Prepared for: 

Salt River Project – Navajo Generating Station 

Tempe, AZ 

BART Analysis for the Navajo 

Generating Station Units 1 - 3 

ENSR Corporation 

November 2007 

Document No.: 05830-012-300 
Prepared for: 

Salt River Project – Navajo Generating Station 

Tempe, AZ 

BART Analysis for the Navajo 

Generating Station Units 1 - 3 

_________________________________ 

Prepared By: Olga Kostrova 

_____________________________ _________________________________ 

Reviewed By: Robert Paine and Ian Thomson 

ENSR Corporation 

November 2007 

Document No.: 05830-012-300 
i November 2007

BART Analysis for Navajo Generating Station 

05830-012-300

Contents 

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

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

1.1 Source Description .......................................................................................................................... 1-1

1.2 Reasonably Attributable BART Analysis ........................................................................................ 1-1

1.3 BART Requirements........................................................................................................................ 1-1

1.4 Sulfur Dioxide Emission Control...................................................................................................... 1-2

1.5 Particulate Matter Emission Control................................................................................................ 1-2

1.6 Nitrogen Oxides Emission Control.................................................................................................. 1-2

1.7 Report Outline.................................................................................................................................. 1-3

2.0 CALPUFF Modeling Procedures.......................................................................................................... 2-1

2.1 CALMET Processing ....................................................................................................................... 2-1

2.2 CALPUFF Modeling Procedures..................................................................................................... 2-1

2.3 Natural Conditions and Monthly f(RH) at Class I Areas................................................................. 2-2

2.4 Light Extinction and Haze Impact Calculations .............................................................................. 2-4

3.0 BART Applicability Analysis ................................................................................................................ 3-1

3.1 BART-Eligible Requirements .......................................................................................................... 3-1

3.2 Existing Control Equipment and Emission Rates........................................................................... 3-1

3.3 Affected Class I Areas..................................................................................................................... 3-4

3.4 Baseline CALPUFF Modeling Results............................................................................................ 3-6

4.0 BART Engineering Analysis for NOx Emissions ............................................................................... 4-1

4.1 Identification of Alternative NOx Controls........................................................................................ 4-1

4.1.1 Low-NOx Burners and Separated Overfire Air (LNB/SOFA)............................................ 4-1

4.1.2 Flue Gas Recirculation ...................................................................................................... 4-1

4.1.3 Selective Non-Catalytic Reduction.................................................................................... 4-2

4.1.4 Selective Catalytic Reduction............................................................................................ 4-3

4.1.5 ECOTUBETM...................................................................................................................... 4-4

4.1.6 ROFATM/ROTAMIXTM........................................................................................................ 4-5

4.2 Technical Feasibility of Alternative NOx Controls ........................................................................... 4-5

4.3 Effectiveness of Technically Feasible NOx Controls ...................................................................... 4-5

4.4 Impacts of Alternative NOx Controls ............................................................................................... 4-7

4.4.1 Economic Impacts ............................................................................................................. 4-7

4.4.2 Non-Air Quality Environmental Impacts............................................................................ 4-7
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4.4.3 Energy Impacts................................................................................................................ 4-10

4.4.4 Remaining Useful Life ..................................................................................................... 4-10

5.0 BART Control Options Modeling Analysis......................................................................................... 5-1

5.1 Modeled Control Scenarios............................................................................................................. 5-1

5.2 CALPUFF Modeling Results for Control Options ........................................................................... 5-1

5.3 Cost of BART Control Options ........................................................................................................ 5-2

6.0 BART Recommendations ..................................................................................................................... 6-1

7.0 References.............................................................................................................................................. 7-1

List of Appendices 

Appendix A CALMET/CALPUFF Processing Refinements

Appendix B Factors Influencing NOx Emissions Effects on Visibility

Appendix C Review of Data from the IMPROVE Monitoring Network

Appendix D CALPUFF Modeling Results

Appendix E BART Cost Information

List of Tables 

Table ES-1: Total Capital and Annual Costs Associated with LNB/SOFA, SCR and SNCR Applied to NGS 

Units 1 through 3 ....................................................................................................................ES-4

Table ES-2: Annual Costs vs. Visibility Improvements/Degradation (Average of the Eight Class I Areas)....ES-5

Table ES-3: Selected Best Available Retrofit Technology – Low NOx Burners / Separated Overfire Air .......ES-6

Table 2-1: Annual Average Natural Background Concentrations ............................................................ 2-2

Table 3-1: Navajo Generating Station Baseline Emissions...................................................................... 3-3

Table 3-2: Navajo Generating Station Modeling Stack Parameters ........................................................ 3-4

Table 3-3: Regional Haze Impacts Due to Baseline Emissions............................................................... 3-6

Table 4-1: Annual NOx Emission Rates Resulting from Application of Control Options to NGS Units 1 – 3 

(lb/MMBtu) ................................................................................................................................ 4-6

Table 4-2: Total Capital and Annual Costs Associated with LNB/SOFA, SCR and SNCR Applied to NGS 

Units 1 through 3 ...................................................................................................................... 4-7

Table 4-3: Summary of Non-Air Quality Environmental Impacts.............................................................. 4-9

Table 4-4: Navajo Generating Station SOFA/LNB Emission Controls (Option 1) ................................. 4-11
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Table 4-5: Navajo Generating Station SOFA/LNB Emission Controls (Alternative Option 1)............... 4-12

Table 4-6: Navajo Generating Station SOFA/LNB/SNCR Emission Controls (Option 2)...................... 4-13

Table 4-7: Navajo Generating Station SOFA/LNB/SCR (Option 3) ....................................................... 4-14

Table 4-8: Navajo Generating Station SOFA/LNB/SCR (Option 4) ....................................................... 4-15

Table 5-1: Regional Haze Benefit of BART Controls................................................................................ 5-3

Table 5-2: Regional Haze Results of BART Controls for Each Year and Class I Areas......................... 5-5

Table 5-3: Annual Costs vs. Visibility Improvements/Degradation (Average of the Eight Class I Areas)...... 5-6

Table 6-1: Recommended Best Available Retrofit Technology – Low NOx Burners / Separated Overfire Air....... 6-1

List of Figures 

Figure ES-1 8th Highest Regional Haze Deciview (Includes Background Haze and NGS BART Control Case 

Emissions) ..............................................................................................................................ES-2

Figure 2-1: NGS CALPUFF Computational Grid in Relation to WRAP Arizona Domain ......................... 2-3

Figure 3-1: Class I Areas within 300 km of the Navajo Generating Station.............................................. 3-5

Figure 3-2: 8th Highest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions ..... 3-7

Figure 5-1: 8th Highest Regional Haze Total Impacts Averaged Over 3 Years for Baseline and BART 

Control Case Emissions........................................................................................................... 5-4

Figure 5-2: Annual Costs vs. Visibility Improvements/Degradation (Average of Eight Class I Areas)..... 5-7

Figure 5-3: Annual Costs vs. Visibility Improvements/Degradations at Petrified Forest NP .................... 5-8

Figure 5-4: Annual Costs vs. Visibility Improvements/Degradations at Canyonlands NP........................ 5-9
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BART Analysis for Navajo Generating Station 

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Executive Summary 

The Salt River Project Agricultural Improvement and Power District (SRP) operates the Navajo Generating 

Station (NGS), a coal-fired steam electric generating station located on the Navajo Nation, approximately 

3 miles east of Page, Arizona. The NGS facility became operational in stages between 1974 and 1976 and 

consists of three coal-fired units with a combined net power generating capacity of approximately 2,250 

MW. The facility is approximately 20 kilometers from the northern boundary of Grand Canyon National Park 

(GCNP). 

