Prepared for:
Southern California Edison



# BART Determination for the Mohave Generating Station: Natural Gas Firing Options (Revised)

ENSR Corporation
October 2008
Document No.: 06200-034-500Prepared for:
Southern California Edison



# BART Determination for the Mohave Generating Station: Natural Gas Firing Options (Revised)

__________________________________________________________

Prepared By: Robert Paine and Olga Kostrova

_________________________________

Reviewed By: Ian Thomson

ENSR Corporation
October 2008
Document No.: 06200-034-500i October 2008 BART Determination for MGS: Natural Gas Firing

06200-034-500 

## Contents

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

1.0 Introduc tion ................................................................................................................... .............................1-1

2.0 Baseline Em issions ............................................................................................................. ......................2-1

2.1 Facility De scription........................................................................................................... ....................2-1

2.2 Estimated Emissions for BA RT Baseline A ssessment ......................................................................2-1

3.0 Evaluation of Alternativ e Control T echnologies ................................................................................. ..3-1

3.1 Consent Decr ee Emi ssions....................................................................................................... ..........3-1

3.2 NO X Emission Controls for Natural Gas Firing ...................................................................................3-2

3.2.1 Selective Cataly tic Reduc tion................................................................................................3- 3

3.2.2 Selective Non-Cataly tic Reducti on........................................................................................3-3

3.2.3 Flue gas Reci rculat ion......................................................................................................... ..3-4

3.2.4 Overfire Air................................................................................................................... ..........3-4

3.2.5 Low NO
x Burner s...................................................................................................................3-4

3.2.6 Burners-Out- of-Service......................................................................................................... .3-5

3.2.7 Low Excess Air ................................................................................................................. .....3-5

3.2.8 Summary of NO X Control Technica l Feasibili ty ....................................................................3-5

3.3 SO 2 Cont rol....................................................................................................................... ...................3-5

3.4 PM Control..................................................................................................................... ......................3-6

3.5 Effectiveness of the NO
x Control Op tions...........................................................................................3-6

3.6 Economic Impacts of the NO
x Control Op tions ..................................................................................3-6

3.7 Environmental Impacts of the NO
x Control Op tions ...........................................................................3-7

3.8 Energy Impacts of the NO
x Control Op tions.......................................................................................3-8

4.0 Future Emissions for BA RT Contro l Options ...................................................................................... ..4-1

4.1 Modeled Stack Parame ters....................................................................................................... ..........4-1

4.2 Estimated Emissions ............................................................................................................ ...............4-1

5.0 Visibility Modeling: CALMET Processing Pr ocedures .........................................................................5-1

5.1 WRAP CALMET Databas e ........................................................................................................... ......5-1

5.2 Enhancements to the WRAP CALMET Dat abase ............................................................................. 5-1

6.0 Visibility Modeling: CALPUFF Pr ocedures ........................................................................................ ....6-1

6.1 CALPUFF Modeli ng Proc edures.................................................................................................... .....6-1ii October 2008 BART Determination for MGS: Natural Gas Firing

06200-034-500 6.2 Natural Conditions and Monthly f(RH) at Cla ss I Areas .....................................................................6-3

6.3 Light Extinction and Haze Impact Calc ulations .................................................................................. 6-3

7.0 CALPUFF Visibility Modeling R esults............................................................................................ .........7-1

7.1 Affected Cl ass I Areas......................................................................................................... ................7-1

7.2 Baseline CALPUFF M odeling Re sults.............................................................................................. ..7-3

7.3 CALPUFF Modeling Results for BART Control Options ....................................................................7-4

8.0 Final BART Dete rminat ion....................................................................................................... .................8-1

8.1 Evaluation of BART Control Options ............................................................................................. .....8-1

8.2 Conclu sions .................................................................................................................... .....................8-3

9.0 Refere nces..................................................................................................................... .............................9-1



## List of Appendices

Appendix A - NO
x BART Review for the Mohave Generating Station

Appendix B - Guidance on CALMET Settings

Appendix C - Factors Influencing NO
x Emissions Effects on Visibility

Appendix D - Re-Calculating CALPOST Visibili ty Outputs with the New IMPROVE Algorithm

Appendix E - CALPUFF Modeling Results and Graphic Charts using the New IMPROVE Equation

Appendix F - CALPUFF Modeling Results and Graphic Charts using the Old IMPROVE Equation

Appendix G - Projected NO
x Emissions on Natural Gas Over Mohave’s Future Operating Range Based on 2005 Actual Reporting for the Mohave Generating Stationiii October 2008 BART Determination for MGS: Natural Gas Firing

06200-034-500 

## List of Tables

Table 2-1 Peak Daily Base line Emissions.................................................................................................. ..2-1

Table 2-2 MGS Baseline Sta ck Parame ters ................................................................................................2- 2

Table 2-3 MGS Baseline Emissions Used for Mode ling..............................................................................2-3

Table 3-1 Consent Decree Em ission Rates.................................................................................................3 -2

Table 3-2 Emissions Control Effectiveness of NO
x Control Op tions...........................................................3-6

Table 3-3 Annual Capacity Factor for M ohave Units 1 and 2......................................................................3-9

Table 3-4 Cost Effectiveness of NO
x Control Op tions .................................................................................3-9

Table 4-1 MGS Natural Gas Firing Stack Parame ters ................................................................................4-2

Table 4-2 MGS BART Option 1 Emissions..................................................................................................4- 2

Table 4-3 MGS BART Option 2 Emissions..................................................................................................4- 3

Table 4-4 MGS BART Option 3 Emissions..................................................................................................4- 3

Table 4-5 MGS BART Option 4 Emissions..................................................................................................4- 4

Table 4-6 MGS BART Option 5 Emissions..................................................................................................4- 4

Table 6-1 Annual Average Natural Concentra tions of Aerosol Components ( μ g/m 3 ) ................................6-3

Table 7-1 Regional Haze Impacts Due to Baseline E missions ...................................................................7-3

Table 7-2 Regional Haze Results of Modeled BART Options .....................................................................7-6

Table 8-1 Summary for BART Analysis for NO
x ..........................................................................................8-8



## List of Figures

Figure 5-1 Location of Surface and Upper Air Stati ons used for Arizona CA LMET Domain ......................5-3

Figure 5-2 CALMET Wind Fields wi th WRAP Sett ings.................................................................................5-4

Figure 5-3 CALMET Wind Fields wi th ENSR Se ttings..................................................................................5-5

Figure 6-1 MGS CALPUFF Computational Grid Rela tive to the WRAP Arizona Doma in...........................6-2

Figure 7-1 Class I Areas within 300 km of t he Mohave Generati ng Station ................................................7-2

Figure 7-2 8 th Highest Regional Haze Impacts for Each M odeled Year Due to Ba seline Emissions .........7-4

Figure 7-3 8 th Highest Visibility Impacts due to Five NO
x Control Op tions...................................................7-8

Figure 7-4 Total Number of Days Removed Above 0.5 de lta-dv Relative to the Baseline Case................7-9

Figure 7-5 Number of Days Removed at Each Class I Area Above 0.5 delta-dv Relative to the
Baseline Case.................................................................................................................. ...........7-10

Figure 8-1 Annual Cost of NO
x Controls vs. Visibility Improvements at the Closest Class I Areas ............8-4

Figure 8-2 Annual Cost of NO
x Controls vs. Visibility Improvem ents at the Other California
Class I Areas .................................................................................................................. ..............8-5

Figure 8-3 Annual Cost of NO
x Controls vs. Visibility Improvem ents at the Other Non-California
Class I Areas .................................................................................................................. ..............8-6

Figure 8-4 NO
x Control Options Cost Effectiv eness ..................................................................................... 8-7ES-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Executive Summary

The Southern California Edison (SCE) Mohave Generatin g Station (MGS) has been identified as a Best Available Retrofit Technology (BART)-eligible source by the Nevada Division of Environmental Protection (NDEP). The MGS is located near the southern tip of Clark County, Nevada. The station has two units capable of either coal or natural gas firing, each with a net rated capacity of 790 megawatts. Commercial operation began in 1971. The affected units include two bo ilers, historically fired wi th coal, referred to as Units 1 and 2. While these units have generally fired c oal, they also have full load natural gas firing capability, or a combination of coal and natural gas firing at full load. The Nevada BART program requires that BART-eligible Electric Generating Unit s (EGU) that cause or contribute to visibility impairment must perform a site-specific BART dete rmination analysis.

In December 2007, Southern California Edison subm itted a BART report (ENSR, 2007) addressing emission control options for coal-fired operation. This anal ysis included a control technology review and CALPUFF modeling analysis to assess the visibi lity impact of the candidate BART c ontrol options. The BART analysis report documented the control technology options and modeling assessment conducted for the MGS.

The station is currently in a temporary period of non-ope ration. SCE has identified a prospective buyer for the MGS who has agreed in principle to an operation that involves dedicated natural gas firing and retirement of the coal firing capability for this facility that would be reflected in a revision to Mohave’s Class I (Title V) Operating Permit. Therefore, this supplemental BART report for MGS addresses future control options that involve only natural gas firing emission scenarios. Because firing of pipeline-quality natural gas inherently
results in minimal SO 2 and PM 10 emissions, this review of BART controls focuses upon emission options for
NO
x .

SCE has been involved in discussions with the NDEP to agree upon a suitably complete list of NO
x BART control options for this prospective future operation of MGS Units 1 and 2. These options include one or more of the following technologies: low-NO
x burners (LNB), overfire air (OFA ), selective non-catalytic reduction (SNCR), flue gas recirculation (FGR), in-line sele ctive reduction (SCR), and stand-alone SCR. An agreedupon set of five feasible BART control options are lis ted in Table ES-1, along with a summary of the BART analysis.

ENSR used the CALPUFF model with meteorological data from years 2001 through 2003 to assess potential visibility improvements due to the five candidate BART control options at the eleven Class I areas located within 300 kilometers of MGS (they are all more than 10 0 km from the project site). For each Class I area, ENSR compared the 98 th percentile value of the modeling results to the threshold of 0.5 delta-deciview (dv). On an annual basis, the 98 th percentile value implies the 8 th highest day at each modeled Class I area.

A review of the 5-step BART determination analys is provided in Table ES-1 shows the NO
x emission reductions, annualized costs, other environmental and ener gy impacts, and visibility improvements expected for each control option relative to the baseline case. Since the Baseline Case reflects implementation of the Consent Decree, which specifies controls that are applic able only for coal-fired units, the costs associated with each gas-fired option are accounted for in this BART analysis.

In its Regional Haze Final Rule Preamble, EPA estima ted ranges of cost effectiveness that were used to establish the presumptive limits for NO
x as $100 to $1000 per ton of NO

x removed. For NO
x controls, EPA stated that its presumptive NOx “limits...are based on the use of cu rrent combustion control technology. Current combustion control technology is generally, but not always, more cost-effective than post-combustion
controls such as SCRs." We note that the cost ef fectiveness of stand-alone SCR is more than $2,300 per ton

of NO
x removed, and the incremental cost effectiveness rela tive to Option 5 is almost $11,000 per ton. EPA further stated that they were “...not establishing presumpt ive limits based on the installation of SCR. AlthoughES-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 States may in specific cases find that the use of SCR is appropriate, we have not determined that SCR is generally cost-effective for BART across unit types."

