DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 

# BART Analysis for

Reid Gardner Station Unit 1

Prepared for 

# NV Energy
6226 West Sahara Avenue Las Vegas, NV 89031


### Revised Report October 2008

Prepared By:

2285 Corporate Circle Henderson, NV 89074DEN/ES072007003/REID_GARDNER_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) Reid Gardner Station Unit 1 (hereafter referred t o as Reid Gardner 1). A BART analysis has been conducted for the following crite ria pollutants: oxides of nitrogen (NO x ), sulfur dioxide (SO 2 ), and particulate matter less than 10 microns in aerodynamic diameter (PM 10 ). The Reid Gardner Station consists of four units: three nominal 100-megawatt (MW ) units and one nominal 265-MW unit, for a total station nominal generating capacity of 565 MW. Only units 1 through 3 are BART-eligible . BART must be implemented within 5 years after the State Implementation Plan ( SIP) is approved by the United States Environmental Protection Agency (EPA). A co mpliance date of 2015 was assumed for this analysis. In completing the BART analysis, technology alternatives were i nvestigated, and potential reductions in NO x , SO 2 , and PM 10 emission rates were identified. While expected emissions levels for each pollutant were estimated, comparisons with the proposed NV Energy BART Limits for NO x , SO 2 , and PM 10 are also presented. Listed below by pollutant are the technology alternatives that were investigated:
NO x emission controls:

• Low NO x Burners (LNB) with Overfire Air (OFA)

• Low NO x Burner (LNB) with selective non-catalytic reduction syste m (SNCR)

• Rotating Opposed Fire Air (ROFA) with Rotamix

• LNB with selective catalytic reduction (SCR) system

• ROFA with SCR
SO 2 emission controls:

• Dry flue gas desulfurization (FGD) system

• Dry sorbent injection

• Furnace sorbent injection

• New wet FGD system

• Improve or upgrade wet soda ash FGD system operation
PM 10 emission controls:

• Upgrade mechanical collector

• Electrostatic precipitator (ESP)

• Fabric filterEXECUTIVE SUMMARY

DEN/ES072007003/REID_GARDNER_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 that may reasonably be ant icipated from the use of BART These steps are incorporated into the BART analysis: Step 1 – Identify All Available Retrofit Control Technologies Step 2 – Eliminate Technically Infeasible Options

• The identification of available, technically feasible, retrofit 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 includ es 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 2015 BART implementation date.EXECUTIVE SUMMARY

DEN/ES072007003/REID_GARDNER_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, control cost an d expected emission information was developed for NO x , SO 2 , and PM 10 . This information is assembled from various sources including emission reduction equipment ven dors, NV Energy operating and engineering data, and internal CH2M HILL historical informatio n. 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 ques tionable, and is also attributable to the inability to gain timely and accurate vendor in formation. This is exemplified by the difficulty in obtaining background info rmation, 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, varianc e in expected emissions can be dependent upon the pollutant under consideration (i.e., particul ate emissions can generally be more accurately predicted than NO x emissions). Therefore, when establishing emission limitations in permits, consideration of variability in cost an d expected emissions information must be considered. 

# Coal Characteristics
The source of fuel burned at Reid Gardner Unit 1 is primarily w estern bituminous coal. Natural gas will be utilized during startup, shutdown, and flame s tabilization. 

# Recommendations

NO x 

## Emission Control LNB with OFA has been selected as the NO x reduction technology with an NV Energy BART Limit (NVEBL) of 0.39 lb/MMBtu averaged on an annual basis. The re 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 Due to uncertainties in future coal supply, and changes in boiler operation from the current pressurized operation to balanced draft operation, the NVEBL of 0.39 lb/MMBtu on an annual basis was established.


## SO 2 

## Emission Control The utilization of the existing wet soda ash FGD system is BART for Reid Gardner 1 with an NVEBL of 0.40 lb/MMBtu averaged on a 24-hour basis.EXECUTIVE SUMMARY

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC ES-4 

## PM 10 

## Emission Control BART for Reid Gardner 1 will be accomplished by the installatio n of a fabric filter with an NVEBL of 0.02 lb/MMBtu averaged on a 3-hour basis, which is currently planned for installation by July 1, 2010. No further PM 10 emission control will be required to achieve BART.


## Control Recommendation The BART selections include the utilization of LNB and OFA, cont inued FGD system operation, and installing a fabric filter for Reid Gardner 1. The se selections are supported by cost and visibility analyses. Even though the NVEBL for each p ollutant was established utilizing technology specific estimated design values, NVE mai ntains the flexibility to meet the limit by implementing operational or technology options o f their choice. 

# BART Modeling Analysis
CH2M HILL is using the CALPUFF modeling system to assess the v isibility impacts of emissions from Reid Gardner 1 at nearby Class I areas. The Class I areas po tentially affected are located more than 50 kilometers (km), but less than 300 km, from the Reid Gardner Station. The Class I areas include the following national parks (NP) and wild erness areas (WA):

• Bryce Canyon NP

• Grand Canyon NP

• Joshua Tree NP

• Sycamore Canyon W A

• Zion NP Visibility impacts were determined for the 1) WRAP baseli ne, 2) the current Title V emission permit limits, and 3) the proposed NVEBL.DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC ii 

# Contents

Section Page Executive Summary...................................................................................................................... ES-1 Background ........................................................................................................................ES-1 BART Engineering Analysis ............................................................................................ES-2 Coal Characteristics...........................................................................................................ES-3 Recommendations.............................................................................................................ES-3 NO x Emission Control .........................................................................................ES-3 SO 2 Emission Control...........................................................................................ES-3 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 1.1 Purpose...................................................................................................................... 1-1 2.0 Present Unit Operation....................................................................................................... 2-1 3.0 BART Engineering Analysis ............................................................................................. 3-1 3.1 Applicability ............................................................................................................. 3-1 3.2 BART Process............................................................................................................ 3-1 3.2.1 BART NO x Analysis .................................................................................. 3-2 3.2.2 BART SO 2 Analysis ................................................................................. 3-10 3.2.3 BART PM 10 Analysis ............................................................................... 3-13 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........................................................................................ 4-7 4.5.1 CALPOST ................................................................................................... 4-7 4.6 Results........................................................................................................................ 4-8 4.6.1 WRAP Verification Runs Results............................................................ 4-8 4.6.2 BART Modeling Analysis......................................................................... 4-9 5.0 BART Analysis and Recommendations.......................................................................... 5-1 5.1 Recommended BART Controls.............................................................................. 5-1 5.2 Dispersion Modeling Results ................................................................................. 5-2 NO x Control Scenario Visibility Modeling ......................................................... 5-4 5.3 Recommendations.................................................................................................... 5-5CONTENTS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC iii

