Prepared for: 

Southern California Edison 

BART Determination for the Mohave 

Generating Station: Natural Gas Firing 

Options (Revised) 

ENSR Corporation 

October 2008 

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

06200-034-500

Contents 

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

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

2.0 Baseline Emissions ...................................................................................................................................2-1

2.1 Facility Description...............................................................................................................................2-1

2.2 Estimated Emissions for BART Baseline Assessment ......................................................................2-1

3.0 Evaluation of Alternative Control Technologies ...................................................................................3-1

3.1 Consent Decree Emissions.................................................................................................................3-1

3.2 NOX Emission Controls for Natural Gas Firing ...................................................................................3-2

3.2.1 Selective Catalytic Reduction................................................................................................3-3

3.2.2 Selective Non-Catalytic Reduction........................................................................................3-3

3.2.3 Flue gas Recirculation...........................................................................................................3-4

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

3.2.5 Low NOx Burners...................................................................................................................3-4

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

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

3.2.8 Summary of NOX Control Technical Feasibility ....................................................................3-5

3.3 SO2 Control..........................................................................................................................................3-5

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

3.5 Effectiveness of the NOx Control Options...........................................................................................3-6

3.6 Economic Impacts of the NOx Control Options ..................................................................................3-6

3.7 Environmental Impacts of the NOx Control Options ...........................................................................3-7

3.8 Energy Impacts of the NOx Control Options.......................................................................................3-8

4.0 Future Emissions for BART Control Options ........................................................................................4-1

4.1 Modeled Stack Parameters.................................................................................................................4-1

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

5.0 Visibility Modeling: CALMET Processing Procedures .........................................................................5-1

5.1 WRAP CALMET Database .................................................................................................................5-1

5.2 Enhancements to the WRAP CALMET Database .............................................................................5-1

6.0 Visibility Modeling: CALPUFF Procedures ............................................................................................6-1

6.1 CALPUFF Modeling Procedures.........................................................................................................6-1
BART Determination for MGS: Natural Gas Firing ii October 2008

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6.2 Natural Conditions and Monthly f(RH) at Class I Areas.....................................................................6-3

6.3 Light Extinction and Haze Impact Calculations ..................................................................................6-3

7.0 CALPUFF Visibility Modeling Results.....................................................................................................7-1

7.1 Affected Class I Areas.........................................................................................................................7-1

7.2 Baseline CALPUFF Modeling Results................................................................................................7-3

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

8.0 Final BART Determination........................................................................................................................8-1

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

8.2 Conclusions .........................................................................................................................................8-3

9.0 References..................................................................................................................................................9-1

List of Appendices 

Appendix A - NOx BART Review for the Mohave Generating Station

Appendix B - Guidance on CALMET Settings

Appendix C - Factors Influencing NOx Emissions Effects on Visibility

Appendix D - Re-Calculating CALPOST Visibility 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 NOx Emissions on Natural Gas Over Mohave’s Future Operating Range Based on 

2005 Actual Reporting for the Mohave Generating Station
BART Determination for MGS: Natural Gas Firing iii October 2008

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List of Tables 

Table 2-1 Peak Daily Baseline Emissions....................................................................................................2-1

Table 2-2 MGS Baseline Stack Parameters ................................................................................................2-2

Table 2-3 MGS Baseline Emissions Used for Modeling..............................................................................2-3

Table 3-1 Consent Decree Emission Rates.................................................................................................3-2

Table 3-2 Emissions Control Effectiveness of NOx Control Options...........................................................3-6

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

Table 3-4 Cost Effectiveness of NOx Control Options .................................................................................3-9

Table 4-1 MGS Natural Gas Firing Stack Parameters ................................................................................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 Concentrations of Aerosol Components (μg/m3) ................................6-3

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

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

Table 8-1 Summary for BART Analysis for NOx ..........................................................................................8-8

List of Figures 

Figure 5-1 Location of Surface and Upper Air Stations used for Arizona CALMET Domain ......................5-3

Figure 5-2 CALMET Wind Fields with WRAP Settings.................................................................................5-4

Figure 5-3 CALMET Wind Fields with ENSR Settings..................................................................................5-5

Figure 6-1 MGS CALPUFF Computational Grid Relative to the WRAP Arizona Domain...........................6-2

Figure 7-1 Class I Areas within 300 km of the Mohave Generating Station ................................................7-2

Figure 7-2 8th Highest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions .........7-4

Figure 7-3 8th Highest Visibility Impacts due to Five NOx Control Options...................................................7-8

Figure 7-4 Total Number of Days Removed Above 0.5 delta-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 NOx Controls vs. Visibility Improvements at the Closest Class I Areas ............8-4

Figure 8-2 Annual Cost of NOx Controls vs. Visibility Improvements at the Other California 

Class I Areas ................................................................................................................................8-5

Figure 8-3 Annual Cost of NOx Controls vs. Visibility Improvements at the Other Non-California 

Class I Areas ................................................................................................................................8-6

Figure 8-4 NOx Control Options Cost Effectiveness .....................................................................................8-7 
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BART Determination for MGS: Natural Gas Firing 

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Executive Summary 

The Southern California Edison (SCE) Mohave Generating 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 boilers, historically fired with coal, referred to as 

Units 1 and 2. While these units have generally fired coal, 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 Units (EGU) that cause or contribute to visibility impairment must perform a 

site-specific BART determination analysis. 

In December 2007, Southern California Edison submitted a BART report (ENSR, 2007) addressing emission 

control options for coal-fired operation. This analysis included a control technology review and CALPUFF 

modeling analysis to assess the visibility impact of the candidate BART control 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-operation. 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 SO2 and PM10 emissions, this review of BART controls focuses upon emission options for 

NOx. 

SCE has been involved in discussions with the NDEP to agree upon a suitably complete list of NOx 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-NOx burners (LNB), overfire air (OFA), selective non-catalytic reduction 

(SNCR), flue gas recirculation (FGR), in-line selective reduction (SCR), and stand-alone SCR. An agreedupon set of five feasible BART control options are listed 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 100 km from the project site). For each Class I area, 

ENSR compared the 98th percentile value of the modeling results to the threshold of 0.5 delta-deciview (dv). 

On an annual basis, the 98th percentile value implies the 8th highest day at each modeled Class I area. 