The data in this report and illustra ted in Table ES-1 clearly indicates that the incremental visibility improvement for BART control options more expensiv e than Option 5 result in only minor visibility improvements at significant cost and other environmental impacts. Consistent with EPA guidance, we select Option 5 (LNB+OFA), an effective combustion control strategy, as BART.ES-3October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table ES-1 Summary of BART Analysis for NOxStep 1Step 2Step 3Step 4aStep 4bStep 5Identify ControlTechnologiesFeasibleControlTechnology?Evaluate ControlEffectiveness forTechnicallyFeasible ControlTechnologiesCalculate CostEffectivenessfor ControlTechnologies(relative tobaseline)DetermineNon-Air QualityEnvironmentaland EnergyImpactsEvaluate VisibilityImpact of Controls vs.baseline (# days > 0.5delta-dv removed, andaverage visibilityimprovement , delta-dv)IdentifyBARTControlResultsControlOption 1Low NOxburners,overfire air, and standalone SCRYes97.6% NOxreduction from coalfired baselineAnnualized cost= $50,990,000;Marginal cost eff.relative to Option5 = $11,714/tonExcess NH3emissions;higher energyuse for pressuredrop; need RMP# days > 0.5 delta-dvremoved = 1346(1),average vis. improvement= 1.11(2)delta-dvMarginalvisibilitybenefits andhigh costControlOption 2Low NOxburners,overfire air, and in-lineSCRYes94.1% NOxreduction from coalfired baselineAnnualized cost= $47,240,000;Marginal cost eff.relative to Option5 = $12,992/tonExcess NH3emissions;higher energyuse for pressuredrop; need RMP# days > 0.5 delta-dvremoved = 1345(1),average vis. improvement= 1.09(2)delta-dvMarginalvisibilitybenefits andhigh costControlOption 3Low NOxburners,overfire air, and fluegas recirculationYes83.5% NOxreduction from coalfired baselineAnnualized cost= $33,610,000;Marginal cost eff.relative to Option5 = $22,806/tonIncreased COemissions;higher energyuse for pressuredrop# days > 0.5 delta-dvremoved = 1332(1),average vis. improvement= 1.05(2)delta-dvMarginalvisibilitybenefits andhigh costControlOption 4Low NOxburners,overfire air, and SNCRYes81.1% NOxreduction from coalfired baselineAnnualized cost= $20,250,000;Marginal cost eff.relative to Option5 = $19,968/tonExcess NH3emissions; needRMP# days > 0.5 delta-dvremoved = 1327(1),average vis. improvement= 1.04(2)delta-dvMarginalvisibilitybenefits andhigh costControlOption 5Low NOxburners andoverfire airYes76.4% NOxreduction from coalfired baselineAnnualized cost= $1,500,000None# days > 0.5 delta-dvremoved = 1319(1),average vis. improvement= 1.02(2)delta-dvSelected asBART(1) Total number of days above 0.5 delta-dv removed over three meteorological years and eleven Class I areas.(2) Average 8thhighest visibility improvement over three meteorological years and eleven Class I areas.1-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 1.0 Introduction

Federal regulations under Title 40 of the Code of Federal Regulations (CFR) Part 51 Appendix Y provide guidance and regulatory authority for conducting a visi bility impairment analysis for designated eligible sources. The program requires the application of Best Available Retrofit Technology (BART) to those existing eligible sources in order to help meet the targets for visibility improvement at designated Class I areas. The BART analysis will be reviewed and us ed by the Nevada Division of Environmental Protection (NDEP) for development of the state’s Regional Ha ze State Implementation Plan (SIP). The NDEP identified the two coalfired boilers, Units 1 and 2, at Southern California Ed ison’s (SCE) Mohave Generati ng Station (MGS) as two BART-eligible emission units. The BART rules require t hat sources that are subject to BART perform a sitespecific BART analysis incl uding a control technology review and CALPUFF modeling to assess the visibility impact of the emission units. SC E submitted a BART report (ENSR, 2007) addressing coal-fired control options in December, 2007. This report addressed emissi on controls required for th e facility to continue operating as a coal-fired unit, and these contro l levels are further discussed in Section 3.

SCE has identified a prospective buyer for the MGS who has agreed in principle to a future operation that involves dedicated natural gas firing, and the retirement of the coal-firing capability fo r this facility, that would be reflected in a revision to the MGS Class I (Title V) Operating Permit. Therefore, the BART control options in this supplemental BART report for MGS involv e only natural gas firing emission scenarios.

This site-specific BART determination analysis includes the following components:

1. A list of demonstrated candidate retrofit controls that may apply.

2. A discussion of technical feasibility for retr ofit of each candidate technology to the boilers.

3. A ranking of the control effectiveness of each f easible retrofit technology, or site-specific BART options.

4. An evaluation of the impacts of eac h site-specific BART option, including:

• An estimate of the annualized cost for each of the BART options;

• An analysis of the incremental cost for each option;

• An evaluation of the impacts on visibility for eac h of the BART options or combinations of BART options;

• An evaluation of the non-air qualit y impacts of each BART option; and

• An evaluation of the energy impacts of each BART option.

5. An evaluation and justification of the mass e mission rates and averaging time in the context of modeled visibility improvements.

The regulation further requires a formal choice of BART based on the above data, including the degree of improvement in visibility (impacts), which may be reasonably anticipated to result from the installation or implementation of the proposed BART. Economic analysis, remaining useful life of the plant, and impacts on facility operation that are a cost c onsequence of air pollution control equipm ent may be considered in the final BART decision-making process.

The organization of the remainder of this report is as follows:

• Section 2 discusses baseline emissions.

• Section 3 presents a general discussion of available NO
x emission controls considered for BART.1-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 • Section 4 presents feasible NO
x control options considered for this specific BART analysis and
discusses the elements of the fi rst four factors listed above.

• Section 5 discusses meteorological processing pr ocedures for the CALPUFF analysis that was used

to determine the modeled visib ility improvements associated with each BART control option.

• Section 6 discusses the CALPUFF dispersion model ing procedures for the visibility improvement analysis.

• Section 7 presents the results of the CALPUFF modeling analysis.

• Section 8 summarizes the BART determination ana lysis and provides a BART selection decision.

• Section 9 contains references.

• Appendix A provides a discussion by the boile r engineering firm, Babcock Power Inc., of NO
x emission control options for this facility.

• Appendix B discusses relevant agency guidance (from EPA Region 9 and the National Park Service) regarding recommendations for CALPUFF system technical options for a BART determination analysis.

• Appendix C discusses the secondary fo rmation of particles from NO
x gaseous emissions and how the CALPUFF model handles this process. The di scussion provides recommendations for appropriate modeling procedures for this application.

• Appendix D provides regional haze calculations procedures using the old IMPROVE equation.

• Appendix E provides detailed CALPUFF modeling resu lts and graphic charts using the new IMPROVE equation.

• Appendix F provides detailed CALPUFF modeling re sults and graphic charts using the old IMPROVE equation.2-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 2.0 Baseline Emissions

2.1 Facility Description

The MGS is located near the southern tip of Clark County, Nevada. The station covers approximately 2,490 acres and is approximately 1 mile west and north of the Colorado River in Laughlin, Nevada. The station is located in Township 32, South Range 66 East MBD&M in Sections 22 and 23 and part of Sections 21, 24, 26, and 27. The plant site is acce ssible from Nevada State Route 163, Edison Way, and Desert Road. The station is currently in a tempor ary period of non-operation and will not operate as a coal fired power plant until pollution contro l equipment is installed. One interested party is in discussion with the plant owners to purchase the asset and return it ba ck to service as only a natural gas-fired plant.

The MGS has two units that have histor ically been coal-fired (but with natural gas firing capability as well), each rated at 790 megawatts (MW) (net). Commercial oper ation of Unit 1 and Unit 2 began in 1971. The facility was originally designed and built as a base-load plant, such that the plant was running full time unless its operations were curtailed for maintenance and other permit limitations. The boilers are each equipped with electrostatic precipitators (ESPs ) to control PM emissions.

The main EGUs are pulverized coal -fueled, tangentially fired boilers. Low-sulfur, bituminous coal has historically been supplied to the statio n via pipeline in slurry consisting of approximately 50 percent coal and 50 percent water. The coal has historically been min ed by Peabody Coal Company at Black Mesa Mine in northeastern Arizona, then crushed, mixed with wate r, and transported 273 miles through the pipeline to the

station.



### 2.2 Estimated Emissions fo r BART Baseline Assessment

The NDEP asked SCE to provide peak 24-hour actual (o r calculated) emission rates from the three Regional Haze Rule baseline years of operation that account for “high capacity utilization” during normal operating conditions. For the case of MGS, these conditions wo uld involve coal firing during the years 2001 through
2003. The baseline emissions for each of the evalua ted pollutants are presented in Table 2-1.

Table 2-1 Peak Daily Baseline Emissions

Emissions (lb/hr)

Pollutant Unit 1 Unit 2

NO X 3,731 3,425

SO 2 6,359 6,209

PM 10 357 423

The speciation of the baseline PM 10 emissions required for modeling purposes was determined using the following approach:

• Filterable PM was subdivided by size category cons istent with the default approach cited in AP-42, Table 1.1-6. For coal-fired boilers equipped with ESPs, 67 percent of the filterable PM emissions are
filterable PM 10 and 29 percent of the PM emissions are fine filterable PM 10 emissions (less than 2.5 microns in size).

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM 10 based on the best estimate for electric utility coal combustion in Table 6 of “Catal og of Global Emissions Inventories and2-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Emission Inventory Tools for Black Carbon”, Willia m Battye and Kathy Boyer, EPA Contract No. 68-D98-046, January 2002.

• Condensable PM 10 was determined using the default approach ci ted in AP-42, Table 1.1-5. For coalfired boilers equipped with ESPs, total condensable PM 10 emissions are determined from the relationship “0.1(S) - 0.03” where S is the sulfur c ontent in percent by weight. The inorganic fraction, assumed to consist of primary sulfat es, is 80 percent of the condensable PM 10 and the organic fraction is 20 percent of the condensable PM 10

.

Table 2-2 presents the stack parameters of the merged flues that were used in the modeling of baseline conditions. Table 2-3 presents the emi ssion rates, including speciation of PM 10 emissions that were used in the modeling of baseline conditions.

Table 2-2 MGS Baseline Stack Parameters

Parameter Units Units 1 & 2

UTM-X (Zone 11, NAD27) Meters 719,677

UTM-Y (Zone 11, NAD27) Meters 3,891,454

Stack Height Meters 152.4

Base Elevation Meters 216.41

Diameter Meters 9.91

Gas Exit Velocity m/s 39.16

Exit Temperature °K 449.82-3October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 2-3 MGS Baseline Emissions Used for Modeling3-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 3.0 Evaluation of Altern ative Control Technologies

The air pollutants produced during natural gas combusti on that may cause visibility impairment downwind of the plant include NO
x , SO 2 , and PM 10 . Given the nature of the fuel, conver sion of the Mohave units from coal to natural gas firing will dramatically reduce the emi ssions of all of these pollutants. Because natural gas combustion inherently minimizes SO 2 and PM 10 emissions and BACT analyses for new projects do not require additional controls for these pollutants, the discussion provided below addresses only NO
x emissions and

candidate controls.



### 3.1 Consent Decree Emissions

The future of the station is governed by a Consent De cree (CD) entered into by the owners of the MGS and is available on the Grand Canyon Trust web site at http://www.grandcanyontrust.org /programs/air/consent.php

. The CD requires new opacity and SO 2 emission limits (specified for c oal-fired units only), including the
installation of low NO X burner technology to reduce NO
x emissions and installation of a lime spray dryer in
combination with a fabric filter baghouse to reduce SO 2 and particulate matter less than 10 microns (PM 10 ) emissions. The addition of air pollution control equipment as required to meet the terms of the CD, if installed, would greatly reduce the visibility impairing pollutants emitted by the plant. These pollutants include NO
x , SO 2 , and PM 10

.