5.3.1 NO x Emission Control .............................................................................. 5-5 5.3.2 SO 2 Emission Control................................................................................ 5-5 5.3.3 PM 10 Emission Control.............................................................................. 5-5 5.4 Just-Noticeable Differences in Atmospheric Haze.............................................. 5-6 6.0 References............................................................................................................................. 6-1


## Appendices A Economic Analysis B BART ProtocolDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC iv 

# Acronyms and Abbreviations

ACFM actual cubic feet per minute AQRV air quality related value ASOS Automated Surface Observing System BACT Best Available Control Technology BART Best Available Retrofit Technology
Btu British thermal unit 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
CaSO 4 calcium sulfate CDPHE Colorado Department of Health and Environment CFR Code of Federal Regulations
CO carbon monoxide CTG Composite Theme Grid
DBA dibasic acid ∆dV delta deciview, change in deciview DEM digital elevation model
dV deciview
EC elemental carbon EPA United States Environmental Protection Agency ESP electrostatic precipitator f (RH) relative humidity factor
FDDA Four Dimensional Data Assimilation FGD flue gas desulfurization FLM Federal Land Manager ft./sec. feet per secondACRONYMS AND ABBREVIATIONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC v Fuel NO x oxidation of fuel bound nitrogen HHV higher heating value hp horsepower
km kilometer
kW kilowatt
kW -Hr kilowatt-hour
LAER lowest achievable emission rate lb/MMBtu pounds per million British thermal unit
LCC Lambert Conformal Conic
LNB low-NO x burner LOI loss on ignition MM5 Mesoscale Meteorological Model, Version 5
MMBtu million British thermal unit
MSL mean sea level
MW megawatt
N 2 nitrogen
NCDC National Climatic Data Center
NDEP Nevada Division of Environmental Protection
NO nitric oxide NOAA National Oceanic and Atmospheric Administration
NO x oxides of nitrogen
NP National Park
NPS National Park Service
NSR New Source Review NVE NV Energy
NWS National Weather Service
OFA over-fire air O&M operations and maintenance
PM 2.5 particulate matter less than 2.5 microns in aerodynamic diameter
PM 10 particulate matter less than 10 microns in aerodynamic diameterACRONYMS AND ABBREVIATIONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC vi ppb part per billion PPM parts per million
PRB Powder River Basin RMC Regional Modeling Center ROFA Rotating Opposed Fire Air S&L Sargent & Lundy NVEBL NV Energy BART Limit SCR selective catalytic reduction SIP State Implementation Plan SNCR selective non-catalytic reduction
SO 2 sulfur dioxide
SO 4 sulfates sq. ft. square feet USGS U.S. Geological Survey
WA Wilderness Area WRAP Western Regional Air PartnershipDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 1-1 

# 1.0 Introduction

1.1 Purpose
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 for those facilities. This information will be included in the Nevada State Implementation Plan (SIP), which the State has estimated will be formally submitted to the EPA by Decemb er 1, 2008. The EPA BART guidelines also state that the BART emission limits must be fu lly 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 he Reid Gardner Station Unit 1 (hereafter referred to as Reid Gardner 1) by CH2M HILL for NV Energy. The analysis was performed for the pollutants oxides of nitrogen (NO x ), sulfur dioxide (SO 2 ), and particulate matter less than 10 microns in aerodynamic diameter (PM 10 ) because they are the primary criteria pollutants that affect visibility. Section 2.0 of this report provides a description of the present unit operation, including a discussion of coal sources and characteristics. The BART Engine ering Analysis is provided in Section 3.0 by pollutant type. Section 4.0 provides the BART mod eling 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 the BART modeling protocol.

1 40 Code of Federal Regulations (CFR) Part 51: Regi onal Haze Regulations and Guidelines for Best Avail able Retrofit Technology (BART) Determinations; Final Rule. 70 Fe deral Register, 39103-39172, July 6, 2005.DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 2-1 

# 2.0 Present Unit Operation

The Reid Gardner Station consists of four units: three nominal 100-megawatt (MW) units and one nominal 265-MW unit, for a total nominal generating capacity of 565 MW . Reid Gardner 4 is not a BART-eligible unit. Reid Gardner 1 is a nominal 100-M W output unit commissioned in 1965 and is located in Moapa, Nevada. Unit 1 is currently equipped with a wall-fired pulverized coal boiler manufactured by Foster Whe eler with low-NO x burners (LNB) and over-fire air (OFA), mechanical collector for partic ulate control, and a venturi/tray scrubber that uses soda ash for SO 2 removal. A unit upgrade project is currently in progress on Reid Gardne r 1 and consists of the following scope:

• Installation of a pulse jet fabric filter

• Installation of a new fly ash handling system

• Removal of existing mechanical collector This pulse jet fabric filter is scheduled for completion b y July 2010; therefore this BART analysis assumes that the above scope and equipment will be impl emented. However, for purposes of this analysis, the costs and emissions reductio n for the fabric filter are included in the analysis. For Table 2-1 below, the PM 10 emission rate shown is equal to the fabric filter vendor guarantee. Reid Gardner 1 was placed in service in 1965 and this analysis is based on a 20-year life for BART control technologies. Assuming a BART implementation date of 2015, this will result in an approximate remaining useful life for Reid Gardner 1 of 20 y ears from the installation date of any BART-related equipment. However, this report does not attempt to quantify any additional life extension beyond current plans or costs nee ded to allow the unit and these control devices at Reid Gardner 1 to operate until 2035. 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 and PM 10 emission rates which is higher than the NVEBL. Table 2-1 lists additional unit information and study assumption s for this analysis.SECTION 2.0: PRESENT UNIT OPERATION