A review of the 5-step BART determination analysis provided in Table ES-1 shows the NOx emission 

reductions, annualized costs, other environmental and energy 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 applicable 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 estimated ranges of cost effectiveness that were used to 

establish the presumptive limits for NOx as $100 to $1000 per ton of NOx removed. For NOx controls, EPA 

stated that its presumptive NOx “limits...are based on the use of current 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 effectiveness of stand-alone SCR is more than $2,300 per ton 

of NOx removed, and the incremental cost effectiveness relative to Option 5 is almost $11,000 per ton. EPA 

further stated that they were “...not establishing presumptive limits based on the installation of SCR. Although 
ES-2 October 2008

BART Determination for MGS: Natural Gas Firing 

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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 illustrated in Table ES-1 clearly indicates that the incremental visibility 

improvement for BART control options more expensive 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-3 

BART Determination for MGS: Natural Gas Firing 06200-034-500

Table ES-1 Summary of BART Analysis for NOx

Step 1 Step 2 Step 3 Step 4a Step 4b 

Identify Control 

Technologies 

Feasible 

Control 

Technology? 

Evaluate Control 

Effectiveness for 

Technically 

Feasible Control 

Technologies 

Calculate Cost 

Effectiveness 

for Control 

Technologies 

(relative to 

baseline) 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evalua

Impact o

baseline 

delta-dv 

averag

improvem

Control 

Option 1 

Low NOx burners, 

overfire air, and standalone SCR Yes 

97.6% NOx

reduction from coalfired baseline 

Annualized cost 

= $50,990,000; 

Marginal cost eff. 

relative to Option 

5 = $11,714/ton 

Excess NH3

emissions; 

higher energy 

use for pressure 

drop; need RMP 

# days 

remov

average v

= 1.1

Control 

Option 2 

Low NOx burners, 

overfire air, and in-line 

SCR 

Yes 

94.1% NOx

reduction from coalfired baseline 

Annualized cost 

= $47,240,000; 

Marginal cost eff. 

relative to Option 

5 = $12,992/ton 

Excess NH3

emissions; 

higher energy 

use for pressure 

drop; need RMP 

# days 

remov

average v

= 1.0

Control 

Option 3 

Low NOx burners, 

overfire air, and flue 

gas recirculation 

Yes 

83.5% NOx

reduction from coalfired baseline 

Annualized cost 

= $33,610,000; 

Marginal cost eff. 

relative to Option 

5 = $22,806/ton 

Increased CO 

emissions; 

higher energy 

use for pressure 

drop 

# days 

remov

average v

= 1.0

Control 

Option 4 

Low NOx burners, 

overfire air, and SNCR Yes 

81.1% NOx

reduction from coalfired baseline 

Annualized cost 

= $20,250,000; 

Marginal cost eff. 

relative to Option 

5 = $19,968/ton 

Excess NH3

emissions; need 

RMP 

# days 

remov

average v

= 1.0

Control 

Option 5 

Low NOx burners and 

overfire air Yes 

76.4% NOx

reduction from coalfired baseline Annualized cost = $1,500,000 None 

# days 

remov

average v

= 1.0

(1) Total number of days above 0.5 delta-dv removed over three meteorological years and eleven Class I areas. (2) Average 8th highest visibility improvement over three meteorological years and eleven Class I areas.
1-1 October 2008 BART Determination for MGS: Natural Gas Firing 

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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 visibility 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 used by the Nevada Division of Environmental Protection (NDEP) for 

development of the state’s Regional Haze State Implementation Plan (SIP). The NDEP identified the two coalfired boilers, Units 1 and 2, at Southern California Edison’s (SCE) Mohave Generating Station (MGS) as two 

BART-eligible emission units. The BART rules require that sources that are subject to BART perform a sitespecific BART analysis including a control technology review and CALPUFF modeling to assess the visibility 

impact of the emission units. SCE submitted a BART report (ENSR, 2007) addressing coal-fired control 

options in December, 2007. This report addressed emission controls required for the facility to continue 

operating as a coal-fired unit, and these control 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 for 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 involve 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 retrofit of each candidate technology to the boilers. 

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

options. 

4. An evaluation of the impacts of each 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 each of the BART options or combinations of BART 

options; 

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

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

5. An evaluation and justification of the mass emission 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 consequence of air pollution control equipment 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 NOx emission controls considered for BART. 
1-2 October 2008 BART Determination for MGS: Natural Gas Firing 

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• Section 4 presents feasible NOx control options considered for this specific BART analysis and 

discusses the elements of the first four factors listed above. 

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

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

• Section 6 discusses the CALPUFF dispersion modeling procedures for the visibility improvement 

analysis. 

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

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

• Section 9 contains references. 

• Appendix A provides a discussion by the boiler engineering firm, Babcock Power Inc., of NOx 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 formation of particles from NOx gaseous emissions and how the 

CALPUFF model handles this process. The discussion 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 results and graphic charts using the new IMPROVE 

equation. 

• Appendix F provides detailed CALPUFF modeling results and graphic charts using the old IMPROVE 

equation. 
2-1 October 2008

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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 accessible from Nevada State Route 163, Edison Way, and 

Desert Road. The station is currently in a temporary period of non-operation and will not operate as a coal 

fired power plant until pollution control equipment is installed. One interested party is in discussion with the 

plant owners to purchase the asset and return it back to service as only a natural gas-fired plant. 

The MGS has two units that have historically been coal-fired (but with natural gas firing capability as well), 

each rated at 790 megawatts (MW) (net). Commercial operation 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 station via pipeline in slurry consisting of approximately 50 percent coal and 

50 percent water. The coal has historically been mined by Peabody Coal Company at Black Mesa Mine in 

northeastern Arizona, then crushed, mixed with water, and transported 273 miles through the pipeline to the 

station. 

2.2 Estimated Emissions for BART Baseline Assessment 

The NDEP asked SCE to provide peak 24-hour actual (or 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 would involve coal firing during the years 2001 through 

2003. The baseline emissions for each of the evaluated pollutants are presented in Table 2-1. 

Table 2-1 Peak Daily Baseline Emissions 

Emissions (lb/hr) 

Pollutant Unit 1 Unit 2 

NOX 3,731 3,425 

SO2 6,359 6,209 

PM10 357 423 

The speciation of the baseline PM10 emissions required for modeling purposes was determined using the 

following approach: 

• Filterable PM was subdivided by size category consistent 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 PM10 and 29 percent of the PM emissions are fine filterable PM10 emissions (less than 2.5 

microns in size). 

• For coal-fired boilers, elemental carbon is expected to be 3.7 percent of fine PM10 based on the best 

estimate for electric utility coal combustion in Table 6 of “Catalog of Global Emissions Inventories and 
2-2 October 2008

BART Determination for MGS: Natural Gas Firing 

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Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-D98-046, January 2002. 

• Condensable PM10 was determined using the default approach cited in AP-42, Table 1.1-5. For coalfired boilers equipped with ESPs, total condensable PM10 emissions are determined from the 

relationship “0.1(S) - 0.03” where S is the sulfur content in percent by weight. The inorganic fraction, 

assumed to consist of primary sulfates, is 80 percent of the condensable PM10 and the organic fraction 

is 20 percent of the condensable PM10. 