The CD controls for NO X
, SO 2
, and PM 10 emissions associated with coal-fir ed units were specified in the December 2007 BART report (ENSR, 2007a), and include the following:

• NO X – Low NO X Burners with Over-fired Air (LNB-OFA)

• SO 2 – Lime Spray Dryer (LSD)

• PM 10 – Fabric Filter (FF). The exis ting electrostatic precipitator (ESP) would remain in operation upstream of the FF.

Conformance to the Consent Decree directly establishes a mass SO 2 emission rate as listed in Table 3-1 for
the units based on coal fuel combusti on. In addition, the emission levels summarized in Table 3-1 for NO
x and

PM 10 are contained in SCE’s F ebruary 7, 2003 Application 1 for the NDEP’s Class I-B Minor Revision to the facility Class I Air Quality Operating Permit issued by the NDEP on February 28, 2003, and as revised on May 21, 2003. Also, the emission levels in Table 3-1 were provided in the Revised Title I-B Operating Permit Renewal Application dated July 2007 (ENSR 2007b). Accordingly, the emission rates in Table 3-1 are used in this BART analysis as reference emi ssion levels, that represent the expec ted level of control associated with the CD for normal operation of the coal-fired units.

1 SCE’s application for a Class I-B minor re vision to the Mohave facility Class I Air Quality Oper ating Permit included a PSD Ap plicability

Determination, which found that PSD was not applicable to the equipment changes required for Mohave to comply with the Consent
Decree and continue operation after year 2005. The NO
x and PM 10 emission rates listed in Table 3-1 are emission rate commitments
made by SCE in its February 7, 2008 Application for a Class I-B minor permit revision for Mohave operations to meet the terms o f the
Consent Decree, and to avoid triggering PSD requirements for NO
x and PM 10 at the facility. The emission rates for NO
x and PM 10 in
Table 3-1 were designed by Moha ve engineers at a level that w ould not triggering PSD Applicabilit y. Thus, while not listed as permit
emission limits in the Mohave Title V (Class I) Operating Permit, the limits for NO
x and PM 10 serve as an enforceable element of the
Class I-B minor revision to the facility Cl ass I Operating Permit issued on February 28, 2003 to avoid trigge ring PSD applicabi lity.3-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Table 3-1 Consent Decree Emission Rates

Emission Rates per Unit

Pollutant (lb/MMBtu) (lb/hr)

NO X 0.338 2,852.4

PM 10 0.025 211.0

SO 2 0.15 1,265.8

In contrast, the emission rates asso ciated with natural gas firing with no new controls on the Mohave units are expected not to exceed about 0.2 lb/MMBtu for NO
x , and about 0.002 lb/MMBtu for SO 2 and PM 10 . Therefore, the natural gas firing option, even without new controls , represents a very substant ial reduction in visibilityaffecting emissions. With respect to the Consent Decree r equirements, it is important to note that it requires that, “... If the Mohave Generating Station is converted to combust a fuel other than coal, such as natural gas, it shall not emit pollutants in greater amounts than that allowed by paragraph (d) of this section [i.e., the coalfired emission limits and control equipm ent specified in the Consent Decree].” 2 Therefore, based on the natural gas-fired emission rates stated above, the proposed conversion of Mohave to a 100% natural gas fired-power plant will re sult in uncontrolled emissions levels that will yield a substantial reduction in visibility reduction emissions when compared to t he Consent Decree Emission Rates listed in Table 3-1. It is important
to note that the NO
x controls considered for the five BART Cont rol Options evaluated in this BART evaluation
will achieve a reduction in NO
x emission rates (compared with the CD controlled emission levels listed in Table 3-1) ranging from 70% to 97% based on the proposed NO
x emission rates listed in Table 3-2 at Section 3.5

below.



### 3.2 NO X 

### Emission Controls fo r Natural Gas Firing

Nitrogen oxides (NO
x ) are formed during the combustion process of natural gas via three distinct mechanisms. The first mechanism, called “thermal” NO
x , refers to the NO
x that is formed through the oxidation of nitrogen that is present in the air supplied to co mplete the combustion process. Thermal NO
x formation is dependent on temperature, local oxygen concent rations, and residence time in the pr imary combustion zone. The second mechanism, called “fuel” NO
x , refers to the NO
x that is formed through the oxidation of the nitrogen that is chemically bound in the fuel itself. Given the nature of the fuel, there is no fuel NO
x produced during natural gas combustion. The third mechanism, “prompt” NO
x , refers to the NO
x that is formed within the flame itself from hydrocarbons that react with molecular nitrogen. Prompt NO
x represents a very small portion of the total
NO
x generated during natural gas combustion. Understanding basic NO
x formation during the combustion process is important in understanding how NO
x control technologies reduce emissions and how they affect unit operation.

There are basically two techniques that ha ve been used in reducing and controlling NO
x emissions generated by utility boilers combusting fossil f uels: (1) modifications to the combus tion process; and (2) use of chemical reagents to reduce NO
x to molecular nitrogen. Modifications to the combustion process are designed to reduce the temperature and available oxygen in the prim ary combustion zone, thereby reducing the production
of thermal NO
x . The post-combustion NO
x controls involve the chemical reaction between the NO
x and ammonia introduced to the flue gas. Both of these contro l techniques by themselves or in combination have been used throughout the industry with va rious degrees of success to reduce NO
x emissions.

2 See: 40 CFR 52.1488(d)(1). The provisions of the Consent Decree were incorporated into the Nevada Visibility SIP at 40

CFR 52.1488(d).3-3 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 The control techniques available to further reduce NO
x emissions from natural gas-f ired, utility boilers, in topdown order, include:

• Selective catalytic reduction (SCR);

• Selective non-catalytic reduction (SNCR);

• Flue gas recirculation (FGR);

• Over fire air (OFA);

• Low NO
x burners (LNB);

• Burners out of service (BOOS); and

• Low excess air (LEA).

The technical feasibility, effectiveness, and potenti al impacts of applying these post-combustion and

combustion controls to the Mohave units are addressed in the BART analysis. A detailed review of these NO
x control techniques prepared by Babcock Po wer, Inc. is provided in Appendix A.



### 3.2.1 Selective Catalytic Reduction

SCR is a post-combustion NO
x control technology that involves a ca talyst bed installed between the boiler economizer and combustion air pre-heater in a conventional natural gas-fired boiler. The temperature range of the flue gas at this point is between 600 to 800°F. Ammonia is injected into t he flue gas upstream of a precious metal catalyst bed and reduces a portion of the NO
x to molecular nitrogen and water. In-line SCR systems are typically applied to natural gas fired-units . Due to the lower velocities required for the NO
x reduction reaction to take place in the catalyst-laden reacto r, the existing ductwork is replaced with larger size ductwork. If there is insufficient space for in-lin e SCR, a stand-alone SCR may be installed adjacent to the boiler. In either case, application of SCR to a natural gas-fired boiler w ould increase overall system pressure drop (approximately 6 to 8 inches H 2 O) would require the installation of induced draft fans resulting in increased fan power consumption and loss of overall pl ant efficiency. The power loss resulting from SCR operation would need to be made up by additional power generation from this plant or from other (possibly coal-fired) plants in the region. In addition, the catalyst will oxidize some available SO 2 to SO 3 prior to stack emission, leading to additional visibili ty-affecting particulate emissions. The formation of sulfates (but not nitrates) with SCR operation is also discussed by EPA at http://www.epa.gov/ttn/catc/dir1/fscr.pdf . The

unreacted ammonia will be e mitted from the stack as ammonia slip for SCR operation. The Babcock Power Appendix A notes that ammonia slip would be estimated as 2 ppm at 3% oxygen.

SCR systems have been applied to natural gas-fired boilers throughout the country and are considered the
most effective control for the removal of NO X emissions. Depending on the uncontrolled NO
x emission levels, reductions ranging from 75 to 90 percent have been be achieved by this technology on natural gas-fired boilers. Therefore, both stand-alone and in-li ne SCR are considered technically feasible NO
x control technologies for the Mohave units under the natural gas firing configuration, although the EPA web citation
noted above does indicate that SCR retrofits on industrial boilers is “difficult and costly”.



### 3.2.2 Selective Non-Catalytic Reduction

SNCR is a post-combustion NO
x control technology that involves the injection of ammonia or urea into the flue gases without the presence of a catalyst. S NCR, like SCR, involves the reaction of NO
x with ammonia where a portion of the NO X is converted to molecular nitrogen and wate r. Without the use of a catalyst or supplemental fuel injection, the NO
x reduction reaction temperature must be tightly controlled between 1,600 and 2,200°F (between 1,600 and 1,800°F for optimum efficiency). Below 1,600°F, the ammonia will not fully react resulting in unreacted ammonia that is emitt ed into the atmosphere (referred to as ammonia slip). If the temperature rises above 2,200°F, the ammonia added will be oxidized resulting in an increased levels of
NO
x . NO
x removal efficiencies with SNCR, typically from 15 to 30 percent, are lower than SCR, depending on the combustion process. The unreacted ammonia will be emitted from the stack as ammonia slip for SNCR3-4 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 operation. The Babcock Power Appendix A notes that ammonia slip would be estimated as 6 ppm at 3% oxygen. Even with the operational complications noted above, SNCR is still consi dered a technically feasible
NO
x control technology for the Mohave units under the natural gas firing configuration.



### 3.2.3 Flue gas Recirculation

Flue gas recirculation (FGR) refers to the mixing of th e combustion products (flue gas) with combustion air to
reduce NO
x emissions. FGR lowers oxygen concentration durin g the initial stages of combustion, along with combustion temperatures. Because fl ue gas is inert, it is important that the oxygen concentration of combustion air/flue gas mixture is main tained above 17 percent to ensure that sufficient oxygen is available for the combustion of natural gas to ensure flame stability and to minimize combustible losses (e.g., CO and PM). The flue gas is typically taken from the outlet of the boi ler upstream of the air heater and then is mixed with hot combustion air exiting the air heater. The mixture is then transported to the burners (windbox) through the existing combustion air ductwork. The NO
x reduction achieved though the use of FGR depend primarily dependent on the FGR flow rate, excess air levels, burner st oichiometry, and burner/furnace heat release rate. Generally, FGR is effective in reducing thermal NO
x due to the dilution effect on the combustion process and reduction in combustion temperatures. Typically the NO
x reductions that have been achieved using FGR range are on the order of 20 to 50 percent. This NO
x control technique is considered technically feasible to control
NO
x emission from the Mohave units under the natural gas firing configuration.



### 3.2.4 Overfire Air

Overfire air (OFA) involves the use of air injection ports above the main combustion (burner) zone in the upper reaches of the furnace to divert a portion of the comb ustion air away from the prim ary combustion zone. The quantity of air that is diverted to the OFA ports typically varies from 5 to 25 percent with the primary objective being to reduce oxygen concentrations and temperatures in the primary combustion zone, thereby reducing
NO
x emissions. The air introduced through the OFA ports ensures complete combusti on. This technology has
been used in combination with other NO
x control techniques, such as LN B and FGR, on hundreds of units throughout the country to provide additional NO
x reduction. The NO
x reductions that have been achieved with OFA ports have ranged from 10 to 30 percent. This NO
x control technique is consider ed technically feasible to
control NO
x emission from the Mohave units under the natural gas firing configuration.