The Clean Air Act’s Regional Haze Rule (RHR) contains a requirement for each State or Tribe to address 

the Best Available Retrofit Technology (BART) requirement when preparing the State’s Regional Haze State 

Implementation Plan (SIP). Since the Navajo EPA does not have an approved Tribal Implementation Plan, 

the Environmental Protection Agency is currently responsible for implementing the RHR at NGS. This 

BART Analysis for the NGS was prepared pursuant to EPA’s July 6, 2005 final RHR titled “Regional Haze 

Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule” 

(“BART Guidelines”). The BART Guidelines include presumptive BART requirements for coal-fired electric 

steam generating sources greater than 750 MW. 

The EPA has determined that the NGS is a “BART-eligible source”. Based on air dispersion modeling 

performed by ENSR, NGS is “subject to BART”. SRP retained ENSR to perform a BART analysis for all 

three units at NGS. The BART analysis was performed for two pollutants: oxides of nitrogen (NOx) and 

particulate matter (PM). A BART analysis was not performed for SO2 because the flue gas desulfurization 

control system at NGS was previously determined by EPA to satisfy BART. 

A BART review was previously conducted for the Navajo Generating Station in the 1990s as part of the 

Reasonably Attributable BART Program, involving visibility impacts in GCNP. This review concluded that 

sulfates were the major contributors to visibility impairment in the Grand Canyon. As a result, NGS installed 

flue gas desulfurization equipment on all of their units by 1999. In a recent Federal Implementation Plan 

(FIP) for the Four Corners Power Plant, EPA also discussed BART issues for the Navajo Generating Station 

in the May 7, 2007 issue of the Federal Register, with an excerpt provided here: “EPA determined 

previously that the SO2 emission limits in the 1991 FIP for the Navajo Generating Station provide for greater 

reasonable progress toward the national visibility goal than would BART. See 71 FR at 53633 and 72 FR at 

25698 and 25700.

PM emissions are controlled with hot-side electrostatic precipitators in combination with wet scrubbers. 

These controls effectively limit emissions to less than 0.03 lb/MMBtu, which is a PM control standard used 

by EPA in recent New Source Review settlement cases on existing power plants. In addition, PM is not 

believed to be a substantial contributor to regional haze in regional class I areas, so a BART analysis of 

further retrofit controls for PM10 emissions is not included in this report. 

NOx emissions are currently controlled by good combustion practices and close coupled overfire air 

(CCOFA). The baseline peak daily NOx emission rate for Navajo ranges from about 0.45 to 0.50 lb/MMBtu, 

which exceeds the BART presumptive limit of 0.28 lb/MMBtu for dry-bottom, tangentially-fired boilers 

burning bituminous coal. Therefore, NOx controls were considered in this BART analysis for the Navajo 

Generating Station. 

The BART analysis for NOx was conducted in accordance with the procedures contained in the BART 

Guidelines. Consistent with the BART Guidelines, the five steps for a case-by-case BART analysis were 

followed. 
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• Step 1 – Identify all available control technologies, including improvements to existing control 

equipment or installation of new add-on control equipment. 

• Step 2 – Eliminate technically infeasible options considering the commercial availability of the 

technology, space constraints, operating problems and reliability, and adverse side effects on the 

rest of the facility. 

• Step 3 – Evaluate the control effectiveness of the remaining technologies based on current pollutant 

concentrations, flue gas properties and composition, control technology performance, etc. 

• Step 4 – Evaluate the annual and incremental costs of each feasible option using approved EPA 

methods, as well as the associated energy and non-air quality environmental impacts of 

compliance. 

• Step 5 – Determine the visibility impairment associated with baseline emissions and the visibility 

improvements provided by the control technologies considered in the engineering analysis. 

The alternative NOx control technologies identified as being technically feasible at NGS include: low NOx

burners and separated overfire air (LNB/SOFA), selective non-catalytic reduction (SNCR), and selective 

catalytic reduction (SCR). 

The results of the visibility modeling for the candidate BART control options are graphically plotted in Figure 

ES-1. This figure compares the total visibility impairment (expressed in deciviews) for the modeled results 

with output from the three modeled years averaged for each case and the eight closest Class I areas for 

ease of review. 

Figure ES-1 8th Highest Regional Haze Deciview 

(Includes Background Haze and NGS BART Control Case Emissions) 

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

Bryce Canyon Canyonlands Capitol Reef Grand Canyon Mesa Verde Petrified Forest Sycamore

Canyon

Zion

Class I Area

8th Highest delta-deciview

Baseline

Option 1: SOFA/LNB on Units 1-3 (0.24 lb NOx/MMBtu)

Option 1-alt: SOFA/LNB on Units 1-3 (0.20 lb NOx/MMBtu)

Option 2: SOFA/LNB/SNCR on Units 1-3

Option 3: SOFA/LNB/SCR on Units 1&3 and SOFA/LNB on Unit 2

Option 4: SOFA/LNB/SCR on Units 1-3
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Option #1 evaluated the installation of low NOx burners and separated overfire air (LNB/SOFA) at an 

emission rate of 0.24 lb/MMBtu. This is an emission rate that is considered to be readily achievable with the 

application of the technology at NGS. This combustion modification produced visibility improvements 

across the eight parks averaging 0.28 deciviews. For comparison, a deciview (dv) change of 1.0 is 

considered the threshold of humanly-perceived changes in visual air quality. Canyonlands National Park 

demonstrated the greatest visibility improvement with a change of 0.38 deciviews. The hardware capital 

costs of this retrofit option were estimated at $30 million dollars with negligible operation and maintenance 

(O&M) costs relative to the other options. 

An alternative to Option #1 evaluated the installation of low NOx burners and separated overfire air 

(LNB/SOFA) with a reduced emission rate of 0.20 lb/MMBtu. This lower emission represents an “optimal” 

outcome for LNB/SOFA technology at NGS, and may not be achievable. Although many tangentially fired 

units firing western sub-bituminous coals such as those from the Powder River Basin have achieved rates 

well below this rate, there is very little experience with LNB/SOFA retrofits with western bituminous fuels 

comparable to the coal burned at NGS. Lowering the NOx emission rate to 0.20 lb/MMBtu for this 

combustion modification produced visibility improvements across the eight parks averaging 0.36 deciviews. 