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 emission rates, including speciation of PM10 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 449.8 
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BART Determination for MGS: Natural Gas Firing 06200-034-500

Table 2-3 MGS Baseline Emissions Used for Modeling 
3-1 October 2008

BART Determination for MGS: Natural Gas Firing 

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3.0 Evaluation of Alternative Control Technologies 

The air pollutants produced during natural gas combustion that may cause visibility impairment downwind of 

the plant include NOx, SO2, and PM10. Given the nature of the fuel, conversion of the Mohave units from coal 

to natural gas firing will dramatically reduce the emissions of all of these pollutants. Because natural gas 

combustion inherently minimizes SO2 and PM10 emissions and BACT analyses for new projects do not require 

additional controls for these pollutants, the discussion provided below addresses only NOx emissions and 

candidate controls. 

3.1 Consent Decree Emissions 

The future of the station is governed by a Consent Decree (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 SO2 emission limits (specified for coal-fired units only), including the 

installation of low NOX burner technology to reduce NOx emissions and installation of a lime spray dryer in 

combination with a fabric filter baghouse to reduce SO2 and particulate matter less than 10 microns (PM10) 

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 NOx, SO2, 

and PM10. 

The CD controls for NOX, SO2, and PM10 emissions associated with coal-fired units were specified in the 

December 2007 BART report (ENSR, 2007a), and include the following: 

• NOX – Low NOX Burners with Over-fired Air (LNB-OFA) 

• SO2 – Lime Spray Dryer (LSD) 

• PM10 – Fabric Filter (FF). The existing electrostatic precipitator (ESP) would remain in operation 

upstream of the FF. 

Conformance to the Consent Decree directly establishes a mass SO2 emission rate as listed in Table 3-1 for 

the units based on coal fuel combustion. In addition, the emission levels summarized in Table 3-1 for NOx and 

PM10 are contained in SCE’s February 7, 2003 Application1

 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 emission levels, that represent the expected 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 revision to the Mohave facility Class I Air Quality Operating Permit included a PSD Applicability 

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 NOx and PM10 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 of the 

Consent Decree, and to avoid triggering PSD requirements for NOx and PM10 at the facility. The emission rates for NOx and PM10 in 

Table 3-1 were designed by Mohave engineers at a level that would not triggering PSD Applicability. Thus, while not listed as permit 

emission limits in the Mohave Title V (Class I) Operating Permit, the limits for NOx and PM10 serve as an enforceable element of the 

Class I-B minor revision to the facility Class I Operating Permit issued on February 28, 2003 to avoid triggering PSD applicability. 
3-2 October 2008

BART Determination for MGS: Natural Gas Firing 

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Table 3-1 Consent Decree Emission Rates 

Emission Rates per Unit 

Pollutant (lb/MMBtu) (lb/hr) 

NOX 0.338 2,852.4 

PM10 0.025 211.0 

SO2 0.15 1,265.8 

In contrast, the emission rates associated with natural gas firing with no new controls on the Mohave units are 

expected not to exceed about 0.2 lb/MMBtu for NOx, and about 0.002 lb/MMBtu for SO2 and PM10. Therefore, 

the natural gas firing option, even without new controls, represents a very substantial reduction in visibilityaffecting emissions. With respect to the Consent Decree requirements, 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 equipment 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 result in uncontrolled emissions levels that will yield a substantial reduction in visibility 

reduction emissions when compared to the Consent Decree Emission Rates listed in Table 3-1. It is important 

to note that the NOx controls considered for the five BART Control Options evaluated in this BART evaluation 

will achieve a reduction in NOx emission rates (compared with the CD controlled emission levels listed in Table 

3-1) ranging from 70% to 97% based on the proposed NOx emission rates listed in Table 3-2 at Section 3.5 

below. 

3.2 NOX Emission Controls for Natural Gas Firing 

Nitrogen oxides (NOx) are formed during the combustion process of natural gas via three distinct mechanisms. 

The first mechanism, called “thermal” NOx, refers to the NOx that is formed through the oxidation of nitrogen 

that is present in the air supplied to complete the combustion process. Thermal NOx formation is dependent 

on temperature, local oxygen concentrations, and residence time in the primary combustion zone. The second 

mechanism, called “fuel” NOx, refers to the NOx 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 NOx produced during natural 

gas combustion. The third mechanism, “prompt” NOx, refers to the NOx that is formed within the flame itself 

from hydrocarbons that react with molecular nitrogen. Prompt NOx represents a very small portion of the total 

NOx generated during natural gas combustion. Understanding basic NOx formation during the combustion 

process is important in understanding how NOx control technologies reduce emissions and how they affect unit 

operation. 

There are basically two techniques that have been used in reducing and controlling NOx emissions generated 

by utility boilers combusting fossil fuels: (1) modifications to the combustion process; and (2) use of chemical 

reagents to reduce NOx to molecular nitrogen. Modifications to the combustion process are designed to 

reduce the temperature and available oxygen in the primary combustion zone, thereby reducing the production 

of thermal NOx. The post-combustion NOx controls involve the chemical reaction between the NOx and 

ammonia introduced to the flue gas. Both of these control techniques by themselves or in combination have 

been used throughout the industry with various degrees of success to reduce NOx 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 

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The control techniques available to further reduce NOx emissions from natural gas-fired, utility boilers, in topdown order, include: 

• Selective catalytic reduction (SCR); 

• Selective non-catalytic reduction (SNCR); 

• Flue gas recirculation (FGR); 

• Over fire air (OFA); 

• Low NOx burners (LNB); 

• Burners out of service (BOOS); and 

• Low excess air (LEA). 

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

combustion controls to the Mohave units are addressed in the BART analysis. A detailed review of these NOx

control techniques prepared by Babcock Power, Inc. is provided in Appendix A. 

3.2.1 Selective Catalytic Reduction 

SCR is a post-combustion NOx control technology that involves a catalyst 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 the flue gas upstream of a 

precious metal catalyst bed and reduces a portion of the NOx 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 NOx

reduction reaction to take place in the catalyst-laden reactor, the existing ductwork is replaced with larger size 

ductwork. If there is insufficient space for in-line SCR, a stand-alone SCR may be installed adjacent to the 

boiler. In either case, application of SCR to a natural gas-fired boiler would increase overall system pressure 

drop (approximately 6 to 8 inches H2O) would require the installation of induced draft fans resulting in 

increased fan power consumption and loss of overall plant 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 SO2 to SO3 prior to stack 

emission, leading to additional visibility-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 emitted 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 NOX emissions. Depending on the uncontrolled NOx 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-line SCR are considered technically feasible NOx 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 NOx control technology that involves the injection of ammonia or urea into the flue 

gases without the presence of a catalyst. SNCR, like SCR, involves the reaction of NOx with ammonia where 

a portion of the NOX is converted to molecular nitrogen and water. Without the use of a catalyst or 

supplemental fuel injection, the NOx 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 emitted 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 

NOx. NOx 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 SNCR 
3-4 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 considered a technically feasible 

NOx 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 the combustion products (flue gas) with combustion air to 

reduce NOx emissions. FGR lowers oxygen concentration during the initial stages of combustion, along with 

combustion temperatures. Because flue gas is inert, it is important that the oxygen concentration of 

combustion air/flue gas mixture is maintained 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 boiler 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 NOx reduction achieved though the use of FGR depend primarily 

dependent on the FGR flow rate, excess air levels, burner stoichiometry, and burner/furnace heat release rate. 

