U.S. ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

STATEMENT OF BASIS AND 

AMBIENT AIR QUALITY IMPACT REPORT 

For a Clean Air Act 

Prevention of Significant Deterioration Permit 

Navajo Generating Station 

Low-NOx Burner Project 

PSD Permit Number AZ 08-01 

October 2008 

Navajo Generating Station PSD Permit AZ 08-01 

Draft Ambient Air Quality Impact Report, October 2008 
 NAVAJO GENERATING STATION – LOW-NOx BURNER PROJECT 

Statement of Basis and Ambient Air Quality Impact Report 

(PSD Permit AZ 08-01) 

Table of Contents 

Acronyms & Abbreviations 

I. APPLICANT INFORMATION.......................................................................................... 4 

II. PROJECT LOCATION ...................................................................................................... 4 

III. PROCESS DESCRIPTION ................................................................................................ 4 

A. Facility Description..................................................................................................... 4 

B. Project Description...................................................................................................... 4 

C. Air Pollution Control Equipment................................................................................ 5 

IV. EMISSIONS FROM THE PROJECT ................................................................................ 6 

V. APPLICABILITY OF SIGNIFICANT DETERIORATION ............................................. 6 

VI. BEST AVAILABLE CONTROL TECHNOLOGY........................................................... 7 

VII. AIR QUALITY IMPACTS............................................................................................... 11 

A. Meteorological and Background Ambient Air Quality Data.................................... 11 

B. Modeling Methodology ............................................................................................ 12 

C. NAAQS Compliance ................................................................................................ 13 

D. Increment Consumption Analysis and Increment Compliance ................................ 14 

VIII. ADDITIONAL IMPACT ANALYSIS............................................................................. 14 

A. Growth Analysis....................................................................................................... 14 

B. Soils and Vegetation Analysis.................................................................................. 14 

C. Visibility Impairment and Air Quality Related Value Analysis............................... 15 

IX. ENDANGERED SPECIES............................................................................................... 15 

X. CONCLUSION AND ACTION....................................................................................... 15 

APPENDIX A

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Acronyms & Abbreviations 

AAQIR Ambient Air Quality Impact Report 

AQRV Air Quality Related Value 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CAA Clean Air Act 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CO2 Carbon Dioxide 

CO Carbon Monoxide 

EPA United States Environmental Protection Agency 

oF Degrees Fahrenheit 

FIP Federal Implementation Plan 

GCP Good Combustion Practices 

LAER Lowest Achievable Emission Rate 

lb/MMBtu Pound per Million British Thermal Units 

LNB Low-NOx Burner 

μg/m3 micrograms per cubic meter 

MMBtu/hr Million British Thermal Units per hour 

MW megawatt 

NAAQS National Ambient Air Quality Standard 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NWS National Weather Service 

NGS Navajo Generating Station 

NO2 Nitrogen dioxide 

NOx Nitrogen oxide 

O2 Oxygen 

PM Particulate Matter 

ppm parts per million 

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

RACT Reasonably Available Control Technology 

RBLC RACT/BACT/LAER Clearinghouse 

SCR Selective Catalytic Reduction 

SNCR Selective Non-catalytic Reduction 

SOFA Separate Over-fire Air 

SIL Significant Impact Level 

scf/MMBtu standard cubic feet per Million British Thermal Units 

NSPS Standard of Performance for New Stationary Sources 

SO3 Sulfite 

SO2 Sulfur dioxide 

H2SO4 Sulfuric acid 

SRP Salt River Project Agricultural and Power District 

tpy tons per year 

USGS United States Geological Survey 

VOC Volatile Organic Compound 

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This document serves as the Statement of Basis and Ambient Air Quality Impact Report for the 

proposed Prevention of Significant Deterioration (PSD) permit for the Navajo Generating Station 

– Low-NOx Burner Project. This document describes the legal and factual basis for the proposed 

permit, including requirements under the PSD regulations at Title 40 of the Code of Federal 

Regulations (CFR) §52.21. This document also serves as the fact sheet to meet the requirements 

of 40 CFR Part 124.7 and 124.8. 