Canyonlands National Park demonstrated the greatest visibility improvement with a change of 0.51 

deciviews. The hardware capital costs of this retrofit option were also estimated at $30 million dollars with 

negligible O&M costs relative to other options. 

Option #2 evaluated selective non-catalytic reduction (SNCR) in addition to LNB/SOFA. The injection of 

ammonia (NH3) or urea ((NH2)2CO) into the boiler further lowers NOx emissions but produces the detriment 

of increasing stack emissions of ammonia salts and sulfuric acid mist. These additional fine particulate 

emissions negatively impacted visibility at Capitol Reef, Grand Canyon, and Bryce Canyon National Parks. 

Moreover, on the three year average basis and across the eight parks the visibility impacts did not change 

from the baseline conditions. 

Option #3 evaluated the construction of selective catalytic reduction (SCR) systems for Units 1 and 3 with 

no post-combustion control on Unit 2 (due to very high SCR retrofit costs for that unit) in combination with 

LNB/SOFA for all units. It is not expected that emission characteristics would change if SCR were applied 

without LNB/SOFA. But for purposes of this report it is assumed that LNB/SOFA would reduce annual O&M 

costs associated with SCR and be the better economic decision if SCR were required, and therefore the 

technologies are shown as being applied together. This option demonstrated visibility improvements across 

the eight parks averaging 0.40 deciviews. Canyonlands National Park demonstrated the greatest visibility 

improvement with a change of 0.66 deciviews. 

Option #4 evaluated SCRs for all three units in combination with LNB/SOFA. The hardware capital costs 

associated with this option were estimated at $660 million dollars with annual O&M costs of $12.5 million 

dollars each year. This option produced an average visibility improvement of 0.53 deciviews compared to 

0.28 deciviews for Option #1. Similar to Option #3, if SCR were ever required at the plant, more detailed 

work would be required to determine if the technology would be applied with or without LNB/SOFA. 

The associated annual costs, derived from capital expenditures and annual O&M costs, are shown in Table 

ES-1. The modeled visibility improvements and the calculated cost in terms of dollars per deciview are 

provided in Table ES-2. 
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Table ES-1: Total Capital and Annual Costs Associated with LNB/SOFA, SCR and SNCR Applied to 

NGS Units 1 through 3 

Control 

Option Control Technology 

Total Capital 

Cost 

($) 

 Fixed Capital 

Costs 

($/yr/unit)a

Annual O&M 

Costs 

($/yr) 

Total Annual 

Costs 

($/yr) 

1/alt. 1 LNB/SOFA (Units 1-3) 30,000,000 2,831,700 0 2,831,700 

2 LNB/SOFA&SNCR (Units 1-3) 60,000,000 5,663,000 9,478,000c 15,141,000 

3 LNB/SOFA (Unit 2); 

LNB/SOFA&SCR (Units1&3) 396,000,000b

 37,378,440 8,316,000 45,694,440 

4 LNB/SOFA&SCR (Units 1-3) 660,000,000b 62,297,000 12,474,000 74,771,000 

a

 Fixed capital costs based on a CRF of 0.09439, assuming an interest rate of 7% and amortization period of 20 years. b Total capital costs include costs associated with outages required for installation of control equipment. c

 Annual O&M costs include the lost revenues resulting from ammonia contamination of fly ash from SNCR. 
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Table ES-2: Annual Costs vs. Visibility Improvements/Degradation (Average of the Eight 

Class I Areas) 

Options BART Controls 

8th Highest 

Ave over 3 

Years and 8 

Class I 

Areas 

(total deltadeciview) 

Annualized 

Cost 

($/Year) 

Incremental 

Cost from 

Previous 

Control 

Scenario 

($/Year) 

Incremental 

Cost 

Effectiveness 

Relative to the 

Previous 

Control 

Scenario 

($/deciview)) 

Baseline None 6.27 $0 $0 $0 

Option 1 

LNB/SOFA on 

Units 1-3 5.99 $2,831,700 $2,831,700 $10,031,114 

Alternative 

Option 1 

 LNB/SOFA on 

Units 1-3 5.91 $2,831,700 $0 $0 

Option 2 

LNB/SOFA/SNCR 

on Units 1-3 6.27 $15,141,400 $12,309,700 

Not effective; 

visibility does 

not improve 

from Baseline 

Option 3 

LNB/SOFA/SCR on 

Units 1&3 and 

SOFA/LNB on Unit 

2 

5.88 $45,694,440 $30,553,040 $77,349,468 

Option 4 

LNB/SOFA/SCR on 

Units 1-3 5.74 $74,771,400 $29,076,960 $212,369,763 

ENSR and SRP recommend LNB/SOFA for all three units as the Best Available Retrofit Technology 

alternative for the Navajo Generating Station based on the expected incremental visibility improvement, the 

cost of compliance, energy impacts, and other non-air quality environmental impacts of compliance. 

Control technologies using SNCR and SCR were rejected due to the small incremental improvement (and is 

some cases degradation) in visibility over that resulting from use of LNB/SOFA; increased emissions of 

ammonia, ammonia salts, and sulfuric acid aerosols, which negatively impact local plume visibility; the high 

capital and O&M compliance costs for these technologies; increased generation needed; and other 

considerations associated with the shipping, storage, and injection of anhydrous ammonia. A summary of 

the BART controls is presented in Table ES-3. 
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Table ES-3: Selected Best Available Retrofit Technology – Low NOx Burners / Separated Overfire Air 

Estimated NOx Emission Rate 0.24 lbs/MMBtu, with possible reduction to 0.20 

lb/MMBtu 

NOx Emission Limit Reduction from Baseline 48% at 0.24 lb/MMBtu 

Estimated NOx Reduction (TPY) at 85% 

utilization

22,675 tons per year at 0.24 lb/MMBtu 

Costs of Compliance • $125/ton of NOx removed 

• $30 million capital cost 

• $2.8 million/year annualized cost 

Energy Impacts Slight increase in fuel consumption associated with 

reduced boiler efficiency 

Non-Air Quality Environmental Impacts • Increased LOI of fly ash, which could 

reduce recycling sales 

• Potential for increased corrosion and more 

frequent replacement of furnace waterwall 

tubes 

Modeled Visibility Impacts • 0.38 deciview improvement at 

Canyonlands (largest Class I area 

improvement)

• 0.28 deciview improvement (8-park 

average)
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1.0 Introduction 

1.1 Source Description 

The Salt River Project Agricultural Improvement and Power District (SRP) operates the Navajo Generating 

Station (NGS), a coal-fired electric steam generating station located on the Navajo Nation, approximately 

3 miles northeast of Page, Arizona. The NGS facility became operational in stages between 1974 and 1976 

and consists of three coal-fired units with a combined power generating capacity of 2,250 MW. Each unit 

has a single stack with a height of 236 meters. The facility is approximately 20 kilometers from the northern 

boundary of Grand Canyon National Park (GCNP), which is the closest Class I area to the facility. 