Generally, FGR is effective in reducing thermal NOx due to the dilution effect on the combustion process and 

reduction in combustion temperatures. Typically the NOx reductions that have been achieved using FGR range 

are on the order of 20 to 50 percent. This NOx control technique is considered technically feasible to control 

NOx 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 combustion air away from the primary 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 

NOx emissions. The air introduced through the OFA ports ensures complete combustion. This technology has 

been used in combination with other NOx control techniques, such as LNB and FGR, on hundreds of units 

throughout the country to provide additional NOx reduction. The NOx reductions that have been achieved with 

OFA ports have ranged from 10 to 30 percent. This NOx control technique is considered technically feasible to 

control NOx emission from the Mohave units under the natural gas firing configuration. 

3.2.5 Low NOx Burners 

Low NOx burners (LNB) are designed to reduce NOx emissions by controlling the mixing of fuel and air during 

the initial stages of combustion. The basic concept that forms the basis of the LNB design is to delay the 

mixing of the fuel and air during the initial stages of the combustion process. This delay is achieved through 

the physical separation of some of the air from the fuel, or through aerodynamic means by imparting swirl to 

the air, or both. The production of NOx is minimized under these conditions since the availability 

(concentration) of oxygen to react with the liberated organically bound nitrogen is minimized. The Mohave 

units are tangentially-fired boilers that are characterized by their inherent lower NOx 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 NOx emissions. The use of OFA ports further delays the introduction of 

air in the combustion zone further reducing NOx emissions. This NOx control technique, therefore, is 

considered technically feasible to further reduce NOx emission from the Mohave units under the natural gas 

firing configuration. At a steady-state, 100% rated heat input operation, LNB with OFA achieves the maximum 

NOx pounds per hour formation presented in Table 4-6. However, as load changes up or down and during 
3-5 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

startup and shutdown, the NOx reduction performance will vary due to variables in combustion air control, but 

in no case will the maximum NOx 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 NOx emissions. Staged combustion involves the generation of a fuelrich zone during the initial stages of the fuel combustion that reduces oxygen concentration and flame 

temperatures. BOOS operation is accomplished by eliminating fuel flow to selected burners, while maintaining 

air flow through those burners. The fuel flow to remaining burners is increased to maintain the heat input 

required to produce the fuel rich atmosphere required for reducing NOx emissions. The current Mohave units 

having been designed for pulverized coal firing lend themselves 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 NOx 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 boilers at Low excess air (LEA) operation with natural gas-fired boilers 

levels has been demonstrated to provide minor improvements in NOx emissions. This operation reduces 

the amount of available oxygen in the primary combustion zone, lowering the overall NOx formation 

stoichiometry and combustion temperatures. The Mohave units typically will operate at excess air levels 

ranging from 8 to12 percent by volume. Further reducing excess air levels could have the negative effects 

of decreasing boiler efficiency and increasing the combustible losses (e.g., CO and PM). This NOx control 

technique, therefore, is inherent in the design of the tangentially-fire boilers under the natural gas firing 

configuration. 

3.2.8 Summary of NOX Control Technical Feasibility 

The NOX control technologies considered technically feasible for application to the Mohave units under the 

natural gas firing configuration include SCR, SNCR, FGR, LNB, and OFA. The other NOx control techniques, 

BOOS and LEA, are inherent in the design of the tangentially-fired boilers under the natural gas firing 

configuration. 

3.3 SO2 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 (H2S) or mercaptans, is added to the fuel as an odorant at a rate of approximately 

1.0 pound of H2S per million cubic feet of natural gas. The conversion of the Mohave units from coal to 

dedicated natural gas combustion, therefore, will reduce SO2 emissions from approximately 0.75 lb/MMBtu 

under baseline conditions to 0.0019 lb/MMBtu under the natural gas firing configuration. This corresponds to a 

reduction in SO2 emissions relative to baseline conditions of approximately 99.8 percent. Given these 

 

3

 The NOx 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 NOx 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 SO2 emission levels, there are no technically feasible control technologies that are capable of 

further reducing SO2 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 PM10 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 PM10 emissions relative to baseline conditions of approximately 84.5 percent. 

Given these extremely low PM10 emission levels, there are no technically feasible control technologies that are 

capable of further reducing PM10 emissions under the natural gas-firing configuration. 

3.5 Effectiveness of the NOx Control Options 

The effectiveness of the technically feasible NOx control options is based on a review of performance data 

from operational plants by Babcock Power, Inc. Based on this review, the NOx emission levels achievable by 

each control technology applied to the Mohave units under the natural gas firing configuration at maximum 

rated heat input are summarized in Table 3-2. 

Table 3-2 Emissions Control Effectiveness of NOx Control Options 

Option Description 

NOx Emissions 

(lb/MMBtu) 

Reduction from coal 

baseline emissions 

(%) 

1 LNB+OFA+SCR (Stand Alone) 0.0104 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 NOx Control Options 

To determine the cost effectiveness of the NOx control options, the direct capital and annual operating and 

maintenance costs associated with each control option were estimated by Babcock Power, Inc. The direct 

equipment and installation capital costs then were adjusted 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 NOx performance. As indicated in Appendix G, NOx

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 

NOx performance should not exceed 0.15 lb/MMBtu, and NOx 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 Construction: 5%-10% 

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

For purposes of this analysis, the owner’s indirect costs are assumed to be 40% of direct procurement costs 

consistent with the Utility Air Regulatory Group’s report “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 that in the financial markets for this type of project it 

would be difficult to attract investors for cost of capital rates below 12%, because the restart of MGS on natural 

gas and its long term competitiveness are speculative. Although the units are anticipated to have a useful life 

of at least 20 years (so that useful life is not a factor in the BART analysis), their long-term competitiveness in 

the electric energy market place is uncertain. In the short term (5 years), it is anticipated that the units will be 

under contract and therefore the short-term outlook supports restart of the units. However, beyond the initial 

5-year period, the market competitiveness of the units 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 project proponents’ judgement that a 12% cost of capital is appropriate for the risks and 

uncertainties associated with the return of investment on the emission control investments. 

