where the catalyst is located dow nstream from the boiler economizer and upstream of the air heater and any particulate cont rol equipment. In this location, the SCR is exposed to the full concentration of any par ticulate in the flue gas that is leaving the boiler. In a full-scale SCR, the flue ducts are routed to a s eparate large reactor3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-8 containing the catalyst. With in-duct SCR, the catalyst is locate d 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 1. From previous SCR desig n experience, a projected NO x emission rate of 0.07 pound per million British thermal units ( lb/MMBtu) is projected for all emissions control equipment scenarios assuming curr ent equipment can meet retrofit requirements.


### 3.2.1.5 Step 4: Evaluate Impacts and Document the Results This step involves the consideration of energy, environmen tal, and economic impacts associated with each control technology. The remaining usefu l life of the plant is also considered during the evaluation. 

### Energy Impacts. The installation of LNB with FGR is not expected to greatly impac t the boiler efficiency or forced draft fan power usage. Therefore, t hese technologies will not have energy impacts. The Mobotec ROFA system requires installation and operation o f one 230 hp ROFA fan (172 kilowatts [kW ] total). An auxiliary power requirement for an SNCR system for a nominal 55 MW unit is estimated at 55 kW. The same estimate was used for Rotam ix. SCR retrofit impacts the existing flue gas fan systems, due t o the additional pressure drop associated with the catalyst, which is typically a 6- to 8-inch wate r gage increase. The energy impacts summarized above are included in the econom ic analysis presented in Appendix A. 

### Environmental Impacts. SNCR, Rotamix and SCR installation could potentially create a visible stack plume, which may negate other visibility improve ments. 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 ec onomic 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 co ntrol efficiencies, and tons of NO x removed is summarized in Table 3-3, and the first year control cost s in Figure 3-1. The capital costs shown in Table 3-3 are applicable for all of the fuel s under consideration. For example, if LNB are installed for PNG, the burner costs incl ude the capability to burn both PNG and No. 2 fuel oil (with only minor equipment changes, atomization changes, and burner control revisions). Similarly, the cost information for any of the NO x reduction technologies listed in Table 3-3 will apply for the fuel altern atives under consideration. The complete Economic Analysis is contained in Appendix A.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-9 

### 3.2.1.6 Step 5: Evaluate Visibility Impacts Please see Section 4.0, BART Modeling Analysis.3.0 BART ENGINEERING ANALYSISDEN/ES072007003/TRACY_1_10-03-08.DOC3-10TABLE 3-3NOxControl Cost Comparison using Fuel Oil #2Tracy Unit 1Factor LNBLNB w/FGRLNBw/SNCRROFAw/RotamixLNB w/SCRTotal Installed Capital Costs $704,000 $1,040,000 $2,532,500b$4,222,763a$16,940,000Total Installed Capital Costs with Additional OwnerCosts$1,232,000 $1,820,000 $4,431,875 $7,389,835 $21,175,000Total First Year Fixed & Variable O&M Costs $22,000$83,589 $68,330 $129,900 $194,090Total First Year Annualized Cost $152,661 $276,611$538,357 $913,636 $2,439,825Power Consumption (MW)- 0.55 0.06 0.61 0.28Annual Power Usage (Million kW-Hr/Yr) - 1.0 0.1 1.10.5NOxDesign Control Efficiency 8.4% 41.1% 31.3% 49.1% 74.5%Tons NOxRemoved per Year 15 76 58 91 138First Year Ave Control Cost ($/Ton NOxRemoved) 9,872 3,641 9,310 10,065 17,701Incremental Control Cost ($/Ton NOxRemoved) 9,872 2,048 (14,418) 11,391 32,426aBased on 75/25 installation cost split between ROFA and RotamixbFuel Tech equipment estimate plus 50% installationcost3.0 BART ENGINEERING ANALYSISDEN/ES072007003/TRACY_1_10-03-08.DOC3-11FIGURE 3-1First Year Control Cost for NOXAir Pollution Control OptionsTracy Unit 1First Year NOx Control Cost(20,000)(10,000)010,00020,00030,00040,000LNB LNB w/ FGR LNB w/SNCR ROFA w/Rotamix LNB w/SCRAir Pollution Control Option

First Year Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control Cost3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-12 

## 3.2.2 BART SO 2 

## Analysis
SO 2 forms in the boiler during the combustion process, and is pri marily dependent on natural gas and fuel oil sulfur content. The BART analysis for SO 2 emissions on Tracy 1 is described below. BART guidelines require that oil-fired units consider limit ing the sulfur content of the fuel oil burned, fuel switching to 0.05 percent No. 2 diesel fuel switch ing will be analyzed as an SO 2 option for this study. It should be noted that the Nevada Public Utilities Commission has mandated that the Tracy units have both PNG and fuel oil capabil ity.