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 2-2 TABLE 2-1 Unit Operation and Study Assumptions Reid Gardner 1 General Plant Data Site Elevation (feet above MSL) 1,573 Stack Height (feet) 200 Stack Exit ID (feet)/Exit Area (sq. ft.) 13.3/138.9 Stack Exit Temperature (°F) 135 Stack Exit Velocity (ft./sec.) 52.4 Stack Flow (ACFM) 436,702 Annual Unit Capacity Factor (percent) 86 Net Unit Output (Nominal MW) 100 Net Unit Heat Rate (Btu/kW-Hr)(100 percent load) 11 ,324 Boiler Heat Input (MMBtu/Hr)(100% load) 1,215 Type of Boiler Wall-fired Boiler Fuel Bituminous Coal (Primary) Natural Gas (Startup, Shutdown, Flame Stabilization) Coal Sources See Table 2-2 NO x Emissions Data (24-hour Average Maximum) Current NO x Controls LNBs with OFA Title V NO x Permit Limit (lb/MMBtu) 0.46 WRAP NO x Emission Rate (lb/MMBtu) 0.591 Average NO x Emission Rate (lb/MMBtu) b 0.381 Maximum NO x Emission Rate (lb/MMBtu) d 0.576 SO 2 Emissions Data (24-hour Average Maximum) Current SO 2 Controls Soda Ash FGD Title V SO 2 Permit Limit (lb/MMBtu) 0.55 WRAP SO 2 Emission Rate (lb/MMBtu) 0.329 Average SO 2 Emission Rate (lb/MMBtu) c 0.050 Maximum SO 2 Emission Rate (lb/MMBtu) d 0.332 PM 10 Emissions Data (24-hour Average Maximum) Current PM 10 Controls a Fabric filter Title V PM 10 Permit Limit (lb/MMBtu) 0.2 WRAP PM 10 Emission Rate (lb/MMBtu) 0.0474 Average PM 10 Emission Rate (lb/MMBtu) a 0.015

a After completion of fabric filter installation. b Used 2004 annual averages.
c Used an average of the 2004 annual averages for Re id Gardner 1, 2, & 3. d Maximum emission rate as per evaluation of the EPA Acid Rain Database for 2001 through 2003. The primary source of fuel burned at Reid Gardner 1 is western bi tuminous coal. Coal sources and characteristics are summarized in Table 2-2.SECTION 2.0: PRESENT UNIT OPERATION

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 2-3 TABLE 2-2 Coal Sources and Characteristics Reid Gardner 1 Mines Bowie Skyline Sufco Dugout Aberdeen Crandall West Ridge
Moist. % 8.50 9.79 9.69 5.53 6.83 7.50 5.78
Ash % 9.06 7.64 7.97 8.65 8.50 8.00 7.48
Volatile Matter % 33.53 38.20 35.95 33.05 38.00 41.05 34.91

Fixed Carbon % 48.91 44.37 46.39 52.77 46.16 43.00 51.84

Sulfur % 0.46 0.57 0.29 0.51 0.51 0.45 1.35 HHV, Btu/lb 12,012 11,712 11,463 12,469 12,276 12,400 12,856

Data from report done by NV Energy January 18, 2007 , Fly Ash Conveyor System – Units 1, 2 and 3. CH2M HILL based inlet SO 2 calculations on coal from the Skyline mine since i t exhibits the highest sulfur content with the exception of West Ridge (not considered ty pical). HHV = higher heating valueDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-1 

# 3.0 BART Engineering Analysis

3.1 Applicability
In compliance with regional haze requirements, the State of Nevad a 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 5 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
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 th e economic analysis presented in Appendix A. For clarity, Appendix A also inclu des sample economic analysis spreadsheet calculations and explanation of assumption s used.SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_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. To minimize costs in the BART analysis, consideration was made o f 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 comp liance using these existing control devices. In some cases, enhancing the perform ance of the existing control equipment was considered. Other scenarios with new control equipment were also developed. Separate analyses have been conducted for NO x , SO 2 , and PM 10 emissions. All costs included in the BART analysis are in 2007 dollars, and costs have not been escalated to the assumed 2013 BART implementation date.


## 3.2.1 BART NO x 

## Analysis
NO x formation in coal-fired boilers is a complex process that is d ependent on a number of variables, including operating conditions, equipment design, a nd coal characteristics.


### 3.2.1.1 Formation of NO x During coal combustion, NO x is formed in three different ways. The dominant source of NO x formation is the oxidation of fuel-bound nitrogen (fuel NO x ). During combustion, part of the fuel-bound nitrogen is released from the coal with t he volatile matter, and part is retained in the solid portion (char). The nitrogen chemically bound in the coal is partially oxidized to nitrogen oxides (nitric oxide [NO] and nitrogen dioxide [NO 2 ]) and partially reduced to molecular nitrogen (N 2 ). A smaller part of NO x formation is due to high temperature fixation of atmospheric nitrogen in the combust ion air (thermal NO x ). 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. In a conventional pulverized coal burner, air is introduced with tur bulence to promote good mixing of fuel and air, which provides stable combustion. How ever, not all of the oxygen in the air is used for combustion. Some of the oxygen combines wit h the fuel nitrogen to form NO x . Coal characteristics directly affect NO x emissions from coal combustion. Coal ranking is a means of classifying coals according to their degree of metamorp hism in the natural series, from lignite to sub-bituminous to bituminous and on to ant hracite. Lower rank coals, such as the sub-bituminous coals from the Powder River Basin (PRB ), produce lower NO x emissions than do higher rank bituminous coals, due to their hi gher reactivity and lower nitrogen content. The fixed carbon to volatile matter ratio (fue l ratio), coal oxygen content, and rank are good relative indices of the reactivity of a coal. Lower r ank coals release moreSECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-3 organically bound nitrogen earlier in the combustion proce ss than do higher rank bituminous coals. When used with LNBs, sub-bituminous coals c reate a longer time for the kinetics to promote more stable molecular nitrogen; hence res ulting in lower NO x emissions. 

### 3.2.1.2 Step 1: Identify All Available Retrofit Con trol Technologies The first step of the BART process is to evaluate NO x control technologies with practical potential for application to Reid Gardner 1, including those co ntrol technologies identified as Best Available Control Technology (BACT) or lowest achievabl e emission rate (LAER) by permitting agencies across the United States. A broad range of information sources has been reviewed in an effort to identify potentially applicable emi ssion control technologies.
Reid Gardner 1 NO x emissions are currently controlled through the use of Fos ter Wheeler LNBs, which were installed in 1999, and OFA. Reid Gardner 1 is a wall-fi red boiler, with burners arranged in a 4-by-2 (four-high and two-wide) configur ation. The following potential NO x control technology options were considered:

• Low NO x Burners (LNB) with Overfire Air (OFA)

• Low NO x Burner (LNB) with selective non-catalytic reduction syste m (SNCR)