The annual NOx emissions associated with the baseline case and five NOx control options were based on the 

maximum hourly NOx emission rate, the maximum heat input rate, and the annual average capacity factor. 

The maximum hourly NOx emission rate for the baseline case and five NOx control options are provided earlier 

in the report. The maximum heat input rates for the baseline case and five NOx 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 2001 through 2005. Table 3-3 

persents the actual and maximum heat input to both of the 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 NOx control options then was determined by dividing the total annual cost by 

the NOx 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 NOx control options 

applied to the Mohave units. 

3.7 Environmental Impacts of the NOx Control Options 

One of the most significant impacts of retrofitting SCR or SNCR on the facility is the addition of ammonia or 

urea storage and handling systems. Anhydrous ammonia and aqueous ammonia above 20 percent are 

considered dangerous to human health. An accidental release of anhydrous ammonia 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 communication 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 NOx, forming elemental nitrogen and water in 

both SCR and SNCR. In reality, not all the injected 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 stoichiometrically required and essentially achieving the NOx

emissions at the expense of ammonia slip. The ammonia slip associated with SCR is specified by Babcock 

Power, Inc. in Appendix A to be 2 ppm at 3 percent O2, while that associated with SNCR is specified to be 6 
3-8 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

ppm at 3 percent O2. This excess ammonia will react with SO2 and NOx in the atmosphere to form ammonium 

salts and hence increased concentrations of both PM10 and PM2.5. 

3.8 Energy Impacts of the NOx Control Options 

Selective catalytic reduction would consume significantly more electrical energy than SNCR. The higher 

electrical energy consumption for SCR operation relative to SNCR primarily is due to the power required for 

the increased fan static pressure required to overcome the pressure drop across the catalyst bed, as well as 

for pumps and an evaporator blower. Likewise, FGR would 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, possibly from regional coalfired power plants, required to maintain the MGS current net electrical output capability have not been 

incorporated into the visibility modeling, so the reviewer should be aware that any reported visibility 

improvements due to FGR or SCR operation do not consider this negative impact. 
3-9 

BART Determination for MGS: Natural Gas Firing 06200-034-500

Table 3-3 Annual Capacity Factor for Mohave Units 1 and 2(a)

Table 3-4 Cost Effectiveness of NOx Control Options 
4-1 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

4.0 Future Emissions for BART Control Options 

4.1 Modeled Stack Parameters 

The NOx control options available for the Mohave units under the natural gas firing configuration that are 

considered in the visibility 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 NOx control options were developed by Babcock Power, Inc. 

as detailed in Appendix A. 

4.2 Estimated Emissions 

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

PM10, SO2, and NOx. SO2 emissions were based on a material balance assuming an H2S concentration of 1.0 

lb per million cubic feet of natural gas. The PM10 emissions and speciation were determined using the 

following approach: 

• PM10 emissions were based on the default approach cited in AP-42, Table 1.4-2. For natural gas-fired 

boilers, filterable PM10 emissions are based on the emission factor of 1.9 lb/106

 scf, while condensable 

PM10 emissions are based on the emission factor of 5.7 lb/106

 scf of natural gas. 

• For natural gas-fired boilers, elemental carbon is expected to be 6.7 percent of fine PM10 based on the 

best estimate for electric utility coal 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. 

• Condensable inorganic PM10 emissions, assumed to consist of H2SO4, are based on “Estimating Total 

Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008. For 

natural-fired boilers equipped with SCR, H2SO4 emissions are determined as follows: 

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

where: E is the H2SO2 emission rate (lb/hr), 

Q is the baseline SO2 emission rate (lb/hr), 

F1 is the fuel factor (0.01 for natural gas), 

S2 is the SCR catalyst SO2 oxidation rate (0.03 for natural gas) 

F2 is the control factor (assumed to be 1.0 given the extremely low SO2 emissions) 

Note that the inorganic PM10 emissions are assumed to consist entirely of H2SO4. NOx 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 slightly 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 gas firing conditions are presented in Table 4-1. The 

NOX, SO2, and PM10 emissions under the five BART control options then are summarized in Tables 4-2 

through 4-6, respectively. As indicated in Appendix G, the maximum NOx emission rate occurs at maximum 

load conditions, which is the case being modeled for the various BART options.
4-2 

BART Determination for MGS: Natural Gas Firing 06200-034-500

Table 4-1 MGS Natural Gas Firing Stack Parameters 

 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 27.81 Exit Temperature °K 395.4 

Table 4-2 MGS BART Option 1 Emissions 

fine total fine soil EC total 

MMBtu/hr Btu/scf gr/106 scf lb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

1

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, Stand-Alone SCR & ESP

7,880 1,000 7,000 0.010 78.80 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.

2

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, Stand-Alone SCR & ESP

7,880 1,000 7,000 0.010 78.80 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.

(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. 6

(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 the u

fuel 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 Description

Max. Heat 

Input

Higher 

Heating 

Value

Fuel Sulfur 

Content Maximum NOx Emissions Maximum SO2 Emissions Maximum Filterable PM 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 

total coarse Fine

Filterable PM10 Conden
4-3 

BART Determination for MGS: Natural Gas Firing 06200-034-500

Table 4-3 MGS BART Option 2 Emissions 

fine total fine soil EC total 

MMBtu/hr Btu/scf gr/106 scf lb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

1

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, InLine SCR & ESP 7,880 1,000 7,000 0.025 197.00 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.

2

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, InLine SCR & ESP 7,880 1,000 7,000 0.025 197.00 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 45.60 (a) 0.

(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. 6

(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 the u

fuel 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 Description

Max. Heat 

Input

Higher 

Heating 

Value

Fuel Sulfur 

Content Maximum NOx Emissions Maximum SO2 Emissions Maximum Filterable PM 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 

total coarse Fine

Filterable PM10 Conden

Table 4-4 MGS BART Option 3 Emissions 

fine total fine soil EC total 

MMBtu/hr Btu/scf gr/106 scf lb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

1

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, FGR & ESP

7,880 1,000 7,000 0.070 551.60 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

2

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, FGR & ESP

7,880 1,000 7,000 0.070 551.60 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

(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. 6

(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 unconfuel factor (0.01 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be 1.0. 