### 3.2.2.1 Step 1: Identify All Available Retrofit Control Tec hnologies A broad range of information sources were reviewed, in an effo rt to identify potentially applicable emission control technologies for SO 2 at Tracy 1; this included control technologies identified as BACT by permitting agencies acros s the United States. The following potential SO 2 control technology options were considered:

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



### 3.2.2.2 Step 2: Eliminate Technically Infeasible Options Technical feasibility will primarily be determined by f uel storage delivery constraints, boiler configuration, and on the ability of low sulfur fuel oil to achi eve SO 2 emissions reduction. The present SO 2 emission on Tracy 1, while burning No. 2 fuel oil, is 0.051 lb/MMBtu. Table 3-4 summarizes the control technology options evaluated in t his BART analysis.

TABLE 3-4 Control Technology Options Evaluated Tracy Unit 1

Technology Estimated Emission Rate (lb/MMBtu)
Current Title V Permit Limitation (converted to lb/MMBtu for comparison) 0.05 (3-hr average)

NVE BART Limit (Low Sulfur No. 2 Fuel Oil) 0.05 (24-hr average)
PNG 0.00062



### 3.2.2.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies When evaluating the control effectiveness of SO 2 reduction technologies, each option can be compared to the proposed NVE BART Limit. With a fuel switch to low sulfur diesel, the expected SO 2 emissions are estimated at this level Because Tracy 1 is not cur rently capable of burning 100% No. 2 fuel oil, capital improvements would be require d. The following describe the control technologies and the con trol effectiveness evaluated in this BART analysis.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-13 

### Use of low sulfur distillate oil (No. 2 fuel oil) This alternative entails the use of a low sulfur (0.05 % sulfur) dies el.



### 3.2.2.4 Step 4: Evaluate Impacts and Document the Results This step involves the consideration of energy, environmen tal, and economic impacts associated with each control technology. The remaining usefu l life of the plant is also considered during the evaluation. 

### Energy Impacts. No energy impact is associated with switching to low sulfur die sel fuel. No energy impact costs are included in the economic analysis presented in Appendix A. 

### Environmental Impacts. No environmental impact is associated with switching to low su lfur diesel fuel. These environmental impacts have not been quantified in the ec onomic analysis presented in Appendix A. 

### Economic Impacts. A summary of the costs and amount of SO 2 removed for fuel switching is provided in Table 3-5.

TABLE 3-5 Costs and Amount of SO 2 Removed for Fuel Switching Tracy Unit 1

Factor Switch to Low Sulfur Diesel Fuel Total Installed Capital Costs $500,000 a
Total First Year Fixed & Variable O&M Costs Total First Year Annualized Cost Additional Power Consumption (MW) Additional Annual Power Usage (1000 MW-Hr/Yr) Incremental SO 2 Design Control Efficiency (%) N/A Incremental Tons SO 2 Removed per Year First Year Average Control Cost ($/Ton of SO 2 Removed) Incremental Control Cost ($/Ton of SO 2 Removed)

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.3.0 BART ENGINEERING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 3-14 

## 3.2.3 BART PM 10 

## Analysis Tracy 1 currently is not equipped with a PM 10 control device. Because of the analysis completed in Section 3.2, no PM 10 analysis is required. Tracy Unit 1 is considered to meet BART PM 10 emissions levels when burning either PNG or No. 2 fuel oil. 