### 3.2.5 Low NO
x 

### Burners

Low NO
x burners (LNB) are designed to reduce NO
x emissions by controlling the mixing of fuel and air during the initial stages of combustion. The basic concept t hat forms the basis of the LNB design is to delay the mixing of the fuel and air during the initial stages of t he combustion process. This delay is achieved through the physical separation of some of the air from the fuel, or through aer odynamic means by imparting swirl to the air, or both. The production of NO
x is minimized under these condi tions since the availability (concentration) of oxygen to react with the liberat ed organically bound nitrogen is minimized. The Mohave units are tangentially-fired boilers that ar e characterized by their inherent lower NO
x emissions when compared to wall-fired boilers. In tangentially-fired boilers, the fuel and air are introduced in the corners of the combustion chamber through alternating ports. Consequently, the mixing of fuel and air is delayed resulting in lower temperatures and hence lower NO
x emissions. The use of OFA ports further delays the introduction of air in the combustion zone further reducing NO
x emissions. This NO
x control technique, therefore, is considered technically feasible to further reduce NO
x emission from the Mohave units under the natural gas firing configuration. At a steady-state, 100% rated he at input operation, LNB with OFA achieves the maximum
NO
x pounds per hour formation presented in Table 4-6. However, as load changes up or down and during3-5 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 startup and shutdown, the NO
x reduction performance will vary due to variables in combustion air control, but
in no case will the maximum NO
x pounds per hour formation listed in Table 4-6 be exceeded. 3

.



### 3.2.6 Burners-Out-of-Service

Burners-out-of-service (BOOS) is a technically proven means of achieving staged combustion reducing burner zone stoichiometry and subsequently NO
x emissions. Staged combustion in volves the generation of a fuelrich zone during the initial stages of the fuel com bustion that reduces oxygen concentration and flame temperatures. BOOS operation is accomplished by eliminat ing fuel flow to selected burners, while maintaining air flow through those burners. The fuel flow to re maining burners is increased to maintain the heat input required to produce the fuel rich atmosphere required for reducing NO
x emissions. The current Mohave units having been designed for pulverized coal firing lend t hemselves to BOOS as the existing burner corner (tangential) openings are oversized for natural gas. The proposed conversion of the units calls for the use of the excess space as overfire (OFA) ports. This NO
x control technique, therefore, is already inherent in the design of the tangentially-fire boilers to accommodate the dedicated natural gas firing.



### 3.2.7 Low Excess Air

Operating natural gas fired utility boile rs at Low excess air (LEA) operat ion with natural gas-fired boilers levels has been demonstrated to provide minor improvements in NO
x emissions. This operation reduces the amount of available oxygen in the prim ary combustion zone, lowering the overall NO
x formation stoichiometry and combustion temperatures. The Mohave units typically will operate at excess air levels ranging from 8 to12 percent by volume. Further reduci ng excess air levels could have the negative effects of decreasing boiler efficiency and increasing the combustible losses (e.g., CO and PM). This NO
x control technique, therefore, is inherent in the design of the tangentially-fire boilers under the natural gas firing configuration.



### 3.2.8 Summary of NO X 

### Control Technical Feasibility

The NO X control technologies considered te chnically feasible for application to the Mohave units under the natural gas firing configurati on include SCR, SNCR, FGR, LN B, and OFA. The other NO
x control techniques, BOOS and LEA, are inherent in the design of the t angentially-fired boilers under the natural gas firing configuration.



### 3.3 SO 2 

### Control

Sulfur dioxide is formed during natural gas combustion by the oxidation of the sulfur in the fuel. The sulfur, in the form of hydrogen sulfide (H 2 S) or mercaptans, is added to the fuel as an odorant at a rate of approximately 1.0 pound of H 2 S per million cubic feet of natural gas. The c onversion of the Mohave units from coal to dedicated natural gas combustion, therefore, will reduce SO 2 emissions from approxima tely 0.75 lb/MMBtu
under baseline conditions to 0.0019 lb/MMBtu under the natur al gas firing configuration. This corresponds to a
reduction in SO 2 emissions relative to bas eline conditions of approximat ely 99.8 percent. Given these

3 The NO x baseline emissions were based on a coal-fueled facility that was economically dispatched as a baseload system resource that would essentially run at full load for all hours available for operation. With the conversion to natural gas only operation, the units will become an economically dispatched system resource delivering energy generally in order of its cost of production as compared to other system resources. Consequently, the units will be considered intermediate and peaking system resources subject to hour-by-hour load changes and potentially multiple weekly starts and shutdowns. As explained in Appendix G, the projected NO x lb/MMBtu actual performance emission rate will be up to 0.20 lb/MMBtu during operation as MGS will be dispatched as a load following, intermediate and peaking system resource, Mohave will achieve 0.10 lb/MMBtu at full load operation, shown in Table 4-6 and an expected 0.15 lb/MMBtu rolling twelve-month average.3-6 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 extremely low SO 2 emission levels, there are no technically feas ible control technologies that are capable of further reducing SO 2 emissions under the natural gas-firing configuration.



### 3.4 PM Control

Particulates formed during natural gas combustion are products of incomplete combustion in the form of unburned carbon and condensable organics. Particulate formation may be promoted in the fuel-rich environment associated with staged combustion techniques , such as FGR or LEA. The conversion of the
Mohave units from coal to dedicated natural gas combustion will reduce PM 10 emissions from approximately
0.046 lb/MMBtu under baseline conditions to 0.0077 lb/MMBtu under the natural gas firing configuration. This corresponds to a reduction in PM 10 emissions relative to baseline c onditions of approximately 84.5 percent. Given these extremely low PM 10 emission levels, there are no technically feasible control technologies that are capable of further reducing PM 10 emissions under the natural gas-firing configuration.



### 3.5 Effectiveness of the NO x 

### Control Options

The effectiveness of the technically feasible NO
x control options is based on a review of performance data from operational plants by Babcock Powe r, Inc. Based on this review, the NO
x emission levels achievable by each control technology applied to the Mohave units u nder the natural gas firing configuration at maximum rated heat input are summarized in Table 3-2.

Table 3-2 Emissions Control Effectiveness of NO
x Control Options

Option Description NO
x Emissions
(lb/MMBtu) Reduction from coal
baseline emissions
(%)

1 LNB+OFA+SCR (Stand Alone) 0.010 4 97.6

2 LNB+OFA+SCR (In-Line) 0.025 94.1

3 LNB+OFA+FGR 0.070 83.5

4 LNB+OFA+SNCR 0.080 81.1

5 LNB+OFA 0.100 76.4



### 3.6 Economic Impacts of the NO x 

### Control Options

To determine the cost effectiveness of the NO
x control options, the direct capital and annual operating and maintenance costs associated with each control option we re estimated by Babcock Power, Inc. The direct equipment and installation capital costs then were adjust ed to account for the additional indirect costs incurred by the owner. Typical indirect owner’s costs over and above the direct procurement cost of the emissions control equipment include:

• Owner’s Engineering: 5%-15%

• Owner’s Project Management: 5%-10%

4 0.10 lb/MMBtu performance rate represents 100% thermal input NO x performance. As indicated in Appendix G, NO x performance will vary from 0.20 lb/MMBtu during startup and shutdown and from 0.07 to 0.15 lb/MMBtu in a range from 25% thermal input to 75% thermal input. Based on economic dispatch expectations, the annual 12-month rolling average

NO x performance should not exceed 0.15 lb/MMBtu, and NO x production should not exceed 788 lb/hour mass rate used in the CALPUFF modeling discussed below.3-7 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 • Project Contingency: %5-10%

• Interest During Co nstruction: 5%-10%

• Total Range of Owner’s Costs: 20%-45%

For purposes of this analysis, the owner’s indirect co sts are assumed to be 40% of direct procurement costs consistent with the Utility Air Regulatory Group’s re port “Capital Cost and Cost Effectiveness: Power Plant Emission Control Technologies.”

The annual fixed capital costs then were estimated by means of the capital recovery factor assuming an interest rate of 12 percent and an amortization period of 20 years. While other cost analyses may assume an interest rate as low as 7%, the project proponent notes t hat in the financial markets for this type of project it would be difficult to attract investors for cost of capita l rates below 12%, because the restart of MGS on natural gas and its long term competitiveness ar e speculative. Although the units ar e anticipated to have a useful life of at least 20 years (so that useful life is not a factor in the BART anal ysis), their long-term competitiveness in the electric energy market place is uncer tain. In the short term (5 years), it is anticipated that the units will be under contract and therefore the short-term outlook suppor ts restart of the units. However, beyond the initial 5-year period, the market competitiveness of the uni ts is speculative and uncertain. As a result, any

investment in emission controls needs to be evaluated on a higher return on investment during the 20-year period. It is the projec t proponents’ judgement that a 12% cost of capital is appropriate for the risks and
uncertainties associated with the return of inve stment on the emission control investments.

The annual NO
x emissions associated with the baseline case and five NO
x control options were based on the maximum hourly NO
x emission rate, the maximum heat input rate, and the annual average capacity factor. The maximum hourly NO
x emission rate for the baseline case and five NO
x control options are provided earlier in the report. The maximum heat input rates for the baseline case and five NO
x control options are 8,439 and 7,880 MMBtu/hr per unit, respectively . The annual average capacity factor is based on historical data compiled by the EPA for the most recent five-year period of full operations from 2 001 through 2005. Table 3-3 persents the actual and maximum heat input to both of th e units over this five-year period. As shown, the annual average capacity factor for each unit and the entire plant was approximately 68%.

The total annual costs were then determined by adding the annual fixed capital costs and annual O&M costs.
The cost effectiveness of the five NO
x control options then was determined by dividing the total annual cost by
the NO
x reduction associated with each control option over the baselines case. The Table 3-4 summarizes the capital and annual operating costs, as well as the cost effectiveness, for each of the NO
x control options applied to the Mohave units.



### 3.7 Environmental Impacts of the NO x 

### Control Options

One of the most significant impacts of retrofitting S CR or SNCR on the facility is the addition of ammonia or urea storage and handling systems. Anhydrous amm onia and aqueous ammonia above 20 percent are considered dangerous to human health. An accidental release of anhydrous am monia or 20-percent or greater aqueous ammonia is reportable to local, state and federal agencies. In anticipation of such an incident, the site would need to develop, implement and maintain a Risk Management Plan (RMP) and Process Safety Measures (PSM) Program. Risk communi cation to the general public typically includes a worst-case analysis with potential impacts possible at up to a mile from the facility. Even the storage of less than 20 percent anhydrous ammonia is subject to the general duty clause of the RMP Program.

Theoretically, one mole of ammonia will react with one mole of NO
x , forming elemental nitrogen and water in both SCR and SNCR. In reality, not all the inject ed reagent will react due to imperfect mixing, uneven temperature distribution, or insufficient residence time. These physical limitations may be compensated for by injecting a larger amount of ammonia than stoichio metrically required and essentially achieving the NO
x emissions at the expense of ammonia slip. The ammoni a slip associated with SCR is specified by Babcock Power, Inc. in Appendix A to be 2 ppm at 3 percent O 2 , while that associated with SNCR is specified to be 63-8 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 ppm at 3 percent O 2 . This excess ammonia will react with SO 2 and NO
x in the atmosphere to form ammonium
salts and hence increased concentrations of both PM 10 and PM 2.5

.