• Rotating Opposed Fire Air (ROFA) with Rotamix

• LNB with selective catalytic reduction (SCR) system

• ROFA with SCR 

### 3.2.1.3 Step 2: Eliminate Technically Infeasible Op tions For Reid Gardner 1, a wall-fired configuration burning primaril y bituminous coal, technical feasibility will primarily be determined by physical constrai nts, boiler configuration, and on the ability to achieve the proposed NV Energy BART Limit of 0.39 lb /MMBtu. For this BART analysis, information pertaining to LNB with OFA , ROFA with Rotamix, SNCR, and SCR was based on a combination of vendor information, inter nal CH2M HILL information, and the EPA Air Pollution Cost Control Manual. Sou rces of cost estimates for Reid Gardner 1 are listed in Table 3-1, which also summarizes the con trol technology options evaluated in this BART analysis, along with projected NO x emission rates. All technologies listed can meet the proposed NV Energy BART Lim it of 0.39 lb/MMBtu.
It should be noted that estimated emissions information from N O x technologies presented represent design targets. With a significant potential for var iability in emissions due to changes in unit operation, a longer averaging period results in a h igher probability in meeting the permit emissions value. Emissions based on a 24-ho ur averaging period are not directly comparable to emissions targets based on a longer averag ing time.SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-4 TABLE 3-1 NO x Control Technology Emission Rate Ranking Reid Gardner Station Unit 1

Technology Source of Estimated Emissions Expected Emission Rate (lb/MMBtu) c
Current Permit Limit Title V 0.46
NVE BART Limit NVEBL a 0.39 (Annual average) Enhancement of the Existing or New LNB w/OFA Foster Wheeler <0.39

LNB w/OFA and SNCR b Foster Wheeler, Fuel Tech 0.23
ROFA w/Rotamix Mobotec 0.16
LNB w/OFA and SCR Foster Wheeler 0.07
ROFA w/SCR Mobotec 0.07

a NVEBL – Based on LNB with OFA information from Fost er Wheeler b Assumes 25 percent SNCR removal efficiency.
c All emission rates are treated as expected rather t han guaranteed values. ROFA = rotating opposed fire air SCR = selective catalytic reduction SNCR selective non-catalytic reduction 

### 3.2.1.4 Step 3: Evaluate Control Effectiveness of R emaining Control Technologies Preliminary vendor proposals, such as those used to support por tions of this BART analysis, may be technically feasible and provide expected or guaranteed emission rates; however, they include inherent uncertainties. These proposals are usuall y prepared in a limited time frame, may be based on incomplete information, may contain over-opt imistic conclusions, and are non-binding. Therefore, emission rate values obtained in such preliminary proposals must be qualified, and it must be recognized that cont ractual guarantees are established only after more detailed analysis has been complet ed. Also, emission rates are typically based on a design value (i.e., 30-day rolling average) versu s a maximum 24-hour value.
Level of Confidence for Vendor Post-Control Emissions Estimates

. To determine the level of NO x emissions needed to achieve compliance consistently with an established goal, a review of typical NO x emissions from coal-fired generating units was completed. As a result of this review, it was noted that NO x emissions can vary around an average emissions level. This variance can be attributed to many reasons, including coal characteristics, unit load, boiler operation including excess air, boiler slagging, burner equipment condition, coal mill fineness, and so forth. The steps used for determining a level of confidence for th e 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.SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-5 3. Review and evaluate unit physical and operational characteristic s and restrictions. The fewer variations there are in operations, coal supply, etc., the more predictable and less variable the NO x emissions are.
4. Make adjustments to the expected value. For each technology ex pected value, there is a corresponding potential for actual NO x emissions to vary from this expected value. From the vendor information presented, along with anticipate d unit operational data, an adjustment to the expected value can be made. The following subsections describe the control technolog ies and the control effectiveness evaluated in this BART analysis. LNBs with OFA System. The mechanism used to lower NO x with LNBs is to stage the combustion process and provide a fuel-rich condition initi ally; this is so oxygen needed for combustion is not diverted to combine with nitrogen and fo rm NO x . Fuel-rich conditions favor the conversion of fuel nitrogen to N 2 instead of NO x . Additional air (or OFA) is then introduced downstream in a lower temperature zone to burn ou t the char. Enhancing the existing or installing new LNBs and OFA is considered to be a capital cost, combustion technology retrofit that may require boiler water wall tube re placement. Neural Net Boiler Controls . Information regarding neural net controls for the boiler was received from NeuCo, Inc. While NeuCo offers several neural net p roducts, CombustionOpt and SootOpt provide the potential for NO x reduction. NeuCo stated these products can be used on most boiler control systems and can be effective eve n in conjunction with other NOx reduction technologies. NeuCo predicts that Combustion Opt can reduce NOx by 15 percent, and SootOpt can provide an additional 5 to 10 percent. Becau se NeuCo does not offer guarantees on this projected emission reduction, a nomi nal reduction of 15 percent was assumed for evaluation purposes. The budgetary prices for Combu stionOpt and SootOpt were $150,000 and $175,000, respectively, with an additional $200,000 cost for a proc ess link to the unit control system. Because NeuCo does not guarantee NO x reduction, the estimated emission reduction levels provided can not be considered as r eliable projections. Therefore, neural net should be considered as a supplementary or polishing t echnology, but not on a stand-alone basis. 

### ROFA. Mobotec markets ROFA as an improved second-generation OFA sys tem. Mobotec states that the flue gas volume of the furnace is set in rotation b y asymmetrically placed air nozzles. Rotation is reported to prevent laminar flow and improve g as mixing so that the entire volume of the furnace can be used more effectively for t he combustion process. In addition, the swirling action reduces the maximum temperature of the flames and increases heat absorption. Mobotec expects that enhanced mixing will also result in reduction in hot/cold furnace zones, improved heat absorption and boiler ef ficiency, and lower carbon monoxide (CO) and NO x emissions. A typical ROFA installation will have a booster fan(s) to supp ly the high-velocity air to the ROFA boxes. Mobotec proposed one 1,000-horsepower (hp) fan for Re id Gardner 1 located at grade, which would provide hot air at all boiler loads. Mobotec does not typically provide installation services bec ause they believe that the Owner can more cost-effectively contract for these services. Howeve r, they did provide a budgetarySECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-6 price for installation labor. Mobotec provides one onsite con struction supervisor during installation 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. Mobotec provided a proposal for their Rotamix SNCR system, whic h anticipated 12 to 24 injection ports for Reid Gardner 1. The guaranteed NO x emission rate for the Rotamix system, operating in conjunction with ROFA, is 0.16 lb/MMBtu. Ammo nia slip is guaranteed at 5 parts per million (ppm) with an ammonia/urea flow rate of 70 to 110 gallons per hour.
SNCR. Selective non-catalytic reduction is generally used to achi eve modest NO x reductions on smaller units. With SNCR, an amine-based reagent such as ammonia or ur ea is injected into the furnace within a temperature range of 1,600 degrees Fahr enheit (°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 appli cations. 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 u tilization, low temperatures, or inadequate mixing, ammonia slip occurs, allowing u nreacted ammonia to create problems downstream. The ammonia may render fly ash unsalab le, 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 NO x reduction generally resulting in lower reagent utilization and higher operating cost. Reductio ns from higher baseline concentrations (inlet NO x ) are lower in cost per ton, but result in higher operating c osts, due to greater reagent consumption. A budgetary proposal was received from Fuel Tech for their ur ea-based SNCR system, which provides nominally a 25 percent reduction from baseline NO x levels. Fuel Tech proposed using 16 injectors located over three boiler levels.
SCR. SCR works on the same chemical principle as SNCR, but SCR uses a c atalyst to promote the chemical reaction. Ammonia or urea is injected into th e flue-gas stream, where it reduces NO x to nitrogen and water. Unlike the high temperatures required f or SNCR, in SCR the reaction takes place on the surface of a vanadium/titanium- based catalyst at a temperature range between 580° F and 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 fly ash in the flue gas that is leaving the boiler. The high-dust configuration is assumed for Reid Gar dner 1. In a full-scale SCR, the flue ducts are routed to a separate large reactor containing th e catalyst. With in-duct SCR, the catalyst is located in the existing gas duct, which may be expanded in the area of the catalyst to reduce flue gas flow velocity and increase flue gas residence time. Due to the higher removal rate, a full-scale SCR was used as the basis for ana lysis at Reid Gardner 1.SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-7 As with SNCR, it is generally more cost effective to reduce NO x emission levels as much as possible through combustion enhancements than to minimize t he catalyst surface area and ammonia requirements of the SCR. 