# 3.3 Summary

The most cost-effective emissions control scenario include s the utilization of LNB with FGR with PNG and/or low-sulfur No. 2 fuel oil. The Nevada Public Util ities Commission has mandated that Tracy Unit 1 maintain the capability to use both PNG and fuel oil.DEN/ES072007003/TRACY_1_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 opt ions for the NV Energy Tracy Power Plant Unit 1. To a large extent, the modeling followed the methodology outl ined in the Western Regional Air Partnership (WRAP) protocol for performing BART analy ses (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) mo deling system to assess the visibility impacts at Class I areas. Work groups that rep resent the interests of the Federal Land Managers (FLM) recommend that an analysis of Class I are a air quality and air quality related values (AQRVs) be performed for major source s located more than 50 km from these areas (EPA, 1998). The CALPUFF model is routinely recomme nded for these types of regulatory analyses. The CALPUFF modeling system includes the meteorological dat a preprocessing program for CALPUFF (CALMET) with algorithms for chemical transfor mation and deposition, and a post processor capable of calculating concentrations, visibili ty impacts, and deposition (CALPOST). The CALPUFF modeling system was applied in a full, ref ined mode. CH2M HILL used the latest version (Version 6) of the CALPUFF mod eling system preprocessors and models in lieu of the EPA-approved version s (Version 5). The FLMs and others have noted that the EPA-approved Version 5 contained err ors and that a newer version should be used. Consequently, it was decided to use t he latest (as of April 2006) version of the CALPUFF modeling system (available at www.sr c.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 d omain. The recompiled processors were tested against the test case resul ts provided with the source code (TRC, 2007), and the difference between the results was 0.03 per cent.4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_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 Mode l, Version 5 (MM5), CALMET, and CALPUFF that were slightly different than those es tablished for the Nevada BART modeling in WRAP (2006). In addition, the CALMET and CALPUFF Lam bert Conformal Conic (LCC) map projection is based on a central meri dian 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-dimension al wind fields and other meteorological parameters suitable for use by the CALPUFF mod el. 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 CA LMET. 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 C olorado Department of Health and Environment (CDPHE) analyses of sound ings for summer ozone events in the Denver area (CDPHE, 2005). The CDPHE analysis sugge sts 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 meteorologi cal regimes, including some regimes associated with high-ozone episod es. 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_1_10-03-08.DOC 4-3 FIGURE 4-1 Tracy Power Plant, CALMET/CALPUFF Domain4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 4-4 Table 4-1 lists the key user-specified options.

TABLE 4-1 User-Specified CALMET Options Tracy Unit 1 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, an d 2003. CH2M HILL used MM5 data as the basis for the CALMET wind fields. Th e horizontal resolution of the MM5 data is 36 km. For 2001, CH2M HILL used MM5 data at 36-km resolution that were obtained f rom the contractor (Alpine Geophysics) who developed the nationwi de data for the EPA. For 2002, CH2M HILL used 36-km MM5 data obtained from Alpine Geophysics, orig inally developed for the WRAP. Data for 2003 (also from Alpine Geophysics), at 36-km r esolution, were developed by the Wisconsin Department of Natural Resources, the Illinois Environmental Protection Agency, and the Lake Michigan Air Directors Cons ortium (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 lan d use effects to generate a4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 4-5 Step 1 wind field, and then further refined using local surface ob servations 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 S ervice’s (NWS) Automated Surface Observing System (ASOS) network that are in the domain. The surface data were obtained in abbreviated DATSAV3 format. A conversion rou tine available from the TRC website was used to convert the DATSAV3 files to CD 144 fo rmat for input to the SMERGE preprocessor and CALMET. Land use and terrain data were obtained from the U.S. Geological Sur vey (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 la nd use categories. Surface properties, such as albedo, Bowen ratio, roughness lengt h, 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 US GS 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 i n fixed-length, TD-3240 format were ordered for the modeling domain. The list of availabl e stations and stations that have collected complete data varies by year, but CH2M HILL proces sed all available stations/data within the domain for each year. Precipitation da ta were prepared with the PXTRACT/PMERGE processors in preparation for use within CALM ET. Following the methodology recommended in WRAP (2006), no ob served upper-air meteorological observations were used as they are redundant to t he MM5 data and may introduce spurious artifacts in the wind fields. In the devel opment 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 p art 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 meteorol ogy 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 observatio ns 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) dat a display and analysis system (v2.97, Enviromodeling Ltda.) to view plots of win d vectors and other meteorological parameters to evaluate the CALMET wind fields. We u sed observed weather conditions, as depicted in surface and upper-air weather maps f rom the National Oceanic and Atmospheric Administration (NOAA) Central Library U.S. D aily Weather Maps Project (http://docs.lib.noaa.gov/rescue/dwm/data_rescue_daily_w eather_maps.html), to compare to the CalDESK displays.4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 4-6 