Unit Description

Max. Heat 

Input

Higher 

Heating 

Value

Fuel Sulfur 

Content Maximum NOx Emissions Maximum SO2 Emissions Maximum Filterable PM 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 

total coarse Fine

Filterable PM10 Conden
4-4 

BART Determination for MGS: Natural Gas Firing 06200-034-500

Table 4-5 MGS BART Option 4 Emissions 

fine total fine soil EC total 

MMBtu/hr Btu/scf gr/106 scf lb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

1

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, SNCR & ESP

7,880 1,000 7,000 0.080 630.40 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

2

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, SNCR & ESP

7,880 1,000 7,000 0.080 630.40 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

(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. 6

(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 unconfuel factor (0.01 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 SNCR is assumed to be a typical value of 5.0% at 3% O2 per Babcock Power.

total coarse Fine

(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 

Unit Description

Max. Heat 

Input

Higher 

Heating 

Value

Filterable PM10 Conden

Fuel Sulfur Content Maximum NOx Emissions Maximum SO2 Emissions Maximum Filterable PM Emissions

Table 4-6 MGS BART Option 5 Emissions5

fine total fine soil EC total 

MMBtu/hr Btu/scf gr/106 scf lb/MMBtu lb/hr lb/MMBtu lb/hr lb/MMBtu lb/hr Basis lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

1

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, & ESP

7,880 1,000 7,000 0.100 788.00 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

2

Natural Gas, 790 MW, Tangential-Fired, LNB, OFA, & ESP

7,880 1,000 7,000 0.100 788.00 0.0019 14.81 0.0019 14.97

Maximum 

Daily 

Emissions

14.97 (a) 0.00 14.97 (a) 13.97 1.00 (b) 44.92 (a) 0.

(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 

(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. 6

(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 uncon

fuel factor (0.01 for natural gas). Given the extemely low uncontrolled SO2 emissions, F2, the control factor, is assumed to be 1.0. 

Fuel Sulfur Content Maximum NOx Emissions Maximum SO2 Emissions Maximum Filterable PM Emissions

Unit Description

Max. Heat 

Input

Higher 

Heating 

Value

Filterable PM10 Conden

total coarse Fine

5 The 0.10 lb/MMBtu emission rate presented in Table 4-6 is based on maximum thermal input NOx emissions. See Appendix G for an explanat

on 100% natural gas fuel and at various load levels that would be expected for a load-following, intermediate and peaking generation system reSouthern California load control area. Such an operation will cause the actual NOx emission performance rate to be as high as 0.15 lb/MMBtu significant operating time 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 Western Regional Air Partnership (WRAP) common BART 

modeling protocol with the exception of the model version 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 (km) CALMET meteorological databases for 3 years 

(2001-2003). The CALMET modeling domains are strategically designed to cover all potential BART eligible 

sources within WRAP states and all PSD Class I areas within 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 protocol discusses MM5 data extraction. The BART 

CALPUFF modeling for MGS was done using the Arizona 4-km CALMET database with 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 are illustrated in Figures 5-1 through 5-3 and listed in 

Table 5-1, and are further discussed below. Figure 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 the 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/bart/calpuff/calmet_inputs/az/. ENSR initially ran 

CALMET with the setting suggested in the WRAP BART modeling protocol. As part of ENSR’s internal quality 

assurance procedure, we displayed and examined the 4-km Arizona WRAP CALMET wind fields in the 

visualization software CALDESK. Figure 5-2 graphically shows wind fields with the WRAP settings for a 

typical hour. Arrows represent wind direction and wind speed for that hour at 10 meter height. Circular areas 

in these figures with common winds and abrupt transitions at the edge of the circles indicate a radius of 

influence of surface stations, R1, which was set to 100 km, as suggested in the WRAP BART protocol. The 

R1 value was coupled with R1MAX = 50 km so that the influence 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 correspondence 
5-2 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

between John Notar of the NPS and Bob Paine of ENSR, shown in Appendix B, along with other relevant 

agency recommendations). A large R1 value results in wind 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 the 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" EPA-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/download/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 analysis; 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 observations to the upper layers using similarity 

theory, and ignore layer 1 from the upper air soundings. 

• Set ITPROG = 1, to use surface station temperature 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 Domain 
5-4 October 2008

BART Determination for MGS: Natural Gas Firing 

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Figure 5-2 CALMET Wind Fields with WRAP Settings
5-5 October 2008

BART Determination for MGS: Natural Gas Firing 

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Figure 5-3 CALMET Wind Fields with ENSR Settings
6-1 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

6.0 Visibility Modeling: 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 CALPUFF (Version 5.8, Level 070623) that has been 

posted at http://www.src.com/calpuff/download/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-guideline version of the model, ENSR used the official EPA version. 

The area covered by the 4-km WRAP domain for Arizona 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 computational 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 recirculation. 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/aqm/308/bart/calpuff/ozone_dat/. Data collection and processing are described in 

Section 3.1.2.7 of the WRAP protocol. These ozone data 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 algorithm 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 Domain 
6-3 October 2008

BART Determination for MGS: Natural Gas Firing 

06200-034-500

6.2 Natural Conditions and Monthly 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 (μg/m3

) 

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 Haze 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 extinction. 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: 

bext = 3 f(RH) [(NH4)2SO4] + 3 f(RH) [NH4NO3] + 4[OC] + 1[Soil] + 0.6[Coarse Mass] + 10[EC] + bRay

The concentrations, in square brackets, are in μg/m3

 and bext is in units of Mm-1. The Rayleigh scattering term 

(bRay) 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 Class 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-caused extinction from ammonium sulfate 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 yield the total hourly source-caused extinction. 
BART Determination for MGS: Natural Gas Firing 7-1 October 2008

06200-034-500

7.0 CALPUFF Visibility 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 within the 300 km the of the MGS. Therefore, Domeland 

Wilderness was included in the regional haze modeling. 
BART Determination for MGS: Natural Gas Firing 7-2 October 2008

06200-034-500

Figure 7-1 Class I Areas within 300 km of the Mohave Generating Station 
BART Determination for MGS: Natural Gas Firing 7-3 October 2008

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 conducted for all three years of CALMET meteorological data (2001-2003). 

The results are reported below using the new IMPROVE equation and the old IMPROVE equation results are 

presented in Appendix F, which lists the tables and figures in the main report that are counterparts in the 

appendix. 

For each Class I area and year, Table 7-1 lists the 8th highest delta-deciview impact. Figure 7-2 shows the 8th

highest deciview impacts. The figure indicates that the 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 98th percentile value of the modeling results should be 

compared to the threshold of 0.5 deciviews to determine if a source contributes to visibility impairment. The 

Guidelines also recommend using the 98th-percentile statistic for comparing visibility improvements due to 

BART control options. On an annual basis, the 98th percentile value implies the 8th highest day at each 

modeled Class I area. 

The results of the baseline emissions analysis indicate that the Mohave units have predicted 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. Candidate BART controls are discussed in Section 3. The 

results of the visibility improvement modeling for these candidate controls are discussed in Section 7.3. 

Table 7-1 Regional Haze Impacts Due to Baseline Emissions 
BART Determination for MGS: Natural Gas Firing 7-4 October 2008

06200-034-500

Figure 7-2 8th 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 Area

8th 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 for these candidate controls. The results presented in 

this section are based on the new IMPROVE equation, while the old IMPROVE equation results are presented 

in Appendix F. 