### 3.8 Energy Impacts of the NO x 

### Control Options

Selective catalytic reduction would consume significa ntly more electrical energy than SNCR. The higher electrical energy consumpti on for SCR operation relative to SNCR primarily is due to the power required for the increased fan static pressure required to overcome th e pressure drop across the catalyst bed, as well as for pumps and an evaporator blower. Likewise, FGR woul d also consume more electrical energy relative to other staged combustion techniques due to the increased fan static pressure required to overcome the pressure drop across the boiler. The increased emissions of criteria pollutants, po ssibly from regional coalfired power plants, required to maintain the MGS cu rrent net electrical output capability have not been incorporated into the visibility modeling, so the re viewer should be aware that any reported visibility improvements due to FGR or SCR operation do not consider this negative impact.3-9October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 3-3 Annual Capacity Factor for Mohave Units 1 and 2(a)Table 3-4 Cost Effectiveness of NOxControl Options4-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 4.0 Future Emissions fo r BART Control Options

4.1 Modeled Stack Parameters

The NO
x control options available for the Mohave units under the natural gas firing configuration that are

considered in the visibili ty modeling analysis are:

• Option 1: LNB, OFA and stand-alone SCR;

• Option 2: LNB, OFA and in-line SCR;

• Option 3: LNB, OFA and FGR;

• Option 4: LNB, OFA and SNCR; and

• Option 5: LNB and OFA.

The design and performance data for these five NO
x control options were developed by Babcock Power, Inc. as detailed in Appendix A.



### 4.2 Estimated Emissions

The conversion of the Mohave units fr om coal to natural gas firing will dramatically reduce the emissions of

PM 10 , SO 2 , and NO
x . SO2 emissions were based on a material balance assuming an H 2 S concentration of 1.0 lb per million cubic feet of natural gas. The PM 10 emissions and speciation were determined using the following approach:

• PM 10 emissions were based on the default approach cited in AP-42, Table 1.4-2. For natural gas-fired boilers, filterable PM 10 emissions are based on the emission factor of 1.9 lb/10 6 scf, while condensable

PM 10 emissions are based on the emission factor of 5.7 lb/10 6 scf of natural gas.

• For natural gas-fired boilers, elemental car bon is expected to be 6.7 percent of fine PM 10 based on the best estimate for electric utility c oal combustion in Table 6 of “Catal og of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-D-98-046, January 2002.

• Condensable inorganic PM 10 emissions, assumed to consist of H 2 SO 4 , are based on “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural-fired boilers equipped with SCR, H 2 SO 4 emissions are determined as follows:

E = (Q)(98.06/64.04)(F1+S2)(F2)

where: E is the H 2 SO 2 emission rate (lb/hr),
Q is the baseline SO 2 emission rate (lb/hr), F1 is the fuel factor (0.01 for natural gas), S2 is the SCR catalyst SO 2 oxidation rate (0.03 for natural gas) F2 is the control factor (assumed to be 1.0 given the extremely low SO 2 emissions)

Note that the inorganic PM 10 emissions are assumed to consist entirely of H 2 SO 4 . NO
x emissions formed during combustion are predominantly in the form of NO due to the fuel lean mixture associated with natural gas combustion. Because NO is only slig htly water soluble, it does not readily dissolve in water droplets available in the combustion process, thus minimizing the formation of nitric acid and

hence nitrates.

The stack parameters for Units 1 and 2 under natural ga s firing conditions are pres ented in Table 4-1. The
NO X , SO 2 , and PM 10 emissions under the five BART control opt ions then are summarized in Tables 4-2 through 4-6, respectively. As indicated in Appendix G, the maximum NO
x emission rate occurs at maximum load conditions, which is the case being modeled for the various BART options.4-2October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 4-1 MGS Natural Gas Firing Stack ParametersUnits Units 1 & 2UTM-X (Zone 11, NAD27) Meters 719,677UTM-Y (Zone 11, NAD27) Meters 3,891,454Stack Height Meters 152.4Base Elevation Meters 216.41Diameter Meters 9.91Gas Exit Velocity m/s 27.81Exit Temperature °K 395.4Table 4-2 MGS BART Option 1 Emissionsfine total fine soil EC total SO4 organicMMBtu/hr Btu/scfgr/106scflb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr1Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,Stand-Alone SCR & ESP7,880 1,000 7,000 0.010 78.80 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.91 (c) 44.69 60.57 7.07 (d)2Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,Stand-Alone SCR & ESP7,880 1,000 7,000 0.010 78.80 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.91 (c) 44.69 60.57 7.07 (d)(b) Elemental carbon is 6.7% of fine PM based on the best estimate for electric utility natural gas combustion in Table 6 of “Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer,EPA Contract No. 68-D-98-046, January 2002.(c) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural gas-fired boilers, H2SO4 emissions are determined from "(Q)(98.06/64.04)(F1+S2)(F2)" where Q is theuncontrolled SO2 emission rate (lb/hr), F1 is thefuel factor (0.01 for natural gas), and S2 is the SO2 oxidation in SCR (0.03 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be 1.0.(d) The ammonia slip resulting from SCR is assumed to be a typical value of 0.75% at 6% O2 per EPRI 2008.Unit DescriptionMax. HeatInputHigherHeatingValueFuel SulfurContentMaximum NOx Emissions Maximum SO2 EmissionsMaximum FilterablePM Emissions(a) The PM and SO2 emissions are based on the emission factors (assuming 1.0 lb of H2S per million cubic feet of natural gas) cited in Section 1.4, Natural Gas Combustion, of "Compilation of Air Pollutant Emission Factors," EPA Document No. AP-42, September 1998.NH3 Sliptotal coarseFineFilterable PM10 Condensable PM10Total PM104-3October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 4-3 MGS BART Option 2 Emissionsfine total fine soil EC total SO4 organicMMBtu/hr Btu/scfgr/106scflb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr1Natural Gas, 790 MW,Tangential-Fired, LNB, OFA, InLine SCR & ESP7,880 1,000 7,000 0.025 197.00 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.91 (c) 44.69 60.57 7.07 (d)2Natural Gas, 790 MW,Tangential-Fired, LNB, OFA, InLine SCR & ESP7,880 1,000 7,000 0.025 197.00 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.91 (c) 44.69 60.57 7.07 (d)(b) Elemental carbon is 6.7% of fine PM based on the best estimate for electric utility natural gas combustion in Table 6 of “Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer,EPA Contract No. 68-D-98-046, January 2002.(c) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural gas-fired boilers, H2SO4 emissions are determined from "(Q)(98.06/64.04)(F1+S2)(F2)" where Q is theuncontrolled SO2 emission rate (lb/hr), F1 is thefuel factor (0.01 for natural gas), and S2 is the SO2 oxidation in SCR (0.03 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be 1.0.(d) The ammonia slip resulting from SCR is assumed to be a typical value of 2% at 3% O2 per Babcock Power.Unit DescriptionMax. HeatInputHigherHeatingValueFuel SulfurContentMaximum NOx Emissions Maximum SO2 EmissionsMaximum FilterablePM Emissions(a) The PM and SO2 emissions are based on the emission factors (assuming 1.0 lb of H2S per million cubic feet of natural gas) cited in Section 1.4, Natural Gas Combustion, of "Compilation of Air Pollutant Emission Factors," EPA Document No. AP-42, September 1998.NH3 Sliptotal coarseFineFilterable PM10 Condensable PM10Total PM10Table 4-4 MGS BART Option 3 Emissionsfine total fine soil EC total SO4 organicMMBtu/hr Btu/scfgr/106scflb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr1Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,FGR & ESP7,880 1,000 7,000 0.070 551.60 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 0.002Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,FGR & ESP7,880 1,000 7,000 0.070 551.60 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 0.00(b) Elemental carbon is 6.7% of fine PM based on the best estimate for electric utility natural gas combustion in Table 6 of “Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer,EPA Contract No. 68-D-98-046, January 2002.(c) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural gas-fired boilers, H2SO4 emissions are determined from "(Q)(98.06/64.04)(F1)(F2)" where Q is the uncontrolled SO2 emission rate (lb/hr) and F1 is thefuel factor (0.01 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be1.0.Unit DescriptionMax. HeatInputHigherHeatingValueFuel SulfurContentMaximum NOx Emissions Maximum SO2 EmissionsMaximum FilterablePM Emissions(a) The PM and SO2 emissions are based on the emission factors (assuming 1.0 lb of H2S per million cubic feet of natural gas) cited in Section 1.4, Natural Gas Combustion, of "Compilation of Air Pollutant Emission Factors," EPA Document No. AP-42, September 1998.NH3 Sliptotal coarseFineFilterable PM10 Condensable PM10Total PM104-4October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 4-5 MGS BART Option 4 Emissionsfine total fine soil EC total SO4 organicMMBtu/hr Btu/scfgr/106scflb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr1Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,SNCR & ESP7,880 1,000 7,000 0.080 630.40 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 21.20 (d)2Natural Gas, 790 MW,Tangential-Fired, LNB, OFA,SNCR & ESP7,880 1,000 7,000 0.080 630.40 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 21.20 (d)(b) Elemental carbon is 6.7% of fine PM based on the best estimate for electric utility natural gas combustion in Table 6 of “Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer,EPA Contract No. 68-D-98-046, January 2002.(c) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural gas-fired boilers, H2SO4 emissions are determined from "(Q)(98.06/64.04)(F1)(F2)" where Q is the uncontrolled SO2 emission rate (lb/hr) and F1 is thefuel factor (0.01 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be1.0.(d) The ammonia slip resulting from SNCR is assumed to be a typical value of 5.0% at 3% O2 per Babcock Power.NH3 Sliptotal coarseFine(a) The PM and SO2 emissions are based on the emission factors (assuming 1.0 lb of H2S per million cubic feet of natural gas) cited in Section 1.4, Natural Gas Combustion, of "Compilation of Air Pollutant Emission Factors," EPA Document No. AP-42, September 1998.Unit DescriptionMax. HeatInputHigherHeatingValueFilterable PM10 Condensable PM10Total PM10Fuel SulfurContentMaximum NOx Emissions Maximum SO2 EmissionsMaximum FilterablePM EmissionsTable 4-6 MGS BART Option 5 Emissions5fine total fine soil EC total SO4 organicMMBtu/hr Btu/scfgr/106scflb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr1Natural Gas, 790 MW,Tangential-Fired, LNB, OFA, &ESP7,880 1,000 7,000 0.100 788.00 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 0.002Natural Gas, 790 MW,Tangential-Fired, LNB, OFA, &ESP7,880 1,000 7,000 0.100 788.00 0.0019 14.81 0.0019 14.97MaximumDailyEmissions14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.23 (c) 44.69 59.89 0.00(a) The PM and SO2 emissions are based on the emission factors (assuming 1.0 lb of H2S per million cubic feet of natural gas) cited in Section 1.4, Natural Gas Combustion, of "Compilation of Air Pollutant Emission Factors," EPA Document No. AP-42, September 1998.(b) Elemental carbon is 6.7% of fine PM based on the best estimate for electric utility natural gas combustion in Table 6 of “Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer,EPA Contract No. 68-D-98-046, January 2002.(c) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For natural gas-fired boilers, H2SO4 emissions are determined from "(Q)(98.06/64.04)(F1)(F2)" where Q is the uncontrolled SO2 emission rate (lb/hr) and F1 is thefuel factor (0.01 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be1.0.NH3 SlipFuel SulfurContentMaximum NOx Emissions Maximum SO2 EmissionsMaximum FilterablePM EmissionsUnit DescriptionMax. HeatInputHigherHeatingValueFilterable PM10 Condensable PM10Total PM10total coarseFine5The 0.10 lb/MMBtu emission rate presented in Table 4-6 is based on maximum thermal input NOxemissions. See Appendix G for an explanation of the operation of MGSon 100% natural gas fuel and at various load levels that would be expected for a load-following, intermediate and peaking generation system resource serving theSouthern California load control area. Such an operation will cause the actual NOxemission performance rate to be as highas 0.15 lb/MMBtu when averaged over anysignificant operatingtime period. The existing ESP structure will remain in place, serving only as a duct for the flue gas.5-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 5.0 Visibility Modeling: CALMET Processing Procedures

For the CALPUFF modeling, SCE followed the Wester n Regional Air Partnership (WRAP) common BART modeling protocol with the exception of the model vers ion and a few refinements to CALMET settings. These
differences are discussed below.