# 4.4 CALPUFF Methodology

4.4.1 CALPUFF Modeling CH2M HILL ran the CALPUFF model with the meteorological outp ut from CALMET over the CALPUFF modeling domain (Figure 4-1). The CALPUFF model wa s used to predict visibility impacts for the pre-control (baseline) scenar io 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 SO 2 and NO X 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 transfor mation 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 s cenarios 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 affec t 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; J uly 6, 2005, pg 39129):
“The emissions estimates used in the models are intended to refl ect steady-state operating conditions during periods of high-capacity utilization. We do not generally recommend that emissions reflecting periods of start-up, shutdown, and malfun ction be used...”
CH2M HILL selected the emissions rates used in the WRAP RMC m odeling as the Pre-control (baseline) emission rates. The WRAP PM10 and SO 2 were speciated to determine emission rates for coarse particulate, fine particulate, eleme ntal carbon, organic aerosols, and sulfates. Emissions were modeled for the following species:

• Sulfur dioxide (SO 2 )

• Nitrogen oxides (NO x )

• Coarse particulate (PM 2.5 < diameter ≤ PM 10 )

• Fine particulate (diameter ≤ PM 2.5 )

• Elemental carbon (EC)4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 4-7 • Organic aerosols (SOA)

• Sulfates (SO 4 )



### 4.4.1.4 Post-control Emission Rates Post-control emission rates represent the NVE BART Limit em ission levels presented in Table 5-1, with the exception of the NO x 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 excepti on of the NO x emission rate which 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/longit ude coordinates to LCC coordinates for the meteorological stations and source locatio ns. The USGS conversion program PROJ (version 4.4.6) was used to convert the National Park Se rvice (NPS) receptor location data from latitude/longitude to LCC. For the Class I areas that are within 300 km of the Tracy Power Plant, dis crete 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 inter sects the 300-km circle (Figure 3-1) were included in the modeling analysis. The follo wing 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 W ilderness (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_1_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 vi sibility 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) ch ange relative to natural background. Default extinction coefficients for each specie s, as shown below, were used:

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0

• PM coarse (PM 10 ) 0.6

• PM fine (PM 2.5 ) 1.0

• Organic carbon 4.0

• Elemental carbon 10.0 CALPOST visibility Method 6 (MVISBK=6) was used for the deter mination of visibility impacts. Monthly average relative humidity factors [f(RH)] we re used in the light extinction calculations to account for the hygroscopic characteristic of s ulfate and nitrate particles. Monthly f(RH) values, from the WRAP_RMC BART modeling, were u sed in CALPOST for the particular Class I area being modeled. The natural background conditions used in the post-processi ng 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 E PA Guidance.

TABLE 4-2 Average Natural Levels of Aerosol Components Tracy Unit 1
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 Estimati ng Natural Visibility Conditions Under the Regional Haze Rule. EPA-454/B-03-005, September 200 3. 

# 4.6 Results
Input and output files for the CALMET/CALPUFF modeling and pos t-processing will be provided upon request.4.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_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 verificat ion runs. The results show good correlation in estimated maximum ∆dv. Much of the dif ference between these values is probably attributed to the different alignment of th e 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 Unit 1

98 th Percentile ∆ dv for Each Year

Class I Area Min

Distance (km) Max

Delta ∆ dv 98 th

Percentile ∆ dv Days > 0.5

∆ dv 2001 2002 2003 98 th ∆ 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 0.544.0 BART MODELING ANALYSIS

DEN/ES072007003/TRACY_1_10-03-08.DOC 4-10 TABLE 4-4 Verification CALPUFF Modeling Results Tracy Unit 1

98 th Percentile ∆ dv for Each Year

Class I Area Min

Distance (km) Max

Delta ∆ dv 98 th

Percentile ∆ dv Days > 0.5

∆ dv 2001 2002 2003 98 th ∆ 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 Sec tion 5. As previously mentioned, the NO x emission rate modeled is in excess of the NVEBL.DEN/ES072007003/TRACY_1_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 1, the recommended BART controls include installing LNB with FGR for NO x and utilizing PNG and/or low-sulfur No. 2 fuel oil for SO 2 and PM 10 emissions reduction. There are no presumptive limits assigned by the Un ited 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 NVE BL 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 Ti tle V Permit Limit and expected emission levels utilizing the NVE BART Limit emis sion levels. While the NO x emission rate modeled is in excess of the current NVEBL, model ing results represent worst case visibility impacts. Because of the basis utilized to establ ish 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 bas ed upon the year 2006, and does not necessarily represent worst case potential emissi on rates. The Title V permit limitations offers a more representative view of maximum poten tial emission rates, since these are enforceable operating limits Comparison of dispersion modeling results for the three scen arios are presented below.