### 3.2.1.5 Step 4: Evaluate Energy and Non-Air Quality Impacts 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 OFA are not expected to impact the boiler efficiency to a large degree or forced draft fan power usage. The refore, these technologies will not have energy impacts. The Mobotec ROFA system requires installation and operation o f one 1,000-hp ROFA fan (746 kilowatts [kW ] total). Fuel Tech provided an estimated auxiliary power requi rement of 343 kW, and the same estimate was used for Rotamix. 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. Mobotec has predicted that CO emissions, and unburned carbon in the ash, commonly referred to as loss on ignition (LOI), would b e the same or lower than prior levels for the ROFA system. SNCR and SCR installation could impact the salability and dispos al of fly ash due to ammonia levels and could potentially create a visible stack plu me, which may negate other visibility improvements. Other environmental impacts inv olve 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 for the LNB with OFA, ROFA with Rotamix, SNCR, and SCR were furnished to CH2M HILL through vendor-obtained price and performance quotations. A comparison of the technologies on the basis of costs, design co ntrol efficiencies, and tons of NO x removed is summarized in Table 3-2, and the first year control cost s are presented in Figure 3-1. The complete Economic Analysis is contained in Appendix A. 

### 3.2.1.6 Step 5: Evaluate Visibility Impacts This is presented in Section 4.0, BART Modeling Analysis.SECTION 3.0: BART ENGINEERING ANALYSISDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC3-8TABLE 3-2NOxControl Cost ComparisonReid Gardner Station Unit 1Factor LNB w/OFALNB w/OFA &SNCRROFAw/RotamixLNB w/OFA &SCR ROFA w/SCRTotal Installed Capital Costs $4.4 Million $6.9 Million $7.9 Million $35.0 Million $38.5 MillionTotal First Year Fixed and Variable O&M Costs $0.1Million $0.4 Million $0.6 Million $1.0 Million $1.3MillionTotal First Year Annualized Cost $0.6 Million $1.1Million $1.5 Million $4.7 Million $5.4 MillionPower Consumption (MW)- 0.10 0.75 0.66 1.41Annual Power Usage (Million kW-Hr/Yr) - 0.8 5.6 5.010.6NOxDesign Control Efficiency 21.3% 40.9% 57.7% 81.6%81.6%Tons NOxRemoved per Year346 665 938 1,327 1,327First Year Average Control Cost ($/Ton of NOxRemoved)1,597 1,702 1,545 3,578 4,067Incremental Control Cost ($/Ton of NOxRemoved) 1,597 1,816 1,162 8,493 0O&M = operations and maintenanceThe incremental control cost for ROFA w/SCR when compared with LNB w/OFA & SCR results in a non numberas the two technologies have the same NOxremoval in tons/yearSECTION 3.0: BART ENGINEERING ANALYSISDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC3-9FIGURE 3-1First-Year Control Cost for NOXAir Pollution Control OptionsReid Gardner Station Unit 101,0002,0003,0004,0005,0006,0007,0008,0009,000LNB w/OFA LNB w/OFA & SNCR ROFA w/Rotamix LNB w/OFA &SCR ROFA w/SCRAir Pollution Control Option

Control Cost ($/Ton NOx Removed)First Year Average Control CostFirst Year Incremental Control CostSECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-10 

## 3.2.2 BART SO 2 

## Analysis
SO 2 forms in the boiler during the combustion process from the o xidation of the sulfur in the coal and is primarily dependent on coal sulfur content. The BART analysis for SO 2 emissions on Reid Gardner 1 is described below. 

### 3.2.2.1 Step 1: Identify All Available Retrofit Con trol Technologies A broad range of information sources were reviewed to ident ify potentially applicable emission control technologies for SO 2 at Reid Gardner 1. This review included control technologies identified as BACT or LAER by permitting agenci es across the United States. The following potential new SO 2 control technology options were considered:

• Dry flue gas desulfurization (FGD) system

• Dry sorbent injection

• Furnace sorbent injection

• New wet lime/limestone FGD system Because Reid Gardner currently uses a soda ash scrubber for SO 2 reduction and current removal efficiency is greater than 50 percent, the EPA BART regul ations state that cost-effective scrubber upgrades should be considered. Ther efore, the following upgrades to the existing scrubber were also considered:

• Eliminate bypass reheat

• Install liquid distribution rings

• Install perforated trays

• Use organic acid additives

• Improve or upgrade scrubber auxiliary system equipment

• Redesign spray header or nozzle configuration 

### 3.2.2.2 Step 2: Eliminate Technically Infeasible Op tions The current soda ash scrubber SO 2 emissions average approximately 0.15 lb/MMBtu or less and meet a Title V permit limit of 0.55 lb/MMBtu. Assuming an uncont rolled SO 2 emission level of 0.97 lb/MMBtu, the currently operating soda ash scrubber i s achieving a reduction of SO 2 of up to 95 percent. With the fabric filter installation, the scrub ber venturi section will be opened further to reduce draft loss through the equipmen t, and the scrubber operation will be improved to primarily remove SO 2 in the scrubber vessel. Dry FGD System. A lime spray dryer typically injects lime slurry in the top of the absorber vessel with a rapidly rotating atomizer wheel. The rapid speed of the atomizer wheel causes the lime slurry to separate into very fine droplets that interm ix with the flue gas. The SO 2 in the flue gas reacts with the calcium in the lime slurry to form dr y calcium sulfate particles. At Reid Gardner 1, this dry particulate matter would be captured dow nstream in the baghouse that is currently being constructed, along with the fl y ash. A lime spray dryer system typically produces a dry waste product suitable for land fill disposal. A dry FGD system is estimated to achieve a maximum of 90 percent SO 2 removal at Reid Gardner 1. This would result in a controlled SO 2 emission rate of 0.054 lb/MMBtu, based on an uncontrolled SO 2 emission rate of 0.97 lb/MMBtu. Therefore, this option cannot redu ceSECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-11 the current soda ash scrubber emissions of 0.05 lb SO 2 /MMBtu, and is therefore eliminated from further analysis. Dry Sodium Sorbent Injection. Dry duct injection of sodium materials, such as sodium carbonate or sodium bicarbonate, can be used to remove moderate le vels of SO 2 from flue gas. The sorbent is injected dry into the flue gas downstream o f the air heater at approximately 300oF, and the reacted and unreacted sorbent material and fly ash would be collected in the fabric filter. Maximum SO 2 removal efficiency for this technology is approximately 75 percent, far less than is now being achieved with th e soda ash scrubber, which eliminates this technology from further consideratio n. Furnace Sorbent Injection. Furnace sorbent injection consists of injecting lime or lim estone into the boiler above the combustion zone (approximately 2,200oF) o r ahead of the economizer (approximately 1,100oF). The sorbent reacts with the SO 2 in the flue gas to form calcium sulfate (CaSO 4 ), and the CaSO 4 , unreacted sorbent, and fly ash is collected in the fabric filter. While furnace sorbent injection is relati vely simple, it has a limited SO 2 removal efficiency limitation of approximately 60 percent. Because thi s is far less than the current soda ash scrubber performance, this option is eliminated from further analysis. New Wet Lime/Limestone Scrubber. A typical wet lime/limestone scrubber consists of SO 2 laden flue gas entering a scrubber vessel where it is sprayed w ith a water/calcium slurry. The calcium reacts to form calcium sulfite or sulfate, and is then either removed and disposed as scrubber waste or reclaimed as gypsum. Wet lime/lim estone scrubbers are capable of very high SO 2 removal efficiencies, with a 95 percent removal efficiency assume d for this BART analysis. Wet Soda Ash FGD System. Wet soda ash FGD systems operate by treating the flue gas in large scrubber vessels with a soda ash solution. The scrubber mixes the flue gas and alkaline reagent using a tray arrangement to distribute the reagent across the scrubber vessel. The sodium in the reagent reacts with the SO 2 in the flue gas to form sodium sulfite and sodium bisulfite, which are removed from the scrubber and disposed. The wet soda ash FGD system at Reid Gardner 1 currently achieves u p to 94 percent SO 2 removal, resulting in an average SO 2 outlet emission rate of approximately 0.15 lb/MMBtu or less. The following scrubber upgrade alternatives were inve stigated:

• Eliminate bypass reheat. With the completion of the fabric filter installation, the flue gas leaving the scrubber will not be reheated. Therefore, this scru bber upgrade option has already been implemented.

• Install liquid distribution rings. Perforated trays accomplish the same purpose of liquid distribution rings, namely better distribution of s crubber liquid.

• Install perforated trays. Reid Gardner 1 scrubber has distribution sieve trays that allo w the flue gas to bubble through the liquid. With the installation of a new fabric filter for improved particulate control ahead of the scrubber, enhanced s crubber operation is anticipated due to lessened tray pluggage from fly ash.

• Use organic acid additives. Organic acid additives such as dibasic acid (DBA) may be used to improve SO 2 removal efficiency by increasing scrubbing liquor alkalinit y;SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-12 however, any potential improvements in SO 2 removal are difficult to predict. Testing would be required to demonstrate feasibility and determine any possible impacts.

• Improve or upgrade scrubber auxiliary system equipment. With the installation of a fabric filter, particulate loading into the scrubber will be reduced. This will lessen pluggage of the scrubber trays and nozzles with fly ash, which sho uld result in improved SO 2 removal and greater reliability.

• Redesign spray header or nozzle configuration. Reduced particulate loading will reduce pluggage of scrubber nozzles, which should improve liq uid distribution and scrubber reliability. It is projected that the operation of the present wet soda ash FGD s ystem may be improved as a result of the fabric filter installation. However, even wit h incremental improvements, minimal additional improvement to the current low SO 2 emission level can be consistently expected from upgrades to the existing wet soda ash scrubber

. Table 3-3 summarizes the control technology options evaluated in t his BART analysis, along with projected SO 2 emission rates. Only scrubber upgrades and new lime/limeston e wet scrubber technology options can equal or exceed the removal e fficiency of the current wet soda ash scrubber. Therefore, only these two alternatives are co nsidered technically feasible for purposes of this analysis.

TABLE 3-3 SO 2 Control Technology Emission Rate Ranking Reid Gardner Station Unit 1

Technology Projected Emission Rate (lb/MMBtu) Estimated SO 2 Removal Efficiency (%)
Current Permit Level 0.55 N/A
NVE BART Limit 0.40 N/A
Current Wet Soda Ash Scrubber 0.15 or less 94+ Improve Existing Wet Soda Ash Scrubber Operation 0.15 or less 95

Dry Sorbent Sodium Injection 0.24 75 New Dry FGD System 0.15 or less 90 Furnace Sorbent Injection 0.39 60
New Wet Lime/Limestone Scrubber 0.15 or less 95 FGD = flue gas desulfurization


### 3.2.2.3 Step 3: Evaluate Control Effectiveness of R emaining Control Technologies When evaluating the control effectiveness of SO 2 reduction technologies, each option can be compared against benchmarks of performance. The projected emiss ion rate for an upgraded wet soda ash FGD system for Reid Gardner 1 is 95 percent SO 2 removal or less than 0.15 lb/MMBtu, while a new wet lime/limestone scrubber instal lation would have similar removal efficiency.SECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-13 Essentially the same level of SO 2 reduction can be achieved through scrubber upgrades and new wet scrubber installation. Therefore, the new wet lime/li mestone scrubber option is eliminated because little additional scrubber capital or operati ng cost is required by improving the current wet soda ash scrubber. 

### 3.2.2.4 Step 4: Evaluate Energy and Non-Air Quality Impacts 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 . Upgrading the existing wet soda ash FGD system operation will not require additional power. Environmental Impacts . There will be no environmental impacts due to improving the current wet soda ash scrubber operation. Economic Impacts . There will be no economic impacts due to improving the curre nt wet soda ash scrubber operation. 