I. APPLICANT INFORMATION 

Applicant Name: Salt River Project Agricultural and Power District (SRP) 

Facility Name: Navajo Generating Station 

Mailing Address: P.O. Box 850, Page, AZ 86040 

II. PROJECT LOCATION 

The Navajo Generating Station (NGS) is located on the Navajo Nation Indian 

Reservation, approximately five miles east of Page off U.S. Highway 98, in Coconino 

County, Arizona. 

III. PROCESS DESCRIPTION 

A. Facility Description 

The NGS consists of three existing coal-fired steam generating units, associated air 

pollution control devices and auxiliary equipment necessary to produce electricity. This 

facility has a combined power generating capacity of 2,250 net megawatts and became 

operational in stages between 1974 and 1976. Units 1, 2, and 3 are operated by SRP and 

co-owned by the following six entities: U.S. Bureau of Reclamation, SRP, Los Angeles 

Department of Water and Power, Arizona Public Service Company, Nevada Power, and 

Tucson Electric Power Company. The facility receives coal with a maximum sulfur 

content of 1.5% by weight from the Peabody Western Coal Company’s Kayenta Mine. 

Light fuel oil, in accordance with the American Society for Testing and Materials grade 2 

(commonly known as Fuel Oil No.2) serves as the ignition fuel for the units. 

B. Project Description 

SRP has proposed the Low-NOx Burner Project as a voluntary measure to significantly 

reduce emissions of nitrogen oxide (NOx) from all three boiler units at the NGS. The 

project involves the installation of Low-NOx Burners (LNB) with Separated Over-fire Air 

(SOFA) systems over a three-year period (see schedule in Table 1). A LNB and SOFA 

system reduces NOx emissions by controlling air and fuel flow to create fuel-rich and O2-

poor conditions in the burner, and stages the addition of over-fire air beyond the burner 

combustion zone to complete combustion in a lower temperature environment which 

reduces the formation of thermal NOx. 

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The Regional Haze rules found in 40 CFR Part 308 will require NGS to install Best 

Available Retrofit Technology (BART) for visibility impairing pollutants. EPA is in the 

process of evaluating the NOx and particulate matter emissions from this plant to 

determine BART for this facility. EPA plans to propose a revision to the Federal 

Implementation Plan (FIP) for NGS within a few months, to require the facility to meet 

emission limits achievable through the application of BART. EPA will promulgate the 

final FIP incorporating BART following the public review and comment process. The 

potential control technologies for NOx reduction at this facility for BART include LowNOx Burners with Separated Over-fire Air, Selective Non-catalytic Reduction (SNCR) 

with ammonia injection, and Selective Catalytic Reduction (SCR). For this facility, 

LNB/SOFA will likely be part of any BART determination even if the final BART FIP 

requires further reduction using SNCR or SCR controls. BART is required to be installed 

as soon as practicable but no later than five years after promulgation of the FIP. 

The early installation of the LNB/SOFA systems will not affect the baselines for cost or 

visibility improvements in the BART determination, and therefore will not influence 

EPA’s determination of the proper NOx reductions required to be achieved from BART. 

While the LNB/SOFA retrofit project that is the subject of this permit will result in 

significant NOx emission reductions, it will result in carbon monoxide (CO) emission 

increases. Due to the nature of combustion, boiler modifications to reduce NOx

emissions will result in incomplete combustion which increases CO emissions. SRP has 

determined that the CO net emission increase resulting from the proposed LNB/SOFA 

retrofits will be greater than the 100 tons per year significance threshold for CO under the 

Prevention of Significant Deterioration (PSD) provisions (see Section V), and therefore 

has submitted a PSD permit application for the project. 

This PSD permit would grant conditional approval to SRP, in accordance with the Clean 

Air Act and the PSD regulations at 40 CFR 52.21, to modify each boiler by installing 

LNBs and SOFA systems in each boiler. If the proposed permit is finalized in 2008, one 

boiler will be retrofitted during each of the next three calendar years as indicated in Table 

1 consistent with SRP’s anticipated planned outage schedule. 