1.2 Reasonably Attributable BART Analysis 

A BART review has already been conducted for the Navajo Generating Station as an implementation of the 

Reasonably Attributable BART Program. In a letter to the Environmental Protection Agency (EPA) dated 

March 24, 1986, the Department of Interior (DOI) certified the existence of visibility impairment at the GCNP, 

and further identified the NGS as a probable source of the impairment. The initial certification was based upon 

photographic evidence. 

In 1991, E.H. Pechan and Associates, Inc. issued a BART Analysis for NGS under EPA contract #68-02-4400. 

The analysis closely followed the 1980 EPA document “Guidelines for Determining Best Available Retrofit 

Technology for Coal-Fired Power Plants and Other Existing Facilities” by addressing six major components: 1) 

types of emission control systems that are possible; 2) the cost of these control systems; 3) energy 

requirements of the possible controls; 4) environmental impacts of these controls on such items as water and 

solid waste disposal; 5) life expectancy of the facility and the possible controls; and 6) the degree of 

improvement in visibility associated with each possible control. 

In August of 1991 as a result of negotiations between representatives of NGS, Environmental Defense Fund 

(EDF), and Grand Canyon Trust (GCT), the parties completed a negotiated memorandum of understanding 

(MOU) which recommended that EPA adopt a regulatory approach designed to achieve a greater degree of 

visibility improvement at GCNP at lower cost than the proposal published by EPA in February 1991. The 

recommendation proposed a 90 percent reduction in sulfur dioxide emissions to be installed on each of the 

three units in stages, with a final completion date in 1999. 

Subsequently, in October 1991, the EPA issued a final rule implementing the recommendations of the MOU. 

Compliance dates for sulfur dioxide controls at NGS were set by the final rule and required 90 percent control, 

based on an annual average, for one unit beginning November 19, 1997, two units beginning November 19, 

1998, and the third unit beginning August 19, 1999. NGS fulfilled the rule requirement with the installation of 

sulfur dioxide controls on the final unit in 1999. 

1.3 BART Requirements 

Federal regulations under 40 CFR 51, Appendix Y, provide guidance and regulatory authority for conducting a 

visibility impairment analysis for designated eligible sources. The program requires the application of BART to 

those existing eligible sources that are believed to cause or contribute to visibility impairment in order to help 

meet the targets for visibility improvement at designated Class I areas. All three units at the NGS are BART 

eligible because they meet the following criteria: 

1. The units were “in existence” on August 7, 1977, but had not been in operation for more than 15 years 

as of that date. 

2. The sum of the emissions of any single visibility-impairing pollutant from the affected units is greater 

than 250 tons/year. 
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3. NGS is a “fossil-fuel fired steam electric plant of more than 250 MMBtu/hr heat input”, and thus is in 

one of the categories of sources identified in the regional haze rule. 

4. In addition, because the plant has a capacity of greater than 750 MW, it is subject to the presumptive 

BART requirements identified in 40 CFR Part 51, Appendix Y. 

The RHR provides that BART-eligible sources that may reasonably be anticipated to cause or contribute to 

visibility impairment at a federal Class I area are “subject to BART”. The “contribution” threshold for visibility 

impairment is a 0.5 deciview change. ENSR has conducted BART exemption modeling of Units 1-3, and the 

results indicate that these units are subject to BART review because the predicted visibility impacts with 

baseline emissions exceed 0.5 delta deciviews in at least one Class I area. 

1.4 Sulfur Dioxide Emission Control 

SO2 emissions at NGS are controlled by wet limestone forced-oxidation flue gas desulfurization (FGD) 

scrubbers, in response to the previous Reasonably Attributable BART process. In a recent Federal 

Implementation Plan (FIP) for the Four Corners Power Plant, EPA discussed BART issues for the Navajo 

Generating Station, with an excerpt provided here: 

Moreover, as explained in the preamble to the 2006 proposed FIP, there are only two major sources of SO2 on 

the Navajo Reservation that are potentially subject to the BART requirements--Navajo Generating Station and 

FCPP. See 71 FR at 53633 and 72 FR at 25698 and 25700. EPA determined previously that the SO2

emission limits in the 1991 FIP for the Navajo Generating Station provide for greater reasonable progress 

toward the national visibility goal than would BART. 

Based on stack test data, the SO2 removal efficiencies are on the order of 95%. The existing SO2 emission 

limit for Navajo is 0.10 lbs/MMBtu on a 365-day boiler operating day average. This SO2 emission limit is more 

restrictive than the presumptive BART limit for tangentially fired boilers burning bituminous coal of 0.15 

lb/MMBtu. Consequently, no further analysis of BART controls for SO2 is presented in this report. 

1.5 Particulate Matter Emission Control 

The use of hot-side ESPs and wet scrubbers effectively limits the PM emissions from Navajo Units 1 through 3 

at the Navajo Generating Station. During historic stack tests at the plant, filterable PM is typically less than 

0.30 lb/MMBtu. These emissions rates are comparable to emissions limits applied to new coal-fired power 

plants and limits included in New Source Review settlements for existing coal-fired power plants. Thus, 

application of additional particulate controls to NGS would not be expected to produce substantial additional 

reductions in PM emissions, and an evaluation of PM controls is not included in this document. BART for PM 

is considered to be the current control configuration. 

1.6 Nitrogen Oxides Emission Control 

NOx emissions at NGS are controlled by good combustion practices and CCOFA. Baseline peak daily NOx

emissions for NGS range from about 0.45 to 0.50 lb/MMBtu, which exceeds the BART presumptive limit of 

0.28 lb/MMBtu for dry-bottom, tangentially-fired boilers burning bituminous coal. Therefore, this BART 

analysis considers BART control options for NOx. 

The BART analysis for NOx was conducted in accordance with the procedures contained in the Final BART 

Guidelines. Consistent with the BART Guidelines, the five steps for a case-by-case BART analysis were 

followed. 

• Step 1 – Identify all available control technologies for the unit, including improvements to existing 

control equipment or installation of new add-on control equipment. 
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• Step 2 – Eliminate technically infeasible options considering the commercial availability of the 

technology, space constraints, operating problems and reliability, and adverse side effects on the rest 

of the facility. 

• Step 3 – Evaluate the control effectiveness of the remaining technologies based on current pollutant 

concentrations, flue gas properties and composition, control technology performance, and other 

factors. 

• Step 4 – Evaluate the annual and incremental costs of each feasible option in accordance with 

approved EPA methods, as well as the associated energy and non-air quality environmental impacts 

of compliance. 

• Step 5 – Determine the visibility impairment associated with baseline emissions and the visibility 

improvements provided by the control technologies considered in the engineering analysis. 

This report documents the case-by-case BART analysis conducted for NOx emissions from Units 1 through 3 

at the Navajo Generating Station. 