### 3.2.2.5 Step 5: Evaluate Visibility Impacts This is presented in Section 4.0, “BART Modeling Analysis.”


## 3.2.3 BART PM 10 

## Analysis Reid Gardner 1 is currently equipped with a mechanical collecto r and a venturi/tray wet soda ash scrubber for both particulate and SO 2 control. However, as part of the planned environmental upgrade on Reid Gardner 1, the mechanical collect or is being removed and a new fabric filter is being installed. The BART analysis for PM 10 emissions at Reid Gardner 1 is described below. For the modeling analysis in Section 4.0, PM 10 was used as an indicator for PM, and PM 10 includes particulate matter less than 2.5 microns in aerodynamic diameter (PM 2.5 ) as a subset. 

### 3.2.3.1 Step 1: Identify All Available Retrofit Con trol Technologies Three retrofit control technologies have been identifie d for additional PM 10 control:

• Fabric filter

• Upgrade existing mechanical collector

• Electrostatic precipitator 

### 3.2.3.2 Step 2: Eliminate Technically Infeasible Op tions Fabric Filter. A fabric filter retrofit project is currently planned to be installed by July 1, 2010, on Reid Gardner 1 with guaranteed filterable particulate emi ssions from the fabric filter of 0.015 lb/MMBtu. Upgrade Existing Mechanical Collector. With the planned fabric filter installation, the mechanical collector internals will be removed to eliminat e the pressure drop and allow the full range of particulate sizing to the fabric filter. In addition , any upgrade to the mechanicalSECTION 3.0: BART ENGINEERING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 3-14 collector would not meet the level of emissions reduction p ossible with a fabric filter. Therefore, an upgrade of the mechanical collector is not feasib le or desirable. New Electrostatic Precipitator. An installation of a new electrostatic precipitator is not justified because the potential level of emissions reductio n is not as great as with the fabric filter installation currently planned. 

### 3.2.3.3 Step 3: Evaluate Control Effectiveness of R emaining Control Technologies The guaranteed PM 10 control technology emission rate is 0.015 lb/MMBtu. 

### 3.2.3.4 Step 4: Evaluate Energy and Non-Air Quality Impacts 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. While there will be additional fan horsepower to overcome pr essure drop from a fabric filter installation, this will be more than offse t by the reduction in pressure drop from both the venturi section of the wet scrubber and the removal of the mechanical collector. Therefore, a fabric filter installation is expect ed to result in a net energy reduction required for operation. Environmental Impacts. There are no environmental impacts expected from the installat ion of a fabric filter. Economic Impacts. Because the planned fabric filter project is considered t o be BART, a comparison of technologies on the basis of costs, design con trol efficiencies, and tons of PM 10 removed was not done. Cost for the fabric filter is summarized i n Table 3-4. The complete Economic Analysis is contained in Appendix A.

TABLE 3-4 PM 10 Control Cost Reid Gardner Station Unit 1 Factor / Control Option Fabric Filter Total Installed Capital Costs $23.5 Million Total First Year Fixed and Variable O&M Costs $0.6 Million
Total First Year Annualized Cost $3.1 Million



### 3.2.3.5 Step 5: Evaluate Visibility Impacts This is presented in Section 4.0, BART Modeling Analysis.DEN/ES072007003/REID_GARDNER_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 Reid Gardner Station Units 1, 2, and 3. 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.SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_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 L ambert 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 Reid Gardner Power Plant. Grid resolution for this dom ain 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.SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 4-3 FIGURE 4-1 Reid Gardner Power Plant, CALMET/CALPUFF DomainSECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 4-4 Table 4-1 lists the key user-specified options.

TABLE 4-1 User-Specified CALMET Options

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).SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 4-5 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 a 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 USG S 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.SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_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 b y 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. Non e of the emission controls included in this BART analysis would substantiall y 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; J uly 6, 2005, pg. 9129): “The emissions estimates used in the models are intended to reflec t steady-state operating conditions during periods of high-capacity utiliz ation. We do not generally recommend that emissions reflecting periods of start-up, shu tdown, and malfunction be used...”
CH2M HILL selected the emissions rates used in the WRAP RMC m odeling as the Precontrol (baseline) emission rates. The WRAP PM 10 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)SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_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 and PM 10 emission rates which are 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 and PM 10 emission rates which are 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/longi tude 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 Reid Gardner Power Pl ant, discrete receptors for the CALPUFF modeling were taken from the NPS dat abase for Class I area modeling receptors. The entire area of each Class I area that is with in or intersects the 300-km circle (Figure 3-1) were included in the modeling analys is. The following lists the Class I areas that were modeled for the Reid Gardner facility:

• Bryce Canyon National Park (NP) (Brca)

• Grand Canyon NP (Grca)

• Joshua Tree NM (Jotr)

• Sycamore Canyon Wilderness (Syca)

• Zion NP (Zion) 

# 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) chan ge relative to natural background. Default extinction coefficients for each specie s, as shown below, were used.

• Ammonium sulfate 3.0

• Ammonium nitrate 3.0SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 4-8 • 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 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 2003.


# 4.6 Results
Input and output files for the CALMET/CALPUFF modeling and po st-processing will be provided upon request.


## 4.6.1 WRAP Verification Runs Results Tables 4-3 and 4-4 present the results of WRAP-RMC model verificat ion runs. Except for the results at Joshua Tree NP, the results show good correlation i n estimated maximum ∆dv. Much of the difference between these values is probably attribu ted to the different alignment of the LCC grids (reference discussion in Section 4. 3.1).SECTION 4.0: BART MODELING ANALYSIS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 4-9 TABLE 4-3 Results from WRAP-RMC CALPUFF Modeling for Reid Gar dner Boilers 1, 2, and 3 (WRAP 2007)
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
Grca 85 3.61 1.11 60 1.72 1.03 1.00 1.25
Zion 148 2.44 0.73 38 0.83 0.46 0.74 0.68
Brca 226 1.27 0.29 8 0.29 0.21 0.37 0.29 Syca 288 0.73 0.18 4 0.19 0.17 0.14 0.17
Jotr 292 1.56 0.70 48 0.88 0.56 0.55 0.67

TABLE 4-4 Verification CALPUFF Modeling Results
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
Grca 86 3.76 1.94 47 1.83 1.93 1.94 1.90
Zion 148 2.14 0.58 14 0.55 0.45 0.80 0.60
Brca 227 1.16 0.36 5 0.39 0.24 0.38 0.34 Syca 289 0.61 0.18 2 0.14 0.18 0.23 0.18
Jotr 292 1.92 0.86 32 1.04 0.85 0.58 0.82