Table 1. Low-NOx Burner Project Schedule 

Boiler Unit Projected LNBs Operational Date Max. Heat Input 

3 March 22, 2009 7,725 MMBtu/hr 

2 March 28, 2010 7,725 MMBtu/hr 

1 April 3, 2011 7,725 MMBtu/hr 

C. Air Pollution Control Equipment 

The existing coal combustion equipment on boiler units 1, 2, and 3 will each be replaced 

with an Alstom LNB/SOFA system. The LNB will reduce the formation of NOx

emissions by burning the coal in a fuel-rich, reducing environment. This reduces the 

concentration of oxygen available for the reaction with fuel nitrogen and reduces flame 

temperatures to minimize the formation of thermal NOx. The SOFA system will decrease 

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the amount of incomplete combustion in the furnace and, therefore, also minimize the 

formation of NOx emissions. 

The facility will install a continuous emissions monitoring system (CEMS) in each stack 

exhaust to measure and record CO concentrations once the LNBs and SOFA systems are 

installed. The facility will also operate, maintain, and quality-assure a CEMS in each 

stack exhaust to measure NOx concentrations according to the requirements of 40 CFR 

Part 75. 

IV. EMISSIONS FROM THE PROJECT 

As discussed in Section III.B, the LNB/SOFA system on each existing boiler will reduce 

NOx emissions but will collaterally increase CO emissions. Pursuant to 40 CFR 

52.21(a)(2)(iv)(c), SRP compared the baseline actual emissions to projected actual 

emissions in order to determine PSD applicability for this project (Table 2). 

Table 2. Summary of CO and NOx Emissions 

Boiler 

Unit Pollutant Pre-Project Baseline 

Emissions 1 (tpy) 

Projected Actual 

Emissions 2 (tpy) 

NOx 12,647 7,462 1 

CO 707 12,903 

NOx 11,660 7,462 2 CO 659 12,903 

NOx 10,342 7,462 3 CO 675 12,903 1 Baseline actual emissions are based on average emissions from the NGS 2006 and 2007 emission 

inventory reports, which satisfies the regulatory provision at 40 CFR 52.21(b)(48)(i). 2

 The projected actual emissions are based on a representative 2-year period between 2014 and 2016 

shown to have the highest utilization during the next ten years following the project, which satisfies the 

regulatory provision at 40 CFR 52.21(b)(41). 

 

V. APPLICABILITY OF PREVENTION OF SIGNIFICANT DETERIORATION 

The Navajo Generating Station is located within the Northern Arizona Intrastate Air 

Quality Control Region which is designated by the EPA as an unclassified or attainment 

area for all criteria pollutants: carbon monoxide (CO); nitrogen dioxide (NO2); sulfur 

dioxide (SO2); ozone, regulated by its precursors, volatile organic compounds (VOC) and 

oxides of nitrogen (NOx); particulate matter with an aerodynamic diameter less than 10 

micrometers (PM10); fine particulate matter with an aerodynamic diameter less than 2.5 

micrometers (PM2.5); and lead (Pb). 

The Prevention of Significant Deterioration (PSD) regulations at 40 CFR 52.21 define a 

“major stationary source” as any source type belonging to a list of 28 source categories 

which emits or has the potential to emit (PTE) 100 tons per year (tpy) or more of any 

attainment pollutant regulated under the Clean Air Act (CAA), or any other source type 

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which emits or has the potential to emit such pollutants in amounts equal to or greater 

than 250 tpy. NGS belongs to one of the 28 listed source categories (i.e., fossil fuel-fired 

electric plants with heat inputs of more than 250 MMBtu/hr). It is considered a 

grandfathered major stationary source because the PTE for criteria pollutants exceeds 100 

tpy. 

Under PSD, modifications at existing major stationary sources are deemed “major” if the 

modification results in a significant emission increase and a significant net emissions 

increase for any pollutant subject to PSD. See 40 CFR 52.21(a)(2)(iv)(a). As shown in 

Table 3, the net emissions increase associated with the proposed changes at NGS exceed 

the PSD significance thresholds for CO. In addition, because no changes are being made 

to the facility’s design or capacity, this project is not expected to increase emissions of 

any other criteria pollutants. Therefore, the proposed project constitutes a major 

modification only for CO and the following PSD requirements must be met: 

• Application of Best Available Control Technology; 

• Analysis of ambient air quality impacts from the project; 

• Analysis of air quality and visibility impacts on Class I areas; and 

• Analysis of impacts on soils and vegetation. 