The 3-year average results of the BART control options 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 8th 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+FGR 
BART Determination for MGS: Natural Gas Firing 7-5 October 2008

06200-034-500

• BART Option 4: LNB+OFA+SNCR 

• BART Option 5: LNB+OFA 

Results for each candidate BART control option are discussed in more detail below. The results discussion 

focuses on Joshua Tree Nation Park and Grand Canyon National 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 other BART options. The visibility 

(average 8th 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. (This metric is used to characterize visibility 

improvement for the other BART options as well.) The BART Option 1 would result in a predicted reduction of 

1346 days above 0.5 delta-dv over three years and the 11 Class 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 (H2SO4) 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 years and at the 11 modeled Class I areas. This control 

option is also subject to the same parasitic 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 visibility by 2.43 and 1.98 delta-dv 

relative to the baseline case at Joshua Tree NP and Grand 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 Joshua 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 98th 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, all 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 NOx 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 California Class I areas and non-California Class I areas. (Figures F-9 and F-10 

graphically show the results using the old IMPROVE equation). 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, indicating a very small difference 

in improvement from the baseline case to each of these BART control options involving the number of days 

removed for delta-dv above 0.5. 
BART Determination for MGS: Natural Gas Firing 7-6 October 2008

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Table 7-2 Regional Haze Results of Modeled BART Options 
BART Determination for MGS: Natural Gas Firing 7-7 October 2008

06200-034-500

Table 7-2 Regional Haze Results of Modeled BART Options 
BART Determination for MGS: Natural Gas Firing 7-8 

06200-034-500Figure 7-3 8th Highest Visibility Impacts due to Five NOx Control Options 

8th Highest Regional Haze Impacts due to Five BART NOx Control Options

0.00.10.20.30.40.5

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 Area

2001-03 Ave 8th Highest dv

LNB+OFA+SCR (Stand Alone)LNB+OFA+SCR (In-Line)LNB+OFA+FGRLNB+OFA+SNCRLNB+OFA
BART Determination for MGS: Natural Gas Firing 7-9 

06200-034-500Figure 7-4 Total Number of Days Removed Above 0.5 delta-dv Relative to the Baseline Case 

1346 1327 1319 1332 1345

0

200400600800

1000120014001600

LNB+OFA+SCR (Stand

Alone)

LNB+OFA+SCR (In-Line) LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days Removed
BART Determination for MGS: Natural Gas Firing 7-10 

06200-034-500Figure 7-5 Number of Days Removed at Each Class I Area Above 0.5 delta-dv Relative to the 

Baseline Case 

237 229 226 218

188 188 188 188

103 103 103 103

219 219 219 219

96 96 96 96

503 497 495 495 502

237

188

103

219

96

0

100200300400500600

LNB+OFA+SCR (Stand

Alone)

LNB+OFA+SCR (InLine) LNB+OFA+FGR LNB+OFA+SNCR LNB+OFA

# of Days Removed

Grand Canyon NJoshua Tree NMZion NPSycamore Canyon W5 Other CA Class I Area2 Other AZ Class I Area
BART Determination for MGS: Natural Gas Firing 8-1 October 2008

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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 Class 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 IMPROVE 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 very low visibility impacts from all of the BART control 

options. The results for the Grand Canyon and Joshua Tree National Parks in Figure 8-1 indicate only modest 

visibility gains at great cost relative to BART Control Option 5 for the other BART control options. 

It is clear from all of these figures that a large visibility improvement is attained 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 98th

percentile impacts below the contribution to perceptible haze threshold of 0.5 delta-dv. 

We also provide Figure 8-4 that plots the annual NOx 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 NOx emissions, but since nitrates are not the most important visibility-impairing 

particle species, the visibility improvement (expressed in terms of change in the average 98th 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 estimated ranges of cost effectiveness that were used to 

establish the presumptive limits for NOx as $100 to $1000 per ton of NOx removed. For NOx controls, EPA 

stated that its presumptive NOx “limits...are based on the use of current 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 effectiveness of stand-alone SCR is in excess of 

$2,400 per ton of NOx removed, and the incremental cost effectiveness relative to Option 5 is over $11,700 per 

ton. EPA further stated that they were “not establishing 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 NOx

control technologies analyzed for MGS are generally consistent with EPA’s guidance. The combustion control 

technologies are significantly more cost effective than post-combustion controls, such as SCR. It is also worth 

noting that the imposition of SCR, on top of the retirement 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-activated as a natural gas-fired plant, then the required 

electrical generation of several hundred megawatts from possibly more visibility-impairing pollutant sources 

would have the potential to adversely affect the Nevada 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: 
BART Determination for MGS: Natural Gas Firing 8-2 October 2008

06200-034-500

• The need to transport ammonia supplies to the plant, with the attendant hazardous air pollutant risks 

and additional vehicular traffic; and 

• The parasitic power loss to run the SCR equipment 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 NOx emissions than those of BART Option 1, and the costs are slightly 

less. Otherwise, the issues for this option 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 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 in-line SCR is in excess of $2,300 per ton of NOx 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 NOx emissions than those of BART Options 1 and 2, and the costs are 

somewhat less. Otherwise, the issues for this option are similar to those of Options 1 and 2, except for no 

requirement for ammonia injection. The visibility improvement relative to that of BART 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 NOx removed, 

and the incremental cost effectiveness relative to Option 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 NOx emissions than the previous BART options 1 and 2, and the costs are somewhat 

less. Otherwise, the issues for this option are similar to those of Options 1 and 2, with a feature of 

considerably higher ammonia slip. The visibility improvement relative to that of BART Option 5 is only 0.04 

delta-dv at the Grand Canyon NP and 0.07 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 more than $1,100 per ton of NOx removed, and 

the incremental cost effectiveness relative to Option 5 is about $20,000 per ton. This 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 options, and Option 4 is rejected as BART. 