1.7 Report Outline 

Section 2 of this report discusses the general CALPUFF modeling approach. It refers to more detailed 

discussions in appendices attached to this report for meteorological data processing as well as the CALPUFF 

modeling approach for the visibility impact analysis. A presentation of the baseline emission impacts on the 

nearby Class I areas for the BART exemption analysis is provided in Section 3. Because this section indicates 

that the incremental visibility impact of the plant is in excess of the EPA-designated limit of 0.5 delta deciviews 

for contributing to visibility impairment, a BART engineering analysis was conducted on available NOx control 

options, as presented in Section 4. A CALPUFF modeling analysis was conducted for these control options; 

the results are presented in Section 5. A recommendation for BART controls is presented in Section 6, based 

upon the information presented in Sections 4 and 5. References are provided in Section 7. 
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2.0 CALPUFF Modeling Procedures 

For the refined CALPUFF modeling, SRP followed the WRAP common BART modeling protocol with the 

exception of the model version and a few refinements to CALMET settings. These differences are discussed 

below in Section 2.2. 

2.1 CALMET Processing 

The Western Regional Air Partnership (WRAP) has developed six 4-km CALMET meteorological databases 

for three 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 NGS was done using the Arizona 4-km domain, as shown in Figure 2-1 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 (DEM) 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 (CTG) 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 NGS was done using the Arizona 4-km CALMET database with application-specific 

modifications described in Appendix A. 

2.2 CALPUFF Modeling Procedures 

SRP 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. It is clear from the discussion provided in 

Appendix A that CALPUFF version 6 is not approvable by EPA at this time without a significant effort to 

show that it is technically superior. 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 2-1. The BART CALPUFF 

modeling for NGS was done using a smaller computational grid within the WRAP domain to minimize 

computation time and output file size. The computational grid domain is also shown in Figure 2-1. This 

domain includes eleven 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 puffs 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 three years (2001-2003), available at 

http://pah.cert.ucr.edu/aqm/308/bart/calpuff/ozone_dat/. Data collection and processing are described in 
2-2 November 2007

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Section 3.1.2.7 of the WRAP protocol. These ozone data files were used as input to CALPUFF. The monthly 

ammonia background concentrations selected for use in CALPUFF are discussed in Appendices A and B. 

2.3 Natural Conditions and Monthly f(RH) at Class I Areas 

Eleven Class I areas were modeled for the Navajo Generating Station. 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 natural background light 

extinctions shown in Table 2-1, modified as noted below with site-specific considerations, and corresponding 

to the annual average (EPA 2003, Appendix B), consistent with the July 19, 2006 EPA guidance to Region 4 

on this issue (“Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations”, Joseph W. Paise/ EPA OAQPS to Kay Prince/Branch Chief). 

Table 2-1: Annual Average Natural Background Concentrations 

Class I Area 

Natural Background 

Concentrations 

(deciviews) 

Natural Background 

Concentrations (Mm-1) 

Arches National Park 4.43 5.57 

Bryce Canyon 4.43 5.57 

Canyonlands National Park 4.45 5.60 

Capitol Reef National Park 4.47 5.64 

Grand Canyon National Park 4.39 5.51 

Mesa Verde National Park 4.53 5.73 

Mazatzal Wilderness 4.35 5.45 

Petrified Forest National Park 4.41 5.54 

Sycamore Canyon 4.40 5.53 

Pine Mountain 4.36 5.47 

Zion 4.42 5.56 

To determine the input to CALPOST, it is first necessary to convert the deciviews to extinction using the 

equation: 

Extinction (Mm-1) = 10 exp(deciviews/10). 

For example, for Arches, 4.43 deciviews is equivalent to an extinction of 5.57 inverse megameters (Mm-1); this 

extinction excludes the default 10 Mm-1 for Rayleigh scattering. This remaining extinction is due to naturally 

occurring particles, and is held constant for the entire year’s simulation. Therefore, the data provided to 

CALPOST for Arches would be the total natural background extinction minus 10 (expressed in Mm-1), or 5.57. 

This is most easily input as a fine soil concentration of 5.57 μg/m3

 in CALPOST, since the extinction efficiency 

of soil (PM-fine) is 1.0 and there is no f(RH) component. The concentration entries for all other particle 

constituents would be set to zero, and the fine soil concentration would be kept the same for each month of the 

year.

The monthly values for f(RH) that CALPOST needs were taken from "Guidance for Tracking Progress Under 

the Regional Haze Rule" (EPA, 2003) Appendix A, Table A-3. 
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Figure 2-1: NGS CALPUFF Computational Grid in Relation to WRAP Arizona Domain 
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2.4 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 sourcecaused 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. 
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3.0 BART Applicability Analysis 

3.1 BART-Eligible Requirements 

The BART-affected emission units at the NGS are Units 1, 2, and 3. The units are BART eligible because they 

meet the following criteria: 

1. The units were “in existence” on August 7, 1977, but had not been in operation for more than 15 years 

as of that date. 

2. The sum of the emissions of any single visibility-impairing pollutant from the affected units is greater 

than 250 tons/year. 

3. NGS is a “fossil-fuel fired steam electric plant of more than 250 MMBtu/hr heat input”, and thus is in 

one of the categories of sources identified in the regional haze rule. 

In addition, because the plant has a capacity of greater than 750 MW, it is subject to the 

presumptive BART requirements identified in 40 CFR Part 51, Appendix Y. 

Because the NGS units are BART-eligible, the next step in the process is to determine whether the BARTeligible emissions contribute to a perceptible visibility impact at any Class I area. The contribution threshold is 

a modeled change in the natural background visibility of 0.5 delta-deciview. This modeling assessment is 

described in Section 4. 

3.2 Existing Control Equipment and Emission Rates 

For purposes of determining BART applicability, the SO2 and NOx baseline emissions were determined by 

ENSR using CEMS data compiled in baseline calendar years 2001 through 2003. PM filterable baseline 

emissions were also determined by ENSR based on stack test data and CEMS data collected in 2001 through 

2006. 

For purposes of determining BART applicability, the SO2 and NOx baseline emissions were based on the 

highest calendar day emission rates for each pollutant and the highest daily heat input rate for each individual 

unit compiled by the CEMS for baseline calendar years 2001-2003. The determination of the highest daily 

emissions did not consider emissions associated with malfunctions, start-up, and shutdown, consistent with 

the WRAP BART protocol. Filterable PM baseline emissions were based on stack test data for each individual 

unit over the period of 2001-2006 and the highest daily heat input rate for each individual unit during the period 

2001-2003. 

Speciation of the particulate matter emissions into filterable and condensable PM components 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% of the filterable PM emissions are 

filterable PM10 and 29% 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% 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-D98-046, January 2002. 
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• 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 2007. For 

coal-fired boilers, H2SO4 emissions are determined by the following relationship: 

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

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

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

F1 is the fuel factor (0.00111 for western bituminous coal), and 

F2 is the control factor (0.63 for a hot-side ESP, 0.56 for an air pre-heater, and 

0.40 for a wet FGD). 

• For coal-fired boilers with FGD, the total condensable organic PM10 emission factor is 0.004 lb/MMBtu 

based on AP-42, Table 1.1-5. 