Table 3. Net emissions increase and PSD applicability

Boiler 

Unit Pollutant Net emissions 

increase 1 (tpy) 

PSD Significance 

Threshold (tpy) Triggers PSD? 

NOx -(7,462) 40 No 1 

CO 12,190 100 Yes 

NOx -(7,462) 40 No 2 CO 12,190 100 Yes 

NOx -(7,462) 40 No 3 CO 12,190 100 Yes 1 Net emissions increase is calculated per 40 CFR 52.21(b)(3) (see Appendix A for detailed calculations).

VI. BEST AVAILABLE CONTROL TECHNOLOGY 

PSD regulations require that a Best Available Control Technology (BACT) determination 

be made for each pollutant subject to PSD review. Section 169(3) of the CAA defines 

BACT as follows: 

The term "best available control technology" means an emission limitation based 

on the maximum degree of reduction of each pollutant subject to regulation under 

the Clean Air Act emitted from or which results from any major emitting facility. 

The permitting authority, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, makes a BACT 

determination through application of processes and available methods, systems, 

and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall 

application of BACT result in emissions of any pollutant which will exceed the 

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emissions allowed by any applicable standard established pursuant to section 

7411 (NSPS) or 7412 (NESHAP) of the Clean Air Act. 

For attainment pollutants being regulated in a PSD permit, EPA evaluates emissions 

control requirements through a “top-down” BACT determination process. In brief, the 

top-down process involves ranking all available control technologies in descending order 

of control effectiveness. EPA first examines the most stringent technology. That 

technology is established as BACT unless it is demonstrated that technical 

considerations, or energy, environmental, or economic impacts justify a conclusion that 

the most stringent technology is not achievable for the case at hand. If the most stringent 

technology is eliminated, then the next most stringent option is evaluated until BACT is 

determined. The top-down BACT analysis is a case-by-case exercise for the particular 

source under evaluation. In summary, the five steps involved in a top-down BACT 

evaluation are: 

1. Identify all available control options with practical potential for application to 

the specific emission unit for the regulated pollutant under evaluation; 

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate the most effective control alternative and document results; if top 

option is not selected as BACT, evaluate next most effective control option; 

and 

5. Select BACT, which will be the most stringent technology not rejected based 

on technical, energy, environmental, and economic considerations. 

The applicant submitted a top-down BACT analysis for CO and proposed CO BACT 

emission limitations based on the analysis. EPA independently evaluated the information 

that SRP submitted and considered the following materials in identifying and evaluating 

available control technologies for pulverized coal-fired boilers: an EPA spreadsheet of 

recently permitted and proposed coal-fired power plants and EPA’s RACT/BACT/LAER 

Clearinghouse (RBLC). EPA’s BACT evaluation for CO emissions associated with the 

Low-NOx Burner Project at the Navajo Generating Station is discussed below. 

BACT for CO Emissions 

Step 1 – Identify All Available Control Technologies

The following control technologies were identified for the control of CO emissions 

from pulverized coal-fired boilers: catalytic oxidation, thermal oxidation, and good 

combustion practices. 

Step 2 – Eliminate all technically infeasible control technologies

Catalytic Oxidation 

Catalytic oxidation is the technology that has been used to obtain the most stringent 

control level for CO from natural gas-fired turbine combustion units. This technology 

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has never been applied to a coal-fired unit. It is evaluated here to determine if it could 

be considered feasible technology for application to NGS’ pulverized coal-fired 

boilers. In this alternative, a catalyst would be situated in the flue gas stream to lower 

the activation energy required to convert products of incomplete combustion (CO and 

VOC) in the presence of oxygen (O2) to carbon dioxide and water. The catalyst 

permits combination of the reactant species at lower gas temperatures and residence 

times than would be required for uncatalyzed oxidation. 

The catalyst would have to be located at a point where the gas temperature is within 

an acceptable range. The effective temperature range for CO oxidation is between 

600oF and about 1,000oF. Catalyst non-selectivity is a problem for sulfur containing 

fuels such as coal. Catalysts promote oxidation of SO2 to SO3 as well as CO to CO2. 