TABLE 5-1 Modeled Emission Control Scenarios Tracy 1

CASE Estimated NO x Emissions (lb/MMBtu) Estimated SO 2 Emissions (lb/MMBtu) Estimated PM 10 Emissions (lb/MMBtu)
WRAP Baseline 0.425 0.001 0.002
Title V Permit Limit 0.63 0.05 0.23
Scenario 1 –NVE BART Limit 0.40 a 0.05 0.03

a – NO x emission rate higher than NVEBL5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-2 TABLE 5-2 Ranking of NO x Control Scenarios by Cost Tracy 1

Rank Scenario Total Annual Cost

1 LNB $152,661 2 LNB w/FGR $276,611 3 New LNB with SNCR $538,357 4 ROFA with Rotamix $913,636 5 New LNB with SCR $2,439,825
The ranking of the different NO x emission control scenarios based on annual costs, from lowest to highest cost, is presented on Table 5-2. Dispersio n Modeling Results The results of the dispersion modeling are shown below. In th is 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 NVE BA RT Limit emission rates. The NVE BART Limit emission rates for Tracy Unit 1 demonstrate an improvement in visibility.

TABLE 5-3 Comparison of Visibility Impacts by Class I Area Tracy Unit 1

98 th 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 0.22 0.44 0.26 1 6 1
Moke 101 0.17 0.32 0.19 1 1 1 Emig 139 0.09 0.16 0.09 0 1 0
Hoov 143 0.10 0.19 0.11 0 1 0
Yose 153 0.10 0.17 0.10 0 1 0
Cari 171 0.24 0.44 0.26 1 6 1
Lavo 176 0.22 0.40 0.25 1 6 1
Anad 182 0.06 0.11 0.06 0 0 0
Sowa 190 0.18 0.30 0.19 1 4 1
Thla 210 0.11 0.20 0.12 0 3 0
Jomu 221 0.07 0.12 0.07 0 0 0
Kais 249 0.04 0.08 0.04 0 0 0
Kica 265 0.06 0.11 0.06 0 0 0
Labe 286 0.09 0.14 0.09 0 0 0
Yobo 287 0.04 0.07 0.04 0 0 05.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-3 FIGURE 5-1 Comparison of 98 th Percentile Delta Deciview Visibility Impacts Part 1 Tracy 1

Comparison of 98th Percentile Delta Deciview Visibi lity Impacts Tracy Unit 1 Part 1

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50

Desolation W Mokelumne W Emigrant W Hoover W Yosemite NP Caribou W Lassen Volcanic NP Ansel Adams

W Class I AreaDelta Deciview WRAP Basline Title V Permit Limit SPR BART Limit5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-4 FIGURE 5-2 Comparison of Delta Deciview Visibility Impacts Par t 2 Tracy 1

Comparison of 98th Percentile Delta Deciview Visibi lity Impacts Tracy Unit 1 Part 2

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50

South Warner

W Thousand

Lakes W John Muir W Kaiser W Kings Canyon NP Lava Beds NM Yolla Bolly Middle Eel W Class I AreaDelta Deciview WRAP Baseline Title V Permit Limit SPR BART Limit5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-5 FIGURE 5-3 Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv Part 1 Tracy 1

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

0 1 2 3 4 5 6 7

Desolation W Mokelumne W Emigrant W Hoover W Yosemite NP Caribou W Lassen Volcanic NP Ansel Adams

W Class I AreaDays WRAP Baseline Title V Permit Limit SPR BART Limit5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-6 FIGURE 5-4 Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv Part 2 Tracy 1

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆ dv Tracy Unit 1 Part 2

0 1 2 3 4 5 6 7

South Warner

W Thousand

Lakes W John Muir W Kaiser W Kings Canyon NP Lava Beds NM Yolla Bolly Middle Eel W Class I AreaDays WRAP Baseline Title V Permit Limt SPR BART Limit

As shown in Figures 5-1 through 5-4, there is a decrease in modeled visibility impact when reducing the modeled emission levels from the Title V Permi t Limit to the NVEBL emission rates. The modeled visibility impact from the modeled emissio n levels from the WRAP and NVEBL are very similar.