Table 3-1 summarizes the baseline emissions that were used in the modeling of baseline conditions. 

Table 3-2 presents the stack parameters that were used for baseline conditions, as well as the BART control 

options. 
3-3 

BART Analysis for Navajo Generating Station 05830-012-300

Table 3-1: Navajo Generating Station Baseline Emissions 
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Table 3-2: Navajo Generating Station Modeling Stack Parameters 

Units Unit 1 Unit 2 Unit 3 

Latitude Deg 36.90500 36.90417 36.90333 

Longitude Deg -111.38917 -111.38889 -111.38833 

Stack Height Ft 775 775 775 

Base Elevation Ft 4,365 4,365 4,365 

Diameter Ft 24.5 24.5 24.5 

Flow ACFM 2,497,502 2,497,502 2,497,502 

Gas Exit Velocity ft/min 5,298 5,298 5,298 

Stack Gas Exit Temperature Deg F 119 119 119 

Lambert Conformal X (1) Km -1267.800 -1267.790 -1267.750 

Lambert Conformal Y (1) Km -241.690 -241.784 -241.884 

Stack Height M 236.2 236.2 236.2 

Base Elevation M 1,330.5 1,330.5 1,330.5 

Diameter M 7.47 7.47 7.47 

Gas Exit Velocity m/s 26.91 26.91 26.91 

Stack Gas Exit Temperature Deg K 321.5 321.5 321.5 

Lambert Conformal coordinate system is based on 40 deg N/97 deg W projection origin, 33 deg N/45 deg N standard 

parallels and NWS-84 datum. 

3.3 Affected Class I Areas 

Class I areas within 300 km of the facility are shown in Figure 3-1 and include the following eleven Class I 

areas: 

1. Arches National Park 

2. Bryce Canyon National Park 

3. Canyonlands National Park 

4. Capitol Reef National Park 

5. Grand Canyon National Park 

6. Mazatzal Wilderness 

7. Mesa Verde National Park 

8. Petrified Forest National Park 

9. Pine Mountain Wilderness 

10. Sycamore Canyon Wilderness 

11. Zion National Park 
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Figure 3-1: Class I Areas within 300 km of the Navajo Generating Station 
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3.4 Baseline CALPUFF Modeling Results 

CALPUFF modeling results of the baseline emissions at eleven Class I areas are presented in Table 3-3 and 

graphically plotted in Figure 3-2. Modeling was conducted for all three years of CALMET meteorological data 

(2001-2003). 

For each Class I area and year, Table 3-3 lists the 8th highest delta-deciview, and the total 8th highest deciview 

(source contribution plus the natural background). Figure 3-2 shows the total 8th highest deciview impacts. 

The figure indicates that the higher visibility impacts generally occur at Grand Canyon National Park, Capitol 

Reef National Park, and Canyonlands National Park. Higher impacts at these Class I area are due to their 

proximity to NGS and local meteorological conditions. 

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 Navajo 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 NGS 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 4. The 

results of the visibility improvement modeling for these candidate controls are discussed in Section 5. The 

final BART recommendations are provided in Section 6. 

Table 3-3: Regional Haze Impacts Due to Baseline Emissions 
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Figure 3-2: 8th Highest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions 

SRP Navajo Generating Station 

Regional Haze Impacts for each Modeled Year Due to Baseline Emissions

Impacts Include Annual Average Background

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Arches NP

Bryce Canyon NP

Canyonlands NP

Capitol Reef NP

Grand Canyon NP

Mazatzal W

Mesa Verde NP

Petrified Forest NP

Pine Mountain W

Sycamore Canyon

W

Zion NP

Class I Area

8th Highest deciview

Met Year 2001 Met Year 2002 Met Year 2003

 
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4.0 BART Engineering Analysis for NOx Emissions 

Nitrogen oxides (NOx) formed during the combustion of coal are generally classified as either thermal NOx or 

fuel-bound NOx. Thermal NOx is formed when elemental nitrogen in the combustion air is oxidized at the high 

temperatures in the primary combustion zone, yielding nitrogen oxide (NO) and nitrogen dioxide (NO2). The 

rate of formation of thermal NOx is a function of residence time and free oxygen, and increases exponentially 

with peak flame temperatures. Thermal NOx from coal combustion can be effectively controlled by techniques 

that limit available oxygen or reduce peak flame temperatures in the primary combustion zone. Fuel-bound 

NOx is formed by the oxidation of chemically bound nitrogen in the fuel. The rate of formation of fuel-bound 

NOx is primarily a function of the coal nitrogen content, but is also affected by gas turbulence and fuel/air 

mixing. 

The following sections describe (1) the technologies for reducing NOx emissions from coal fired power plants, 

(2) the feasibility of applying such controls to NGS, (3) the expected effectiveness of such controls if used at 

NGS, and (4) the impacts of implementing such controls at NGS. 

4.1 Identification of Alternative NOx Controls 

The alternative NOx control technologies available for limiting NOx emissions from Units 1 through 3 include 

combustion techniques, such as LNB/SOFA systems and flue gas recirculation, and post-combustion controls, 

such as selective non-catalytic reduction (SNCR), selective catalytic reduction (SCR), ECOTUBETM, and 

ROFATM/ROTAMIXTM,. These alternative NOx control technologies are evaluated below in terms of their 

possible application to Unit 1 through 3. 

4.1.1 Low-NOx Burners and Separated Overfire Air (LNB/SOFA) 

LNB/SOFA systems in tangentially fired boilers are designed to control fuel and air mixing to reduce peak 

flame temperatures, resulting in less NOx formation. Combustion, reduction, and burnout are achieved in three 

stages within a conventional low NOx burner. In the initial stage, combustion occurs in a fuel-rich, oxygendeficient zone where the NOx is formed. A reducing atmosphere follows where hydrocarbons are formed that 

react with the already formed NOx. In the third stage, internal air staging completes the combustion, but may 

result in additional NOx formation. This, however, can be minimized by completing the combustion in an airlean environment. Combustion air is separated into primary and secondary flow sections to achieve complete 

burnout and to encourage the formation of nitrogen, rather than NOx. Primary air (70-90%) is mixed with the 

fuel, producing a relatively low-temperature, oxygen-deficient, fuel-rich zone and, therefore, reducing the 

formation of fuel-bound NOx. Secondary air representing 10-30% of the combustion air is injected above the 

combustion zone through a special wind-box with air introducing ports and/or nozzles mounted above the 

burners. Combustion is completed at this increased flame volume. Hence, the relatively low-temperature 

secondary stage limits the production of thermal NOx. The location of the injection ports and mixing of overfire 

air are critical to maintain efficient combustion. Retrofitting SOFA on an existing boiler involves waterwall tube 

modifications to create the ports for the secondary air nozzles and the addition of ducts, dampers, and the 

wind-box. The effectiveness of the technology at reducing NOx is influenced by a number of site specific 

factors including fuel characteristics (e.g., nitrogen content, ratio of fixed to volatile carbon, heat content), 

furnace geometry, structural factors that may limit options for locations of SOFA ports, etc. 