The amount of SO2 conversion is a function of temperature and catalyst design. 

Under optimum conditions, formation of SO3 can be minimized to 5% of inlet SO2. 

This level of conversion would result in a large collateral increase in H2SO4

emissions which aside from the increased ambient air impacts, could result in 

unacceptable amounts of corrosion to the fabric filter particulate collector, air 

preheater, ductwork and stack. 

Because of this technical issue, oxidation catalysts cannot feasibly be applied to 

NGS’ coal-fired boilers. Thus, EPA has determined that oxidation catalysts are 

technically infeasible for application to the coal-fired boilers at the NGS. 

Thermal Oxidation 

Thermal oxidation would involve injecting additional air into the flue gas and heating 

the oxygen enriched mixture to approximately 1,500o

F to oxidize CO to carbon 

dioxide. However, since the combustion of the reheat fuel would also result in CO 

emissions, there is no evidence that thermal oxidation would result in any CO 

emission reductions. Since thermal oxidation has never been demonstrated on a coalfired boiler, and because there is no evidence that it could reduce CO emissions, 

thermal oxidation is not considered by the EPA to be a technically feasible CO 

control technology for NGS’ coal-fired boilers. 

Combustion Practices 

Combustion control refers to controlling emissions of CO through the design and 

operation of the boiler in a manner so as to limit CO formation. In general, a 

combustion control system seeks to maintain the proper conditions to ensure 

complete combustion through one or more of the following operation design features: 

providing sufficient excess air, staged combustion to complete burn out of products of 

incomplete combustion, sufficient residence time, and good mixing. All of these 

factors also tend to reduce emissions of CO. However, this process must be optimized 

with the efforts to reduce NOx emissions, which may increase when steps to lower 

CO are taken. 

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Step 3 – Rank Control Effectiveness of Technically Feasible Control Options

Based on the above analysis, good combustion practices (GCP) is the only technically 

feasible CO control technology for NGS’ pulverized coal-fired boilers. GCP or 

combustion controls generally include the following components: 

• Good air/fuel mixing in the combustion zone 

• High temperatures and low oxygen levels in the primary combustion zone 

• Overall excess oxygen levels high enough to complete combustion while 

maximizing boiler thermal efficiency 

• Sufficient residence time to complete combustion 

Step 4 – Evaluate the Most Effective Controls

Because no specific CO control technologies beyond good combustion practices were 

identified as part of this BACT analysis, additional evaluation is unnecessary. 

Step 5 – Select BACT for CO Emissions

Listings in the RBLC indicate that recent CO BACT emission limits for new coalfired boilers using GCP are generally 0.15 lb/MMBtu. For existing boilers being 

retrofitted with LNBs or other NOx controls, CO BACT limits vary considerably from 

0.15 lb/MMBtu (30-day average) to 1.63 lb/MMBtu (3-hour average). This variability 

is due to several factors such as furnace configurations, excess air, staging of the 

combustion process, coal type, etc. 

Because the boilers at NGS will be retrofitted rather than being originally designed 

for optimum combustion as with new units, it is uncertain whether the retrofitted units 

can achieve the same CO emission rates as new boilers. In addition, NGS is designed 

as a divided furnace which means it is comprised of two furnace cells that share a 

common furnace wall. A divided furnace contains eight windboxes (eight burner 

fronts) which are located on the front and rear of the unit and off the furnace corners. 

Due to the geometry and aerodynamics of a divided furnace, the CO emissions 

typically are higher than those of a traditional four-cornered unit, all other parameters 

being equal. 

The rank of coal can also have an effect on CO emissions. The boilers at the NGS are 

fueled primarily with Western Bituminous coal from the Peabody Western Coal 

Company’s Kayenta Mine. When reducing NOx emissions, CO emissions can be 

more difficult to control with this rank of coal. 

Rather than setting the CO emission rates equal to the lowest proposed BACT limits 

for new units in the RBLC, SRP has proposed a rate of 0.42 lb/MMBtu, based on a 

rolling 30-day average. In order to ensure that SRP will be emitting the lowest 

possible CO emission limit that the units can practically achieve on a continuous 

basis, EPA incorporated the proposed emission rate into the permit along with 

language that will allow this limit to be ratcheted down after the first 18 months of 

operation (“Demonstration Period”) once the LNB/SOFA systems were installed. 