### 5.1 WRAP CALMET Database

The WRAP has developed six separate 4-kilometer (k m) CALMET meteorological databases for 3 years (2001-2003). The CALMET modeling domains are strategica lly designed to cover all potential BART eligible
sources within WRAP states and all PSD Class I areas with in 300 km of those sources. The extents of the six domains are shown in Figure 3-a through Figure 3- 1f of the WRAP common BART modeling protocol,

available at http://pah.cert.ucr.edu/aqm/308/bart/ WRAP_RMC_BART_Protocol_Aug15_2006.pdf . The BART modeling for MGS was done using the Arizona 4-km domain, as shown in Figure 5-1 of this report. The WRAP CALMET meteorological inputs, technical options , and processing steps are described in Sections 2 and 3 of the WRAP protocol.

USGS 3 arc-second Digital Elevation Model files were used by WRAP to generate the terrain data at 4-km resolution for input to the six CALMET runs. Likewise , the Composite Theme Grid format files using Level I USGS land use categories were used by WRAP to generate the land use data at 4-km resolution for input to
the six CALMET runs. See Sections 3.1.1.3 and 3.1. 1.4 of the WRAP common BART modeling protocol for more details on the data processing.

Three years of 36-km MM5 data (2001-2003) were used by WRAP to generate the 4-km sub-regional meteorological datasets. Section 2 of the WRAP pr otocol discusses MM5 data extraction. The BART CALPUFF modeling for MGS was done using the Arizona 4-km CALMET database wi th application-specific
modifications described in Section 5.2.

CALMET meteorological inputs, technical options, and processing steps used in this BART analysis were identical to those specified in the WRAP common BART modeling protocol with the exception of only R1, R2, and RMAX1, and the model version. These differences ar e illustrated in Figures 5-1 through 5-3 and listed in Table 5-1, and are further discussed below. Fi gure 5-1 shows the CALMET/CALPUFF modeling domain established by the WRAP for Arizona.



### 5.2 Enhancements to the WRAP CALMET Database

ENSR suggested two modifications/enhancements to t he 4-km Arizona CALMET WRAP database. They are
as follows:

The 4-km Arizona CALMET database has been produced by ENSR using the downloaded CALMET inputs
from the WRAP website http://pah.cert.ucr.edu/aqm/308/bar t/calpuff/calmet_inputs/az/ . ENSR initially ran CALMET with the setting suggested in the WRAP BART m odeling protocol. As part of ENSR’s internal quality assurance procedure, we displayed and examined th e 4-km Arizona WRAP CALMET wind fields in the visualization software CALDESK. Figur e 5-2 graphically shows wind fields with the WRAP settings for a typical hour. Arrows represent wind direction and wind s peed for that hour at 10 meter height. Circular areas in these figures with common winds and abrupt transitio ns at the edge of the circles indicate a radius of influence of surface stations, R1, which was set to 10 0 km, as suggested in the WRAP BART protocol. The R1 value was coupled with R1MAX = 50 km so that the in fluence of the surface stations is established out to 50 km and then it abruptly ends beyond that distance. Setting R1 and R1MAX to such high values is not recommended by the model developer and Federal Land Managers, especially with MM5 data resolution of 36 km with areas of complex terrain. Typically, R1 is set to a fairly small value, generally not exceeding half of the MM5 data resolution (18 km), according to recent guidance on multiple PSD projects involving CALPUFF modeling in the WRAP region from John Notar of the National Park Service (personal correspondence5-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 between John Notar of the NPS and Bob Paine of EN SR, shown in Appendix B, al ong with other relevant agency recommendations). A large R1 value results in wi nd fields surrounding surface stations that overwrite the MM5 wind fields, which do have terrain influences incorporated into them. In many instances, the extended extrapolation of the surface station data with an abrupt transition at 50 km produces opposing wind directions in adjacent grid squares at the 50 km distance.

To avoid this problematic wind field result, ENSR used a smaller R1 value of 18 km and R1MAX value of 30 km. The resulting wind fields for the same hour and height are depicted in Figure 5-3. The adjusted R1 and
R1MAX values blend the surface observations into t he MM5 observations much better, creating a more uniform wind field throughout the domain. Therefore, ENSR used the smaller R1 and R1MAX values to be more consistent with FLM guidance and due to the better performance in the wind field depiction associated

with the smaller values.

When rerunning CALMET, ENSR used the "official" E PA-approved version of CALPUFF modeling system
CALMET Version 5.8 instead of Version 6. 211 that was used by WRAP, available at http://www.src.com/calpuff/do wnload/download.htm#EPA_VERSION

.

In accordance with recent CALPUFF modeling guidance from the EPA Region IX and National Park Service, the ENSR CALMET modeling also used the technical options listed below.

• Include upper air soundings in a Step 2 analys is; the WRAP BART protocol does not include these observations. Figure 5-1 shows upper air and surface station locations.

• Set NOOBS = 0, to use both surface and upper air observations.

• Set IEXTRP = -4, to extrapolate surface wind ob servations to the upper layers using similarity theory, and ignore layer 1 from the upper air soundings.

• Set ITPROG = 1, to use surface station temp erature and the MM5 for upper air temperature interpolation.5-3 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 5-1 Location of Surface and Upper Air Stations used for Arizona CALMET Domain5-4 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 5-2 CALMET Wind Fields with WRAP Settings5-5 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 5-3 CALMET Wind Fields with ENSR Settings6-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 6.0 Visibility Mode ling: CALPUFF Procedures

This section provides a summary of the modeling procedures that were used for the refined CALPUFF analysis for the MGS.



### 6.1 CALPUFF Modeling Procedures

SCE and ENSR used the EPA-approved version of CA LPUFF (Version 5.8, Level 070623) that has been posted at http://www.src.com/calpuff/downl oad/download.htm#EPA_VERSION . Although the WRAP BART protocol mentions the use of CALPUFF version 6, the EPA’s Office of Air Quality Planning and Standards has clearly stated that the use of a version other than the official EPA version is a non-guideline application that must obtain regional EPA approval on a case-by-case basis. To avoid the need for the justification and documentation required to use a non-guide line version of the model, ENSR used the official EPA version.

The area covered by the 4-km WRAP domain for Ariz ona is shown in Figure 5-1. The BART CALPUFF modeling for MGS was done using a smaller computational grid within the WRAP domain to minimize computation time and output file size. The computatio nal grid domain is shown in Figure 6-1. This domain
includes 11 Class I areas within 300 km of the source, plus a 50-km buffer around each Class I area and a 100-km buffer around the source to assure puff recirculatio n. The receptors used for each of the Class I areas are based on the National Park Service database of Class I receptors.

For CALPUFF model technical options, inputs, and processing steps, ENSR followed the WRAP common BART protocol with the exception of the model version. Due to the long distance to the nearest Class I area, building downwash effects were not included in the CALPUFF modeling.

WRAP has developed hourly ozone measurement files for 3 years (2001-2003), available at http://pah.cert.ucr.edu/aq m/308/bart/calpuff/ozone_dat/ . Data collection and processing are described in Section 3.1.2.7 of the WRAP protocol. These ozone da ta files were used as input to CALPUFF. Ammonia background concentrations selected for use in CALPUFF are discussed in Appendix C.

As suggested by NDEP, ENSR applied both the new and old IMPROVE equations to report regional haze results for the baseline case and the five BART options using Excel spreadsheets for western US Class I areas, as supplied by Dr. Ivar Tombach. The new IMPROVE calculation system (described in Appendix D) incorporates the equation for determining light extinction from particulate concentration estimates. The old IMPROVE algorithm does not incorporate the effects of site-specific Rayleigh scattering and naturally occurring sea salt on background visibility, but the new al gorithm does account for this effect. We provide the results using the new IMPROVE equation in Appendix E and with the old IMPROVE equation in Appendix F.6-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 6-1 MGS CALPUFF Computational Grid Relative to the WRAP Arizona Domain6-3 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

### 6.2 Natural Conditions and Mont hly f(RH) at Class I Areas

There are 11 Class I areas to be modeled for the MGS BART analysis. For these Class I areas, natural background conditions must be established in order to determine a change in natural conditions related to a source’s emissions. For the modeling described in this document, ENSR used the Annual Average Natural Concentrations, listed in Table 6-1 and the monthly f(RH) values recommended by EPA (EPA 2003a,b). For each Class I area, the natural conditions and the f(RH) values to be used are consistent with the Arizona WRAP modeling.

Table 6-1 Annual Average Natural Concentrations of Aerosol Components ( μ g/m 3 )

Ammonium Sulfate 0.12

Ammonium Nitrate 0.10

Organic Carbon 0.47

Elemental Carbon 0.02

Soil 0.5

Coarse Mass 3.0



### 6.3 Light Extinction and Ha ze Impact Calculations

The CALPOST postprocessor was used for the calculation of the impact from the modeled source’s primary and secondary particulate matter concentrations on light ex tinction. The formula that is used is the existing IMPROVE/EPA formula, which is applied to determine a change in light extinction due to increases in the particulate matter component concentrations. Using the notation of CALPOST, the formula is the following:

b ext = 3 f(RH) [(NH 4 )2SO 4 ] + 3 f(RH) [NH 4 NO 3 ] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + b Ray

The concentrations, in square brackets, are in μ g/m 3 and b ext is in units of Mm -1 . The Rayleigh scattering term (b Ray ) has a default value of 10 Mm -1 , as recommended in EPA guidance for tracking reasonable progress (EPA 2003a).

The assessment of visibility impacts at the Cla ss I areas used CALPOST Method 6. Each hour’s source-caused extinction is calculated by first using the hygroscopic components of the source-caused concentrations, due to ammonium sulfate and nitrate, and monthly Class I area-specific f(RH) values. The

contribution to the total source-caus ed extinction from ammonium sulfat e and nitrate is then added to the other, non-hygroscopic components of the particulate concentration (from coarse and fine soil, secondary organic aerosols, and elemental carbon) to yiel d the total hourly source-caused extinction.7-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 7.0 CALPUFF Visibilit y Modeling Results

This section provides a summary of the modeled visibility improvement on affected Class I areas as a result of installing BART control options on MGS.



### 7.1 Affected Class I Areas

Class I areas within 300 km of the facility are shown in Figure 7-1 and include the following 11 Class I areas:

1. Grand Canyon National Park

2. Sycamore Canyon Wilderness

3. Mazatzal Wilderness

4. Pine Mountain Wilderness

5. Zion National Park

6. Joshua Tree National Monument

7. Agua Tibia Wilderness

8. San Jacinto Wilderness

9. San Gorgonio Wilderness

10. Cucamonga Wilderness

11. Domeland Wilderness

Note that Domeland Wilderness is located approximately 320 km from the MGS; however, the NPS receptor file indicates that there is at least one receptor wi thin the 300 km the of the MGS. Therefore, Domeland Wilderness was included in the regional haze modeling.7-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 7-1 Class I Areas within 300 km of the Mohave Generating Station7-3 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

### 7.2 Baseline CALPUFF Modeling Results

CALPUFF modeling results of the baseline emissions at 11 Class I areas are presented in Table 7-1 and graphically plotted in Figure 7-2. (The old IMPROVE equation results can be found in Table F-1 and Figure F1, respectively). Modeling was c onducted for all three years of CALM ET meteorological data (2001-2003). The results are reported below usi ng the new IMPROVE equation and th e old IMPROVE equation results are presented in Appendix F, which lists the tables and figu res in the main report that are counterparts in the appendix.