4.1.2 Flue Gas Recirculation 

Flue gas recirculation for NOx control includes gas recirculation into the furnace or into the burner. In this 

technology, 20 to 30% of the flue gas (at 350-400°C) is recirculated and mixed with the combustion air. The 

resulting dilution in the flame decreases the temperature and availability of oxygen, thereby reducing 

thermal NOx formation. When flue gas recirculation into the burner is used in low NOx burners, the flue gas 

is usually recirculated subject to the operational constraints of flame stability and impingement. Retrofitting 

an existing coal-fired unit with flue gas recirculation involves installation of a system to extract the flue gas 
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from the boiler unit, additional ductwork, fan, and a fly ash collecting device. The fly ash control device is 

necessary in order to clean the flue gas of particulate matter prior to recirculation. Heat distribution in the 

furnace may be affected due to the increase in throughput. Excessive flue gas recirculation can also result 

in flame instability problems and increased steam temperatures. Flue gas recirculation alone in coal-fired 

boilers achieves a low NOx reduction efficiency of less 20%. This is because the ratio of thermal-NOx to 

total NOx emissions is relatively low in coal-fired plants. 

4.1.3 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction is based on a gas-phase homogeneous reaction that involves the injection of 

an amine-based compound into the flue gas within an appropriate temperature range for reduction of NOx. An 

amine-based compound, such as ammonia, NH3, or urea, (NH2)2CO, is used as the NOx reducing agent in 

SNCR processes. When ammonia or urea is injected into the flue gas stream, it selectively reduces the NOx

into molecular nitrogen, N2, and water, H2O. At stoichiometric conditions, when the adequate residence time 

is reached, the overall reactions that occur may be characterized by: 

Ammonia 

4NO + 4NH3 + 02 → 4N2 + 6H20 

2NO2 + NH3 + 02 → 3N2 + 6H20 

Urea

2(NH2)2CO + 4NO + O2 → 4N2 + 2CO2 + 4H2O 

In an SNCR system, NOx reduction does not take place in the presence of a catalyst, but rather is driven by 

the thermal decomposition of ammonia or urea and the subsequent reduction of NOx. Consequently, the 

SNCR process operates at higher temperatures than the SCR process. Critical to the successful reduction of 

NOx with SNCR is the temperature of the flue gas at the point where the reagent is injected. For the ammonia 

injection process, the necessary temperature range is 1,700 to 1,900°F. The other factors affecting SNCR 

performance are gas mixing, residence time at operating temperatures, and ammonia slip. 

Because oxygen is present in the flue gas, a portion of the ammonia may oxidize at temperatures greater than 

2,000°F. Above 2,000°F, the reaction of ammonia oxidation becomes predominant. Nitrogen monoxide is 

formed as a product of this reaction of ammonia oxidation. As a result, when the flue gas temperature at 

reagent injection locations is higher than the appropriate temperature window, the SNCR process results in 

NOx formation rather than NOx reduction. At temperatures lower than the required temperature window, the 

NOx reduction reaction rates become lower, and unreacted ammonia may slip through and be emitted to the 

atmosphere. 

As with SCR, SNCR equipment vendors suggest a higher ammonia injection rate than is stoichiometrically 

required to achieve higher NOx control efficiencies. The various SNCR vendors typically will not provide a 

guarantee against ammonia slip of less than 5 ppm for systems designed for high NOx performance levels. 

This excess ammonia may react with SO3 and water vapor to form ammonium bisulfate and ammonium 

sulfate. Although no SO2 is oxidized by the SNCR system, naturally occurring SO3 concentrations are high 

enough to be a concern with potentially high ammonia slip rates. Ammonium bisulfate may precipitate out at 

air heater operating temperatures and can ultimately lead to air heater fouling and plugging. Furthermore, the 

ammonium salts may condense as the flue gases cool and can lead to increased emissions of both PM10 and 

PM2.5. Ammonia slip from SNCR systems occurs either from injection at temperatures too low for effective 

reaction with NOx or from over-injection of reagent, leading to uneven distribution. Controlling ammonia slip in 

SNCR systems is difficult as there is no opportunity for effective feedback to control reagent injection. The 

reagent injection system must be able to place the reagent where it is most effective within the boiler because 
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NOx distribution varies within the cross section. An injection system that has too few injection control points or 

fails to inject a uniform amount of ammonia across the entire section of the boiler will almost certainly lead to a 

poor distribution ratio and high ammonia slip. Distribution of the reagent can be especially difficult in larger 

coal-fired boilers because of the long injection distance required to cover the relatively large cross-section of 

the boiler. Multiple layers of reagent injection as well as individual injection zones in the cross-section of each 

injection level are commonly used to follow the temperature changes caused by boiler load changes. 

On small coal-fired units (i.e., less than 200 MW), SNCR has been demonstrated to achieve NOx reductions 

ranging from 25 to 50% with acceptable levels of ammonia slip. This variation in NOx reduction depends on 

site-specific considerations and the amount of ammonia slip considered acceptable. In practical 

applications, non-uniformities in velocity and temperature at the reagent injection location can pose 

operational difficulties because of the inherent sensitivity of the process to these parameters. The physical 

location of the effective temperature range within the boiler depends on operating factors such as unit load, 

combustion air distribution, and soot blowing cycles. Generally, these factors require the utilization of 

multiple injection elevations in full-scale systems. For larger boilers (i.e., greater than 300 MW), there are 

numerous challenges associated with applying SNCR. In particular, such boilers’ large physical dimensions 

pose challenges for injecting and mixing the reagent with the flue gas. Another issue with larger units is the 

fact that the SNCR temperature window often exists within the convective passes. Demonstrations at the 

Port Jefferson, Morro Bay, and Merrimac plants have shown that injecting in the convective pass can create 

high ammonia slip due to limited residence time at the operating temperatures of SNCR.1,2

EPRI sponsored a computational fluid dynamics modeling program to evaluate the performance of SNCR 

on Southern Company Service’s Wansley Unit 1 located in Roopville, Georgia. This 880-MW unit is a 

tangentially-fired boiler equipped with a low-NOX burner and separated overfire air. The modeling results 

demonstrated that SNCR has the potential to reduce NOx emissions by only 22% with an acceptable 

ammonia slip of 6 ppm. The firing characteristics of the boiler make achieving higher levels of NOx

reduction impractical. The most influential factor is the separated overfire air system, which elevates upper 

furnace temperatures by causing the combustion process to extend beyond the furnace nose and into the 

convection section.3

4.1.4 Selective Catalytic Reduction 

Selective catalytic reduction is a process that involves post-combustion removal of NOx from flue gas utilizing a 

catalytic reactor. In the SCR process, ammonia injected into the flue gas reacts with nitrogen oxides and 

oxygen to form nitrogen and water vapor. The SCR process converts NOx to nitrogen and water by the 

following general reactions: 

 4NO + 4NH3 + O2 → 4N2 + 6H2O 

 2NO2 + 4NH3 + O2 → 3N2 + 6H2O 

The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively lower the 

activation energy of the NOx decomposition reaction to about 375° to 750°F, depending on the specific catalyst 

and other contaminants in the flue gas. The factors affecting SCR performance are catalyst reactor design, 

optimum operating temperature, sulfur content of the fuel, catalyst deactivation due to aging or poisoning, 

ammonia slip emissions, and design of the ammonia injection system. 