## 5.1.1 NOx Control Scenario Visibility Modeling While visibility modeling has not been completed for the co mbination of NO x , SO 2 , and PM 10 NBEBL values, Tables 5-4 and 5-5 below compare the results for the various NO x 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, LNB with FGR is selected as BART for Tracy 1.5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-7 TABLE 5-4 NO x Control Scenario Results for Desolation Wilderness Tracy 1

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 2 0.009 0.153 16.962

2 New LNB and

FGR 0 0.047 0.277 5.885

3 New LNB and

SNCR 0 0.036 0.538 14.954

4 ROFA

w/Rotamix 0 0.056 0.914 16.315

5 New LNB and

SCR 0 0.085 2.440 28.704

TABLE 5-5 NO x Control Scenario Results for Yosemite NP Tracy 1

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 0 0 0 0
1 New LNB 0 0.005 0.153 30.532

2 New LNB and

FGR 0 0.024 0.277 11.525

3 New LNB and

SNCR 0 0.018 0.538 29.909

4 ROFA

w/Rotamix 0 0.029 0.914 31.505

5 New LNB and

SCR 0 0.045 2.440 54.2185.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-8 

# 5.2 Recommendations

5.2.1 NO x 

## Emission Control LNB with FGR has been selected as the NO x reduction technology with an NVEBL of 0.25 lb/MMBtu averaged on an annual basis. LNB with FGR is based on util izing enhanced combustion techniques to meet the proposed NVE BART Limit. Th ere is significant uncertainty involved in obtaining vendor emission guarantees and associated equipment/construction costs at this stage of analysis when re trofitting older boiler units. Site specific engineering is required on a “unit by unit” bas is to determine the most effective control technology. The estimated vendor NOx emission rate for LNB with FGR is 0.16 lb/ MMBtu, which was based on burning PNG or No. 2 fuel oil. The BART analysis was comple ted utilizing this emission rate, and the technology selection of LNB and FGR was made accordingly. The BART NO x NVEBL for other similar NVE units burning PNG and fuel oil was determined from a vendor estimate while burning the worst case No. 6 fuel o il. Therefore, due to uncertainties in complying with a permit limit based on prel iminary vendor information, and to be consistent with the basis of selection for other s imilar NVE units, the Tracy 1 NVEBL of 0.25 lb/MMBtu on an annual basis was established. This value i s based on the vendor estimate for Tracy 1 while burning No. 6 fuel oil with LNG and FGR.


## 5.2.2 SO 2 

## Emission Control The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART fo r Tracy Unit 1 with an NVEBL of 0.05 lb/MMBtu averaged on a 24-hour basis. No additional SO 2 emission control is required.


## 5.2.3 PM 10 

## Emission Control The utilization of PNG and/or low-sulfur No. 2 fuel oil is BART fo r Tracy Unit 1 with an NVEBL of 0.03 lb/MMBtu averaged on a 3-hour basis. No additional PM 10 emission control is required. 

# 5.3 Just-Noticeable Differences in Atmospheric Haze

Conclusions reached in the reference document Just-Noticeable Differences in Atmospheric Haze by Dr. Ronald Henry of the University of Southern California st ate that only dV differences of approximately 1.5 to 2.0 dV, or more are perceivable by t he 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 a ny, observable visibility improvements at the Class I areas studied would be expected un der any of the scenarios. Thus the results indicate that even though many millions of d ollars will be spent, only minimal, if any, noticeable visibility improvements may result

. Finally, it should be noted that none of the data were correcte d 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, the re were several megawildfires that lasted for many days and could have had an impact of background visibility5.0 PRELIMINARY ASSESSMENT AND RECOMMENDATIONS

DEN/ES072007003/TRACY_1_10-03-08.DOC 5-9 in these Class I areas. If natural obscuration were to reduce the redu ction in visibility impacts modeled for the Tracy 1 facility, the effect would be to i ncrease the costs per ∆dV reduction that are presented in this report.DEN/ES072007003/TRACY_1_10-03-08.DOC 6-1 

# 6.0 References

40 CFR Part 51. 2005. Regional Haze Regulations and Guidelines for Best Avai lable 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 Nonattainm ent Area Permitting. October.
EPA. 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long-Range Transport Impa cts. Air Quality Modeling Group (MD-14), Research Triangle Park, North Carolina; National Park Servi ce, Air Resources Division, Denver, Colorado; USDA Forest Service, Air Program, F ort Collins, Colorado; and U.S. Fish and Wildlife Service, Air Quality Branch, Denver, Color ado. December 1998. Guidance for Estimating Natural Visibility Conditions Unde r the Regional Haze Rule

. Henry, Ronald C. 2002. “Just-Noticeable Differences in Atmospheri c 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 f or BART Exemption Screening Analysis for Class I Areas in the Western Un ited States. Air Quality Modeling Forum. Regional Modeling Center. August 15, 2006.

# AppendicesAPPENDIX A 

# Economic AnalysisAPPENDIX B 

# BART Protocol