After the Demonstration Period for each boiler, SRP will submit to EPA a written 

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report together with CO CEMS data showing actual CO emissions which evaluates 

whether a lower CO emissions limit can be consistently and reasonably achieved 

while maintaining NOx emission levels at or below 0.24 lb/MMbtu on a 30-day 

rolling average. The report shall provide all supporting documentation identifying the 

combustion characteristics that impact CO emissions and evaluate the potential for 

reducing the CO emission limit to a level that can be consistently and reasonably met. 

Within 30 days after EPA concludes in writing that the report is acceptable, SRP shall 

apply for a permit modification to decrease the CO emission limit. 

Based on the analysis above, we conclude that the use of good combustion practices 

is the best available control technology for CO emissions for Boiler Units 1, 2, and 3 

given the facility’s specific coal and furnace design parameters. This control 

technology can achieve a CO emission rate of 0.42 lb/MMBtu based on a 30-day 

rolling average, excluding periods of startup and shutdown. For periods of startup and 

shutdown, BACT is also good combustion practices. 

VII. AIR QUALITY IMPACTS 

The PSD regulations require an air quality impact analysis to estimate the effects of the 

proposed project on ambient air quality. For all regulated pollutants emitted in 

significant quantities, the analysis must consider whether the proposed project will cause 

a violation of the National Ambient Air Quality Standards (NAAQS) and the applicable 

PSD increments; certain additional impacts must also be assessed. Below are 

descriptions of the general approach, air quality model selection, significant impact 

levels, and the project's compliance with ambient air quality standards. SRP conducted 

modeling of the project via a contractor, RTP Environmental Associates, and submitted a 

modeling report and protocol with the permit application in April 2008 (revised July 

2008). 

The proposed project will result in a significant increase in CO emissions. NOx emissions 

will decrease, and other pollutants would have negligible changes. The project's ambient 

impact is above the significant impact level for CO, triggering the requirement for a 

cumulative impact analysis. The cumulative impact analysis SRP submitted 

demonstrated that the project would not cause or contribute to a violation of the 1-hour or 

8-hour CO NAAQS. 

EPA's conclusion is that SRP used appropriate modeling procedures and followed 

applicable guidance, and demonstrated that the proposed project would not violate any 

NAAQS or PSD increment, and will not have an adverse impact on any Air Quality 

Related Value (AQRV) at any Class I area. 

A. Meteorological and Background Ambient Air Quality Data 

The ambient impact analysis requires representative meteorological data, either 5 years of 

National Weather Service (NWS) data, or a year of on-site data. SRP used upper air data 

from Desert Rock, NV, and surface data from the nearby NWS station at Page Municipal 

Airport. Desert Rock is more distant than the alternative Flagstaff, AZ upper air station, 

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but is more representative since the Flagstaff elevation is substantial different than that at 

the project site. Missing data at Page caused each of the 5 most recent years to be 

somewhat below the 90% completeness EPA threshold for acceptance. To compensate, 

SRP used an additional two years of data so that the total number of hours was more than 

would be available for 5 years at 100% completeness. SRP also checked that the missing 

hours were distributed roughly evenly between the different hours of the day and months 

of the year. Thus a full range of meteorological conditions is represented, including those 

with potentially high modeled impact. EPA believes that this meteorological data is 

representative, and that the processing procedures meet the goals of EPA guidelines for 

meteorological data. 

The ambient impact analysis also requires representative background air quality data, to 

add to modeled values for comparison to the NAAQS. No CO monitor is close by, but 

the Page area is relatively pristine for CO; elevated CO levels are typically driven by high 

traffic density in large urban areas. SRP used ambient data from Maricopa County, 

which up until a few years ago had CO NAAQS violations; background values were 8931 

μg/m3

 for the 1-hour CO NAAQS, and 6069 μg/m3 for the 8-hour CO NAAQS. The use 

of these values is an extremely conservative approach that tends to overstate the 

cumulative impact of the proposed project. 