For each Class I area and year, Table 7-1 lists the 8 th highest delta-deciview impact. Figure 7-2 shows the 8 th
highest deciview impacts. The figure indicates that th e higher visibility impacts generally occur at Grand Canyon National Park and Joshua Tree National Monument . Higher impacts at these Class I areas occur due to their proximity to MGS.

EPA recommends in its BART Guidelines that the 98 th percentile value of the modeling results should be compared to the threshold of 0.5 decivie ws to determine if a source contri butes to visibility impairment. The Guidelines also recommend using the 98 th -percentile statistic for compari ng visibility improvements due to BART control options. On an annual basis, the 98 th percentile value implies the 8 th highest day at each
modeled Class I area.

The results of the baseline emissions analysis indicate that the Mohave units have pr edicted visibility impacts exceeding 0.5 deciviews in at least one Class I area. Therefore, per 40 CFR Part 51, Appendix Y, the MGS is presumed to be subject to BART because its emissions may reasonably be anticipated to cause or contribute to visibility impairment at a relevant Class I area. Ca ndidate BART controls are discussed in Section 3. The results of the visibility improvement modeling for t hese candidate controls are discussed in Section 7.3.

Table 7-1 Regional Haze Impacts Due to Baseline Emissions7-4 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Figure 7-2 8 th Highest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions

8th Highest Regional Haze Impacts due to Baseline Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5

Grand Canyon

NP Joshua Tree

NM Zion NP Sycamore Canyon W Agua Tibia W Cucamonga W San Gorgonio

W San Jacinto W Mazatzal W Pine Mountain

W Domeland W

Class I Area8th Highest deciview Met Year 2001

Met Year 2002

Met Year 2003

Met Year Ave 2001-2003



### 7.3 CALPUFF Modeling Results for BART Control Options

Five BART control options were modeled for each meteorological year (2001-2003) and for eleven Class I areas to determine the predicted visibility improvement fo r these candidate controls. The results presented in this section are based on the new IMPROVE equation, wh ile the old IMPROVE equation results are presented in Appendix F.

The 3-year average results of the BART control opti ons modeling are presented in Table 7-2 and graphically plotted in Figure 7-3. Figures E- 1 through E-5 shows the same statistic for each meteorological year. (The old IMPROVE equation results can be found in Table F-2 and graphically shown in Figures F-2 through F-8).

Table 7-2 shows the 8 th highest visibility results averaged over three modeled years and corresponding visibility improvements relative to the baseline case. The table also summarizes the total number of days over three years above the 0.5 delta-dv and the number of days above the 0.5 delta-dv that were reduced relative

to the baseline case.

Emission rates that were used in modeling the five BART control options are listed in Tables 4-2 through 4-6. These control scenarios, which are more fully discussed in Section 3, are:

• BART Option 1: LNB+OFA+SCR (Stand Alone)

• BART Option 2: LNB+OFA+SCR (In-Line)

• BART Option 3: LNB+OFA+FGR7-5 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 • BART Option 4: LNB+OFA+SNCR

• BART Option 5: LNB+OFA

Results for each candidate BART control option are di scussed in more detail below. The results discussion focuses on Joshua Tree Nation Park and Grand Canyon Nati onal Park because of their proximity to the MGS.

BART Option 1 : The modeling results indicate that the LNB+ OFA+SCR (Stand-Alone) controls will provide the largest visibility benefit, although not substantially more than the ot her BART options. The visibility (average 8 th highest days) is predicted to improve by 2.65 and 2. 14 delta-dv relative to the baseline case at Joshua Tree NP and Grand Canyon NP, respectively. (T his metric is used to characterize visibility improvement for the other BART options as well.) The BA RT Option 1 would result in a predicted reduction of 1346 days above 0.5 delta-dv over three years and the 11 Cl ass I areas considered in this analysis. Note that these modeling results do not account for other power generation required to make up for the parasitic losses due to the SCR operational requirements. However, this control option would create new emissions of primary sulfates (H 2 SO 4 ) and excess ammonia.

BART Option 2 : The modeling results for the LNB+OFA+SCR (In- Line) controls are very similar to BART Option 1 and show that the visibility is predicted to improve by 2.61 and 2.10 delta-dv relative to the baseline case at Joshua Tree NP and Grand Canyon NP, respectively. The BART Option 2 would result in a predicted reduction of 1345 days above 0.5 delta-dv over three year s and at the 11 modeled Class I areas. This control option is also subject to the same paras itic power requirements as Option 1.

BART Option 3 : Addition of FGR to LNB and OFA is predicted to improve visibility by 2.46 and 2.01 delta-dv

relative to the baseline case at Joshua Tree NP and Grand Canyon NP, respectively. The BART Option 3 would result in a predicted reduction of 1332 days above 0.5 delta-dv over three years and at the 11 modeled
Class I areas.

BART Option 4 : Addition of SNCR with LNB+OFA is predicted to improve visibili ty by 2.43 an d 1.98 delta-dv
relative to the baseline case at Joshua Tree NP and Gr and Canyon NP, respectively. This BART option would result in a predicted reduction of 1327 days above 0.5 delta-dv over three years and at the 11 modeled Class I

areas.

BART Option 5 : A combination of LNB+OFA emission controls is predicted to improve visibility by 2.36 and
1.94 delta-dv relative to the baseline case at Jos hua Tree NP and Grand Canyon NP, respectively, and would lead to a reduction of 1319 days above 0.5 delta-dv over three years and at the 11 modeled Class I areas.

It is noteworthy that the average 98 th percentile daily impact over the three years modeled results in a visibility impact less than 0.5 delta-dv at all Class I areas for all of the BART control options, even Option 5 (using the new IMPROVE equation). Therefore, al l of these options result in an imperceptible visibility impact.

Figure 7-4 shows the total number of days above 0.5 delta-dv removed as a result of the BART NO
x controls and Figure 7-5 shows the breakdown of the days above 0. 5 delta-dv removed at the highly impacted Class I
areas as well as at the Californ ia Class I areas and non-California Class I areas. (Figures F-9 and F-10 graphically show the results using the old IMPROVE equati on). Note that if the full height of the bars in Figure 7-4 were plotted, the heights of the bars would be virtually the same, indica ting a very small difference in improvement from the baseline case to each of thes e BART control options involving the number of days
removed for delta-dv above 0.5.7-6 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Table 7-2 Regional Haze Results of Modeled BART Options7-7 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 Table 7-2 Regional Haze Results of Modeled BART Options7-8October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 7-3 8thHighest Visibility Impacts due to Five NOxControl Options8th Highest Regional Haze Impacts due to Five BART NOx Control Options0.00.10.20.30.40.5Grand CanyonNPJoshua TreeNMZion NP SycamoreCanyon WAgua Tibia W Cucamonga W San GorgonioWSan Jacinto W Mazatzal W Pine MountainWDomeland WClass I Area

2001-03 Ave 8th Highest dvLNB+OFA+SCR (Stand Alone)LNB+OFA+SCR (In-Line)LNB+OFA+FGRLNB+OFA+SNCRLNB+OFA7-9October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 7-4 Total Number of Days Removed Above 0.5 delta-dv Relative to the Baseline Case1346131913271332134502004006008001000120014001600LNB+OFA+SCR (StandAlone)LNB+OFA+SCR (In-Line) LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days Removed7-10October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 7-5 Number of Days Removed at Each Class I Area Above 0.5 delta-dv Relative to theBaseline Case237229226218188 188 188 188103 103 103 103219 219 219 21996 96 96 96503495495497502237188103219960100200300400500600LNB+OFA+SCR (StandAlone)LNB+OFA+SCR (InLine)LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days RemovedGrand Canyon NJoshua Tree NMZion NPSycamore Canyon W5 Other CA Class I Area2 Other AZ Class I Area8-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 8.0 Final BART Determination

8.1 Evaluation of BART Control Options

To assess the relative visibility benefits of the candidate BART options, we provide plots showing the visibility improvements as a function of costs for the two closest Cl ass I areas in Figure 8-1, as well as all of the other California Class I areas in Figure 8-2 and the other non- California Class I areas in Figure 8-3. The separate figures (8-1 through 8-3) are provided to assist the reader ’s interpretation of the results. Similar figures are graphically plotted using the old IMPR OVE equation results in Figures F-11 through F-13. It is apparent from Figures 8-2 and 8-3 that these other Class I areas show ve ry low visibility impacts fr om all of the BART control options. The results for the Grand Canyon and Joshua Tr ee National Parks in Figure 8-1 indicate only modest visibility gains at great cost re lative to BART Control Option 5 for the other BART control options.

It is clear from all of these figures t hat a large visibility improvement is at tained by the restriction of fuel to natural gas and the installation of LNB and OFA. The remaining, more expensive BART control options provide some modest improvements, but at significant cost. All BART control options result in average 98 th
percentile impacts below the contribution to perceptible haze threshold of 0.5 delta-dv.

We also provide Figure 8-4 that plots the annual NO
x emissions reduction as a function of annual costs for each control options as shown in Table 3-3.

A summary of findings for each of the BART control options is presented below.

BART Control Option 1: LNB + OFA + Stand-Alone SCR

This option has the lowest NO
x emissions, but since nitrates are not the most important visibility-impairing particle species, the visibility improvement (expressed in terms of change in the average 98 th percentile day over three years modeled) relative to that of BART Option 5 is only 0. 20 delta-dv at the Grand Canyon NP and 0.29 delta-dv at Joshua Tree NP (and less at the other Class I areas). The number of days of 0.5 delta-dv reduced from the base case is nearly the same for all Class I areas.

In its Regional Haze Final Rule Preamble, EPA estima ted ranges of cost effectiveness that were used to establish the presumptive limits for NO
x as $100 to $1000 per ton of NO

x removed. For NO
x controls, EPA stated that its presumptive NOx “limits...are based on the use of cu rrent combustion control technology. Current combustion control technology is generally, but not always, more cost-effective than post-combustion
controls such as SCRs." Note from Table 3-4 that the cost effective ness of stand-alone SCR is in excess of $2,400 per ton of NO

x removed, and the incremental cost effectiveness relative to Option 5 is over $11,700 per ton. EPA further stated that they were “not establishi ng presumptive limits based on the installation of SCR. Although States may in specific cases find that the use of SCR is appropriate, we have not determined that SCR is generally cost-effective for BART across unit types." As shown in the figures in this section, the NO
x control technologies analyzed for MGS are generally cons istent with EPA’s guidance. The combustion control technologies are significantly more cost effective than post-combustion contro ls, such as SCR. It is also worth noting that the imposition of SCR, on top of the retire ment of the coal-firing capability and the other capital equipment improvements proposed could possibly require an investment in excess of what the prospective owners would be able to support. If MGS is not re-act ivated as a natural gas-fired plant, then the required electrical generation of several hundr ed megawatts from possibly more visibility-impairing pollutant sources would have the potential to adversely affect the Nev ada Regional Haze Rule State Implementation Plan (SIP) outlook for meeting the 2018 milestone. Other factors that contribute to the rejection of this option as BART

are:8-2 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 • The need to transport amm onia supplies to the plant, with the attendant hazardous air pollutant risks and additional vehicular traffic; and

• The parasitic power loss to run the SCR equi pment that will need to be made up elsewhere.

Therefore, Option 1 is rejected as BART for MGS.

BART Control Option 2: LNB + OFA + In-Line SCR

This option has the somewhat higher NO
x emissions than those of BART Opti on 1, and the costs are slightly less. Otherwise, the issues for this opti on are similar to that of Option 1. The visibility improvement relative to that of BART Option 5 is only 0.16 delta-dv at the Grand Canyon NP and 0.18 delta-dv at Joshua Tree NP (and less at the other Class I areas). The number of da ys of 0.5 delta-dv reduced fr om the base case is nearly
the same for all Class I areas.