## 4.6.2 BART Modeling Analysis The results and comparisons of the CALPUFF modeling for the b aseline emission rates and those for the NVE BART Limit emission rates are provided in Sec tion 5. As previously mentioned, the NO x and PM 10 emission rates modeled are in excess of the NVEBL.DEN/ES072007003/REID_GARDNER_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 Reid Gardner 1, the recommended BART con trols for NO x , SO 2 , and PM 10 are as follows:

• LNB with OFA for NO x control

• Continued wet soda ash FGD operation for SO 2 control

• Fabric filter for PM 10 control Table 5-1 compares the baseline emission control scenario with e xpected emission levels utilizing the NVE BART Limit emission levels. Because of the ba sis utilized to establish the estimated emissions rate for each of these cases, it is import ant to consider economic and dispersion modeling results for each scenario in making the o verall 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. While the NO x emission rate modeled is in excess of the current NVEBL, modeling res ults represent worst case visibility impacts. The Title V permit limit offers a more rep resentative view of maximum potential emission rates, since these are enforceable operati ng limits. Comparison of dispersion modeling results for the three scen arios are presented below.

TABLE 5-1 Modeled Emission Control Scenarios Reid Gardner Station Unit 1

Case Expected NO x Emissions (lb/MMBtu) Expected SO 2 Emissions (lb/MMBtu) Expected PM 10 Emissions (lb/MMBtu)

WRAP Baseline 0.591 0.329 0.0474
Title V Emission Limit Baseline 0.46 0.55 0.2
Scenario 1 – NVE BART Limit a 0.46 0.40 0.03

a – NO x and PM 10 emission rates higher than NVEBL 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.SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDAT IONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 5-2 TABLE 5-2 Ranking of NO x Control Scenarios by Cost Reid Gardner Station Unit 1

Rank Controls Total Annual Cost
1 LNB w/OFA $0.6 Million 2 New LNB w/OFA and SNCR $1.1 Million 3 ROFA w/Rotamix $1.5 Million 4 New LNB w/OFA and SCR $4.7 Million 5 ROFA w/SCR $5.4 Million



# 5.2 Dispersion 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 Reid Gardner Unit 1 demon strate an improvement in visibility.

TABLE 5-3 Comparison of Visibility Impacts by Class I Area Reid Gardner 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
Grca 86 0.85 0.93 0.83 19 25 19
Zion 148 0.22 0.26 0.22 3 3 2
Brca 227 0.13 0.15 0.12 0 0 0 Syca 289 0.06 0.08 0.06 0 0 0
Jotr 292 0.32 0.41 0.33 3 11 4SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDAT IONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 5-3 FIGURE 5-1 Comparison of 98 th Percentile Delta Deciview Visibility Impacts Reid Gardner 1

Comparison of 98th Percentile Delta Deciview Visibi lity Impacts Reid Gardner Unit 1

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Grand Canyon NP Zion NP Bryce Canyon NP Sycamore Canyo n W Joshua Tree NP Class I AreaDelta Deciview WRAP Basline Title V Permit Limit SPR BART LimitSECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDAT IONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 5-4 FIGURE 5-2 Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv Reid Gardner 1
Comparison of Days of Visibility Impacts Exceeding 0.5 ∆ dv Reid Gardner Unit 1

0 5 10 15 20 25 30

Grand Canyon NP Zion NP Bryce Canyon NP Sycamore Canyo n W Joshua Tree NP Class I AreaDays WRAP Baseline Title V Permit Limit SPR BART Limit

As shown in Figures 5-1 through 5-2, 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 similar.


## NO x 

## Control Scenario Visibility Modeling While visibility modeling has not been completed for the com bination of NO x , SO 2 , and PM 10 NBEBL values, Table 5-4 below compares the results for the various NO x control technologies. Results from one representative Class I area is pr ovided. Based on an evaluation of the cost per ∆dv reduction from Table 5- 4, LNB with OFA is selected as BART for Reid Gardner 1.SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDAT IONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 5-5 TABLE 5-4 Control Scenario Results for the Grand Canyon Natio nal Park Reid Gardner 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 8 0.354 0 0
1 LNB w/OFA 6 0.44 0.552 1.254

2 LNB w/OFA and

SNCR 4 0.521 1.133 2.174

3 ROFA w/Rotamix 2 0.592 1.450 2.450
4 ROFA w/SCR 0 0.698 4.747 6.801
5 LNB w/OFA and SCR 0 0.698 5.395 7.729



# 5.3 Recommendations

5.3.1 NO x 

## Emission Control LNB with OFA has been selected as the NO x reduction technology with an NVEBL of 0.39 lb/MMBtu averaged on an annual basis. A unit specific engineeri ng analysis will be performed to determine the required operational and technol ogy options to achieve the NVEBL. Due to uncertainties in future coal supply, and changes in boiler operation from the current pressurized operation to balanced draft operation, the NVEBL of 0.39 lb/MMBtu on an annual basis was established.


## 5.3.2 SO 2 

## Emission Control The use of the existing wet soda ash FGD system with a NVE BART l imit of 0.40 lb/MMBtu averaged on a 24-hour basis is selected as BART for Reid Gardner 1. Alt hough no scrubber upgrades are required to meet the NVE BART Limit, improved operat ion is anticipated due to the currently planned fabric filter installation. A unit s pecific engineering analysis will be performed to determine the required operational and technol ogy options to achieve the NVEBL.


## 5.3.3 PM 10 

## Emission Control A fabric filter is considered BART for Reid Gardner 1 based on i ts reduction in PM 10 emissions with a NVE BART Limit of 0.02 lb/MMBtu averaged on a 3-hour b asis. A unit specific engineering analysis will be performed to determin e the required operational and technology options to achieve the NVEBL.SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDAT IONS

DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 5-6 

# 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, s tate 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 a major imp act of background visibility in these Class I areas. If natural obscuration were t o reduce the reduction in visibility impacts modeled for the Reid Gardner facility, t he effect would be to increase the costs per ∆dV reduction that are presented in this report.DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 6-1 

# 6.0 References

40 CFR Part 51. 2005. Regional Haze Regulations and Guidelines for Best Availab le Retrofit Technology Determinations; Final Rule (July 6, 2005, pg 39129). United States Environmental Protection Agency. 1990. New Source Review Workshop Manual – Prevention of Significant Deterioration and Nonattainm ent Area Permitting. October 1990.
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, Fo rt 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.DEN/ES072007003/REID_GARDNER_1_10-03-08.DOC 

# AppendicesDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC APPENDIX A 

# Economic AnalysisDEN/ES072007003/REID_GARDNER_1_10-03-08.DOC APPENDIX B 

# BART Protocol