B. Modeling Methodology 

SRP modeled NGS with AERMOD, the standard EPA-recommended air quality model 

for permitting, with default regulatory options selected. In addition to the meteorological 

inputs discussed above, an air quality model needs inputs characterizing emissions 

sources. SRP modeled the proposed project's emissions assuming 1500 ppm CO 

concentration rates from each boiler, which was based on estimates by a low-NOx burner 

vendor that SRP consulted, plus 50% for conservatism. Based on an "F factor" of 9780 

scf/MMBtu for CO from bituminous coal (40 CFR §60, Appendix A-7, Method 19, table 

19-2), this corresponds to CO emission rates of 1.24 lb/MMBtu, or 9610 lb/hr. (This is 

substantially higher than, though not directly related to, the proposed permit limit of 0.42 

lb/MMBtu.) 

SRP also used inputs for the proposed project's stack height, temperature, and exit 

velocity, which determine the pollutant plume's buoyancy and momentum, and hence its 

distance from the ground. Because these factors vary with the operating load of the 

source, SRP performed load screening, i.e. initial modeling to determine the worst case. 

SRP used AERMOD to estimate impacts under 50%, 75% and 100% load conditions; the 

highest impact occurred for 100% load, which was then used for the rest of the modeling. 

Nearby buildings can cause downwash, in which a pollutant plume is pulled down into 

the building's wake, leading to high pollutant concentrations. SRP simulated this with the 

appropriate AERMOD model options, including effective building dimensions from the 

BPIP software EPA provides for the purpose. 

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Land surface characteristics, such as roughness, affect local meteorology. SRP used 

EPA’s AERSURFACE program to prepare AERMET surface inputs, based on USGS 

National Land Cover Data. Land west of the Page, AZ meteorological station is 

Commercial/Industrial, while land to the east is principally shrubland, with some 

grassland. Terrain elevation data from USGS Digital Elevation Model files was 

processed through AERMAP, which computes effective heights used by AERMOD to 

help determine how the pollutant plume interacts with terrain features. 

The final inputs are the locations, or receptors, at which the model will compute pollutant 

concentrations. SRP used receptors out to 40 km from the source, and additional sets of 

receptors that are progressively more closely spaced nearer the source, and also fence line 

receptors, the closest locations to which the general public has access. The receptors had 

100 m spacing out to 2.5 km, 200 m spacing out to 3.5 km, 500 m spacing out to 6.5 km, 

1 km spacing out to 20 km, and 2 km spacing out to 40 km. To ensure the maximum 

concentration was found, SRP also performed additional modeling on a fine grid with 

100 m spacing centered near the maximum found on the regular grid. Because 100 m 

spacing is somewhat sparse for a fine grid, EPA remodeled the area of greatest impact 

using 25 meters (m) receptor spacing. 

C. NAAQS Compliance 

The proposed project's modeled impacts are shown in Table 4 below. The PSD 

regulations do not allow a project to cause or contribute to a violation of the NAAQS or 

of the PSD increment. EPA interprets this standard to be met when the applicant can 

show that it will not make a “significant” contribution to a violation of a NAAQS or PSD 

increment. That is, the applicant must show that its own impact is below the Significant 

Impact Level (SIL), or else show that there is no violation at locations where its impact is 

above the SIL. The proposed project's modeled impacts from CO exceeded the SIL, 

triggering the requirement for a cumulative analysis, which includes other, nearby 

sources. However, examination of emission inventories for nearby counties showed there 

were no additional sources to include. Thus, SRP used the same modeling results as for 

the proposed project by itself. While SRP could have used the 2nd highest value for 

comparing to the NAAQS, SRP continued to use the 1st high value that was used in 

comparing to the SIL, a conservative approach. As mentioned above, EPA remodeled the 

area of greatest impact using 25 m receptor spacing (Table 5). For most of the seven 

modeled years the impacts were nearly the same as the SRP result, but for the 2005 

modeled year there was a 5% increase. Cumulative impact including background 

concentrations increased less than 3%.SRP's modeling analysis demonstrated that the 

proposed project would remain below both the 1-hour and 8-hour CO NAAQS. 