Note from Table 3-3 that the cost effectiveness of in-line SCR is in excess of $2,300 per ton of NO

x removed, and the incremental cost effectiveness relative to Option 5 is about $13,000 per ton. The conclusions for this BART control option are basically similar to that for Option 1, and this option is rejected as BART.

BART Control Option 3: LNB + OFA + FGR

This option has notably higher NO
x emissions than those of BART Options 1 and 2, and the costs are somewhat less. Otherwise, the issues for this option ar e similar to those of Options 1 and 2, except for no requirement for ammonia injection. The visibility improvem ent relative to that of BA RT Option 5 is essentially zero delta-dv at the Grand Canyon NP and only 0.10 delta -dv at Joshua Tree NP (and less at the other Class I areas). The number of days of 0.5 delta-dv reduced from the base case is nearly the same for all Class I

areas.

Note from Table 3-3 that the cost effectiveness of this option is in excess of $1,800 per ton of NO

x removed, and the incremental cost effectiveness relative to Opti on 5 is about $22,800 per ton. This option also may

result in increased CO emissions. The conclusions for this BART control option are basically similar to those for Options 1 and 2, and this option is rejected as BART.

BART Control Option 4: LNB + OFA + SNCR

This option has higher NO
x emissions than the previous BART options 1 and 2, and the costs are somewhat less. Otherwise, the issues for this option are sim ilar to those of Options 1 and 2, with a feature of considerably higher ammonia slip. The vi sibility improvement relative to t hat of BART Option 5 is only 0.04 delta-dv at the Grand Canyon NP and 0.07 delta-dv at Jos hua Tree NP (and less at the other Class I areas). The number of days of 0.5 delta-dv reduced from the ba se case is nearly the same for all Class I areas.

Note from Table 3-3 that the cost effectiveness of this option is more than $1,100 per ton of NO

x removed, and the incremental cost effectiveness relative to Option 5 is about $20,000 per ton. Th is option requires ammonia deliveries and storage, and the attendant complications. The conclusions for this BART control option are basically similar to those of the previous opt ions, and Option 4 is rejected as BART.

BART Control Option 5: LNB + OFA

This option has higher NO
x emissions than those of the other BART options, but the costs are comparatively quite low. The CALPUFF visibility modeling result s presented in Sections 5.0 - 7.0 was performed based on the maximum expected 788 lbs NO
x per hour for each Mohave generating unit, consistent with Table 4.6, in Section 4.0. This option also results in visibility impacts at all 11 Class I areas within 300 Km of MGS that are8-3 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 below the contribution to the perceptible limit (0.5 delta-dv). The number of days of 0.5 delta-dv reduced from the base case is nearly the same for all Class I areas.

Note from Table 3-3 that the annualized cost for this option is less than $100 per ton of NO

x removed. This option represents the combustion controls cited by EPA as cost-effective for NO
x BART, and accordingly is

selected as BART.



### 8.2 Conclusions

Table 8-1 presents an overall summary of the BART determination. The data in Figures 8-1 and 8-2 clearly

indicate that the incremental visibili ty improvement for BART control options other than Option 5 result in only minor visibility improvements at signi ficant cost and other negative environmental impacts. Consistent with EPA guidance noted in Section 8.1, we select Option 5, an effective combustion control strategy, as BART.

Consistent with the CALPUFF modelin g demonstrating significant visibility improvements for affected Class I areas from BART Control Option 5, we select a NO
x BART Emissions Limit of 788 lbs/hour for each Mohave Generating Unit. In addition, consistent with the controlled NO
x performance of Mohave as a 100% natural gas generating facility, 6 we select a NO
x BART Emission Rate of 0.15 lb/MMBtu, and we select a 12-month rolling average as the method for determining compliance with both the lb/hour and lb/MMBtu BART Emission

Limits.

6 See a detailed discussion in Appendix G regarding Mohave's NOx reduction performance as a 100% natural gas fueled generating fa cility serving the Southern California load control area as a load following, intermediate and peaking system generation resource8-4October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 8-1 Annual Cost of NOxControls vs. Visibility Improvements at the Closest Class I Areas010203040500.00.51.01.52.02.53.02001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Grand Canyon NPJoshua Tree NPBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-Alone8-5October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 8-2 Annual Cost of NOxControls vs. Visibility Improvements at the Other California Class IAreas010203040500.00.10.20.30.40.50.60.70.80.91.02001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Agua Tibia WCucamonga WSan Gorgonio WSan Jacinto WDomeland WBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-Alone8-6October 2008BART Determination for MGS: Natural Gas Firing06200-034-500010203040500.00.20.40.60.81.01.21.42001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)Sycamore Canyon WMazatzal WPine Mountain WZion NPBaselineLNB+OFA+SNCRLNB+OFALNB+OFA+FGRLNB+OFA+SCRIn-LineLNB+OFA+SCRStand-AloneFigure 8-3 Annual Cost of NOxControls vs. Visibility Improvements at the Other Non-CaliforniaClass I Areas8-7October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Figure 8-4 NOxControl Options Cost EffectivenessNOx Control Options Cost Effectiveness01020304050600 5,000 10,000 15,000 20,000 25,000NOx Emissions Reduction (tons/year)

MM$/yearLNB+OFALNB+OFA+SNCRLNB+OFA+FGLNB+OFA+SCR(In-Line)LNB+OFA+SCR(Stand-Alone)Baseline8-8October 2008BART Determination for MGS: Natural Gas Firing06200-034-500Table 8-1 Summary for BART Analysis for NOxStep 1Step 2Step 3Step 4aStep 4bStep 5IdentifyControlTechnologiesFeasibleControlTechnology?EvaluateControlEffectivenessforTechnicallyFeasibleControlTechnologiesCalculate CostEffectiveness forControlTechnologies(relative to baseline)DetermineNon-Air QualityEnvironmentaland EnergyImpactsEvaluate VisibilityImpact of Controlsvs. baseline (# days >0.5 delta-dv removed,and average visibilityimprovement , deltadv)Identify BART ControlControlOption1Low NOxburners,overfire air,and standalone SCRYes97.6% NOxreduction fromcoal-firedbaselineAnnualized cost =$50,990,000;Marginal cost eff.relative to Option 5 =$11,714/tonExcess NH3emissions; higherenergy use forpressure drop;need RMP# days > 0.5 delta-dvremoved = 1346(1),average vis.improvement = 1.11(2)delta-dvMarginal visibility benefitsand high costControlOption2Low NOxburners,overfire air,and in-lineSCRYes94.1% NOxreduction fromcoal-firedbaselineAnnualized cost =$47,240,000;Marginal cost eff.relative to Option 5 =$12,992/tonExcess NH3emissions; higherenergy use forpressure drop;need RMP# days > 0.5 delta-dvremoved = 1345(1),average vis.improvement = 1.09(2)delta-dvMarginal visibility benefitsand high costControlOption3Low NOxburners,overfire air,and flue gasrecirculationYes83.5% NOxreduction fromcoal-firedbaselineAnnualized cost =$33,610,000;Marginal cost eff.relative to Option 5 =$22,806/tonIncreased COemissions; higherenergy use forpressure drop# days > 0.5 delta-dvremoved = 1332(1),average vis.improvement = 1.05(2)delta-dvMarginal visibility benefitsand high costControlOption4Low NOxburners,overfire air,and SNCRYes81.1% NOxreduction fromcoal-firedbaselineAnnualized cost =$20,250,000;Marginal cost eff.relative to Option 5 =$19,968/tonExcess NH3emissions; needRMP# days > 0.5 delta-dvremoved = 1327(1),average vis.improvement = 1.04(2)delta-dvMarginal visibility benefitsand high costControlOption5Low NOxburners andoverfire airYes76.4% NOxreduction fromcoal-firedbaselineAnnualized cost =$1,500,000None# days > 0.5 delta-dvremoved = 1319(1),average vis.improvement = 1.02(2)delta-dvSelected as BART(1)Total number of days above 0.5 delta-dv removed overthree meteorological years and eleven Class I areas.(2)Average 8thhighest visibility improvement over threemeteorological years and eleven Class I areas.9-1 October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## 9.0 References

Atkinson, D. and T. Fox. 2006. Dispersion Coeffici ents for Regulatory Air Quality Modeling in CLAPUFF. Memorandum from U.S. EPA/OAQPS to Kay T. Prince, EPA Region 4. March 16.

Battye, W. and K. Boyer. 2002. Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon, Table 6, EPA Contract No. 68-D-98-046, available at http://www.cleanairnet.org/asi a/1412/articles-37073_resource_1.pdf

.

Electric Power Research Institute. 2008. Estimating Total Sulfuric Acid Emissions from Stationary Power

Plants. Technical Update, March, 2008. Available at http://mydocs.epri.com/docs/public/000000000001016384.pdf

.

ENSR, 2007a. BART Analysis for the Mohave Gener ating Station. Document Number 06200-033-500. December, 2007.

ENSR. 2007b. Mohave Generating Station Revised Class I-B Operating Permit Renewal Application. July

2007.

Morris, R.E., S. Lau, and B. Koo. 2005. “Evaluati on of the CALPUFF Chemistry Algorithms.” Paper #1048 presented at the 98th Annual Air and Waste Management Meeting, Minneapolis, MN.

Personal correspondence between John Notar of the N PS and Bob Paine of ENSR, November 28, 2005.

Regional Haze Regulations and Guidelines for Best Ava ilable Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 70, No. 128 published July 6, 2005).

Regional Haze Regulations; Revisions to Provisions Gove rning Alternative to Source-Specific Best Available Retrofit Technology (BART) Determinations; Fina l Rule (FR Vol. 71, NO. 198 published October 13, 2006).

United States Environmental Protection Agency (EPA). 2005. 40 CFR Part 51, FRL -7925-9, RIN: 2060-AJ31, Regional Haze Regulations and Guidelines for Be st Available Retrofit Technology (BART) Determinations (Appendix Y), updated June 24, 2005

_____. 2003a. Guidance for Estimating Natural VisibilityConditions Under the Regional Haze Program, EPA454/B-03-005. September 2003.

_____. 2003b. Guidance for Tracking Progress Under t he Regional Haze Rule, EPA-454/B-03-003, Appendix A, Table A-3, September 2003.

_____. 1998. Interagency Workgroup on Air Quality M odeling (IWAQM) Phase 2 Summary Report and Recommendations for Modeling Long Range Transport Impacts, EPA-454/R-98-019, page 14,

December 1998.

_____. 1995. AP 42, Fifth Edition, Compilation of Air Po llutant Emission Factors, Vo lume 1: Stationary Point and Area Sources, January 1995.

Western Regional Air Partnership (WRAP). 2006. CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in th e Western United States. August 15, 2006.October 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix A

NO x 

## BART Review for the Mohave Generating StationOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix B

Guidance on CALMET SettingsOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix C

Factors Influencing NO x 

## Emissions Effects on VisibilityOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix D

Re-Calculating CALPOST Visibility Outputs with the New IMPROVE AlgorithmOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix E

CALPUFF Modeling Results and Gr aphic Charts using the New IMPROVE EquationOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix F

CALPUFF Modeling Results and Gr aphic Charts using the Old IMPROVE EquationOctober 2008 BART Determination for MGS: Natural Gas Firing
06200-034-500 

## Appendix G

Projected NO x 

## Emissions on Natural Gas Over Mohave’s Future Operating Range Based on 2005 Actual Reporting for the Mohave Generating Station