BART Control Option 5: LNB + OFA 

This option has higher NOx emissions than those of the other BART options, but the costs are comparatively 

quite low. The CALPUFF visibility modeling results presented in Sections 5.0 - 7.0 was performed based on 

the maximum expected 788 lbs NOx 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 are 
BART Determination for MGS: Natural Gas Firing 8-3 October 2008

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 NOx removed. This 

option represents the combustion controls cited by EPA as cost-effective for NOx 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 visibility improvement for BART control options other than Option 5 result in only 

minor visibility improvements at significant 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 modeling demonstrating significant visibility improvements for affected Class I 

areas from BART Control Option 5, we select a NOx BART Emissions Limit of 788 lbs/hour for each Mohave 

Generating Unit. In addition, consistent with the controlled NOx performance of Mohave as a 100% natural 

gas generating facility,6

 we select a NOx 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 facility serving the Southern California load control area as a load following, 

intermediate and peaking system generation resource 
BART Determination for MGS: Natural Gas Firing 8-4 

06200-034-500Figure 8-1 Annual Cost of NOx Controls vs. Visibility Improvements at the Closest Class I Areas 

0

1020304050

3.0 2.5 2.0 1.5 1.0 0.5 0.0

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Grand Canyon NPJoshua Tree NP

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCR In-Line

LNB+OFA+SCR Stand-Alone
BART Determination for MGS: Natural Gas Firing 8-5 

06200-034-500Figure 8-2 Annual Cost of NOx Controls vs. Visibility Improvements at the Other California Class I 

Areas 

0

1020304050

1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Agua Tibia WCucamonga WSan Gorgonio WSan Jacinto WDomeland W

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCR In-LineLNB+OFA+SCR Stand-Alone
BART Determination for MGS: Natural Gas Firing 8-6 

06200-034-500

0

1020304050

1.4 1.2 1.0 0.8 0.6 0.4 0.2 0.0

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Sycamore Canyon WMazatzal WPine Mountain WZion NP

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCR In-Line

LNB+OFA+SCR Stand-Alone

Figure 8-3 Annual Cost of NOx Controls vs. Visibility Improvements at the Other Non-California 

Class I Areas 
BART Determination for MGS: Natural Gas Firing 8-7 

06200-034-500Figure 8-4 NOx Control Options Cost Effectiveness 

NOx Control Options Cost Effectiveness

0

102030405060

0 5,000 10,000 15,000 20,000 25,000

NOx Emissions Reduction (tons/year)

MM$/year

LNB+OFA

LNB+OFA+SNCR

LNB+OFA+FG

LNB+OFA+SCR(In-Line)

LNB+OFA+SCR (Stand-Alone)

Baseline
BART Determination for MGS: Natural Gas Firing 8-8 

06200-034-500Table 8-1 Summary for BART Analysis for NOx

Step 1 Step 2 Step 3 Step 4a Step 4b Step 5 

Identify 

Control 

Technologies 

Feasible 

Control 

Technology? 

Evaluate 

Control 

Effectiveness 

for 

Technically 

Feasible 

Control 

Technologies 

Calculate Cost 

Effectiveness for 

Control 

Technologies 

(relative to baseline) 

Determine 

Non-Air Quality 

Environmental 

and Energy 

Impacts 

Evaluate Visibility 

Impact of Controls 

vs. baseline (# days > 

0.5 delta-dv removed

and average visibility 

improvement , deltadv) 

Control 

Option 

1 

Low NOx

burners, 

overfire air, 

and standalone SCR 

Yes 

97.6% NOx

reduction from 

coal-fired 

baseline 

Annualized cost = 

$50,990,000; 

Marginal cost eff. 

relative to Option 5 = 

$11,714/ton 

Excess NH3

emissions; higher 

energy use for 

pressure drop; 

need RMP 

# days > 0.5 delta-dv 

removed = 1346(1), 

average vis. 

improvement = 1.11(2)

delta-dv 

Control 

Option 

2 

Low NOx

burners, 

overfire air, 

and in-line 

SCR 

Yes 

94.1% NOx

reduction from 

coal-fired 

baseline 

Annualized cost = 

$47,240,000; 

Marginal cost eff. 

relative to Option 5 = 

$12,992/ton 

Excess NH3

emissions; higher 

energy use for 

pressure drop; 

need RMP 

# days > 0.5 delta-dv 

removed = 1345(1), 

average vis. 

improvement = 1.09(2)

delta-dv 

Control 

Option 

3 

Low NOx

burners, 

overfire air, 

and flue gas 

recirculation 

Yes 

83.5% NOx

reduction from 

coal-fired 

baseline 

Annualized cost = 

$33,610,000; 

Marginal cost eff. 

relative to Option 5 = 

$22,806/ton 

Increased CO 

emissions; higher 

energy use for 

pressure drop 

# days > 0.5 delta-dv 

removed = 1332(1), 

average vis. 

improvement = 1.05(2)

delta-dv 

Control 

Option 

4 

Low NOx

burners, 

overfire air, 

and SNCR 

Yes 

81.1% NOx

reduction from 

coal-fired 

baseline 

Annualized cost = 

$20,250,000; 

Marginal cost eff. 

relative to Option 5 = 

$19,968/ton 

Excess NH3

emissions; need 

RMP 

# days > 0.5 delta-dv 

removed = 1327(1), 

average vis. 

improvement = 1.04(2)

delta-dv 

Control 

Option 

5 

Low NOx

burners and 

overfire air 

Yes 

76.4% NOx

reduction from 

coal-fired 

baseline 

Annualized cost = 

$1,500,000 None 

# days > 0.5 delta-dv 

removed = 1319(1), 

average vis. 

improvement = 1.02(2)

delta-dv 

(1) Total number of days above 0.5 delta-dv removed over three meteorological years and eleven Class I areas. (2) Average 8th highest visibility improvement over three meteorological years and eleven Class I areas. 
BART Determination for MGS: Natural Gas Firing 9-1 October 2008

06200-034-500

9.0 References 

Atkinson, D. and T. Fox. 2006. Dispersion Coefficients 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/asia/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 Generating 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. “Evaluation 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 NPS and Bob Paine of ENSR, November 28, 2005. 

Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; 

Final Rule (FR Vol. 70, No. 128 published July 6, 2005). 

Regional Haze Regulations; Revisions to Provisions Governing Alternative to Source-Specific Best Available 

Retrofit Technology (BART) Determinations; Final 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 Best Available Retrofit Technology (BART) 

Determinations (Appendix Y), updated June 24, 2005 

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

_____. 2003b. Guidance for Tracking Progress Under the Regional Haze Rule, EPA-454/B-03-003, Appendix 

A, Table A-3, September 2003. 

_____. 1998. Interagency Workgroup on Air Quality Modeling (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 Pollutant Emission Factors, Volume 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 the Western United States. August 15, 2006. 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix A 

NOx BART Review for the Mohave Generating Station 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix B 

Guidance on CALMET Settings 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix C 

Factors Influencing NOx Emissions Effects on Visibility 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix D 

Re-Calculating CALPOST Visibility Outputs 

with the New IMPROVE Algorithm 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix E 

CALPUFF Modeling Results and Graphic Charts using the New 

IMPROVE Equation 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix F 

CALPUFF Modeling Results and Graphic Charts using the Old 

IMPROVE Equation
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034-500

Appendix G 

Projected NOx Emissions on Natural Gas Over Mohave’s Future 

Operating Range Based on 2005 Actual Reporting for the Mohave 

Generating Station