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Table 4. Modeled maximum project impacts using SRP modeling

Maximum Predicted Air Quality Impacts from the Proposed Project 

(all values in μg/m3) 

Pollutant Averaging 

Period 

Modeled 

Impact 

Significant 

Impact 

Level (SIL) 

Monitored 

Background 

Total 

Concentration NAAQS

1-hour 10,486 2000 8,931 19,417 40,000 CO 

8-hour 1,749 500 6,069 7,818 10,000 

Table 5. Modeled maximum project impacts, including 25 m fine grid

Maximum Predicted Air Quality Impacts from the Proposed Project 

(all values in μg/m3) 

Pollutant Averaging 

Period 

Modeled 

Impact 

Significant 

Impact 

Level (SIL) 

Monitored 

Background 

Total 

Concentration NAAQS

1-hour 11,062 2000 8,931 19,993 40,000 CO 

8-hour 1,844 500 6,069 7,913 10,000 

D. Increment Consumption Analysis and Increment Compliance 

There is no PSD increment defined for CO, so no analysis is required. 

VIII. ADDITIONAL IMPACT ANALYSIS 

In addition to assessing the ambient air quality impacts expected from a proposed new 

source or modification, the PSD regulations require that certain other impacts be 

considered. These include impacts on growth, soils and vegetation, and visibility. 

A. Growth Analysis 

Since this proposed project is a retrofit to an existing source, with no changes in 

operations, there will be no change in the size of the work force, and no expected growth 

impacts. 

B. Soils and Vegetation Analysis 

The PSD regulations require analysis of air quality impacts on sensitive vegetation types, 

with significant commercial or recreational value, and sensitive types of soil. The SRP 

permit application stated that comparison to the NAAQS themselves can be used to 

assess such impacts. However, the NAAQS for CO are primary NAAQS, aimed solely at 

protecting human health. There is no secondary NAAQS, which would be aimed at 

protecting "welfare", including plants. The only available guidance for conducting the 

soils and vegetation analysis is in A Screening Procedure for the Impacts of Air Pollution 

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Sources on Plants, Soils, and Animals (EPA 1980). This document gives a CO screening 

level of 1,800,000 μg/m3

, over a one-week averaging time. The maximum cumulative 

impact of the project was 19,417 μg/m3 with a 1-hour averaging time, far below the 

screening level. Thus, even though comparing a 1-hour average to a weekly level is a 

very conservative procedure, the project passes the screening test. 

C. Visibility Impairment and Air Quality Related Value Analysis 

Since CO has a negligible contribution to visibility impairment, no visibility analysis is 

required. EPA is not otherwise aware of any other Class I Area AQRV that could be 

affected by CO emissions. A visibility improvement is expected from the installation of 

the LNB/SOFA. An analysis provided by SRP for the visibility improvement as a result 

of the burner modifications can be found in the BART regulatory docket at: 

http://www.regulations.gov/fdmspublic/component/main?main=DocketDetail&d=EPAR09-OAR-2008-0454 

IX. ENDANGERED SPECIES 

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued 

existence of any endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. 

For this proposed project, SRP submitted an “Endangered Species Act Analysis” to EPA 

Region 9 in April 2008 (revised July 2008). The proposed project will occur on the active 

plant site which is already a developed industrial area, and it is expected that the species 

identified in the analysis generally avoid human contact and thus avoid the facility area. 

EPA reviewed the analysis and has initiated informal consultation with the U.S. Fish and 

Wildlife Service. EPA expects to conclude the consultation process informally before a 

final decision is made to issue the permit. 

X. CONCLUSION AND ACTION 

Based on the information supplied by SRP, our review of the analyses contained in the 

permit application, and our independent evaluation provided above, it is our 

determination that the proposed project will employ BACT and complies with PSD 

permitting requirements. Therefore, EPA is proposing to issue SRP a PSD Permit (No. 

AZ 08-01) allowing a modification at the Navajo Generating Station. This permit is 

subject to review and comments. A final decision on issuance of the permit will be made 

by EPA after considering comments received during the public comment period and upon 

completion of the ESA consultation process. 

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APPENDIX A 

Emissions Calculations 

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