 

1

 Shore, D., et al, "Urea SNCR Demonstration at Long Island Lighting Company's Port Jefferson Station, 

Unit 3," Proceedings of the EPRI/EPA Joint Symposium on Stationary Combustion NOx Control, May 1993. 2

 Lin, Chin-I, " Full Scale Tests of SNCR Technology on a Gas-Fired Boiler," EPRI Workshop on NOx

Controls for Utility Boilers, July 1992. 

3

 Harmon, A., et al., “Evaluation of SNCR Performance on Large-Scale Coal-Fired Boilers,” Institute of Clean Air 

Companies (ICAC) Forum on Cutting NOx Emissions, Durham, NC, March 1998. 
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The SCR system includes a number of subsystems, including the SCR reactor, ammonia injection system, and 

ammonia storage and delivery system. The SCR reactor is located downstream of the economizer and 

electrostatic precipitators, and upstream of the air pre-heater. From the ESP outlet, the flue gas first passes 

through a low-pressure ammonia/air injection grid designed to provide optimal mixing of ammonia with flue 

gas. The ammonia-treated flue gas then flows through the catalyst bed and exits to the air pre-heater. The 

SCR system for a pulverized coal boiler typically uses a fixed bed catalyst in a vertical down-flow, multi-stage 

reactor. 

Reduction catalysts are divided into two groups: base metal, primarily vanadium, platinum, or titanium (lower 

temperature); and zeolite (higher temperature). Both groups exhibit advantages and disadvantages in terms 

of operating temperature, ammonia-NOx ratio, and optimum oxygen concentration. The optimum operating 

temperature for a vanadium-titanium catalyst system is in the range of 550° to 800°F, which is significantly 

higher than for platinum catalyst systems. However, the vanadium-titanium catalyst systems begin to break 

down when continuously operating at temperatures above this range. Operation above the maximum 

temperature results in oxidation of ammonia to either ammonia sulfate or NOx, thereby actually increasing NOx

emissions. 

To achieve high NOx control efficiencies, the SCR vendors suggest a higher ammonia injection rate than is 

stoichiometrically required to react all of the NOx in the combustion gases. This results in emissions of unreacted ammonia or “ammonia slip.” The various SCR vendors typically guarantee ammonia slip of about 2 

ppm for systems designed for very high NOx performance levels. This excess ammonia may react 

with SO3 and water vapor to form ammonium bisulfate (NH4)HSO4 and ammonium sulfate (NH4)2SO4. Higher 

levels of ammonia and SO2 result in higher levels of ammonium bisulfate and ammonia sulfate. These 

ammonium salts may condense as the flue gases cool and can lead to increased emissions of both PM10 and 

PM2.5. Furthermore, the catalyst promotes the partial oxidation of SO2 to SO3, which in turn combines with 

water, increasing the formation of these ammonia salts and potential emissions of PM10 and PM2.5. 

Some SCR installations have experienced significant air pre-heater plugging and corrosion resulting from 

the deposition of ammonium bisulfate. The plugging and corrosion can cause reduced boiler efficiency, 

higher flue gas pressure drop, more frequent air pre-heater cleaning and washing, increased boiler 

downtime, and increased maintenance cost. The primary factors for controlling the formation and deposition 

of ammonium bisulfate are the level of ammonia, the level of SO3, the air pre-heater surface temperature 

profile, the air pre-heater surface material, and the air pre-heater physical configuration. The temperature 

window for ammonium bisulfate deposition is as wide as 300 to 425°F. The temperature window for sulfuric 

acid formation, which is primarily a function of SO3 concentration, is significantly lower, but must also be 

evaluated in system design. 

The SCR system is subject to catalyst deactivation over time. Catalyst deactivation occurs through two 

primary mechanisms: physical deactivation and chemical poisoning. Physical deactivation generally results 

from either prolonged exposure to excessive temperatures or masking of the catalyst due to entrainment of 

particulate from ambient air or internal contaminants. Chemical poisoning is caused by the irreversible 

reaction of the catalyst with a contaminant in the gas stream and thus is a permanent condition. Catalyst 

suppliers typically guarantee a limited lifetime for high performance catalyst systems. Fly ash plugging 

generally results from excessive fly ash carryover to the catalyst or poor catalyst gas flow design. Gas, ash, 

and ammonia flow distribution modeling is critical in the design phase. 

4.1.5 ECOTUBETM 

The ECOTUBETM system is a hybrid NOx reduction system that combines SOFA and SNCR technologies. 

Retractable lance tubes that penetrate the boiler above the primary burner zone inject high-velocity air, 

which creates turbulent airflow and increases the residence time for the air/fuel mixture. The water-cooled 

ECOTUBEs are automatically retracted from the boiler on a regular basis and cleaned to remove layers of 

soot and other depositions. 
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4.1.6 ROFATM/ROTAMIXTM 

Mobotec provides a NOx reduction system that combines OFA and SNCR technologies into an integrated 

system. The system uses a modified OFA system with improved mixing characteristics achieved through 

adding a rotation to the OFA. This system is called ROFATM - Rotating Opposed Firing Air. In addition, 

ROTAMIXTM, consisting of adding urea or ammonia injection into the ROFA air nozzles, can be added to the 

system. The extra mixing produced by combining the ROFA nozzles with the reagent injection results in 

improved mixing and a more homogeneous temperature profile in the boiler. This NOx reduction system 

has primarily been applied to smaller units, with the vendor reporting NOx reductions of up to 75%. 

4.2 Technical Feasibility of Alternative NOx Controls 

Of the technologies discussed above, the following are not considered technically feasible for application to 

Navajo Units 1 through 3: 

• Flue gas recirculation (FGR) has been demonstrated on units of the same scale as NGS Units 1 

through 3 but has not been demonstrated to achieve NOx reduction that is more effective than staged 

combustion techniques such as LNB/SOFA. 

• ECOTUBE has not been demonstrated on units of the same scale and design as NGS Units 1 through 

3. 

• The Mobotec ROFA/ROTAMIX system has not been demonstrated on units of the same scale and 

design as NGS Units 1 through 3. 

Therefore, the BART analysis is limited to those technologies that have been demonstrated to achieve 

significant NOx reduction on units of the same scale and design as Navajo Units 1 through 3: LNB/SOFA; 

LNB/SOFA plus SNCR; and LNB/SOFA plus SCR. 

4.3 Effectiveness of Technically Feasible NOx Controls 

The alternative NOx control technologies, LNB/SOFA, SCR, and SNCR, have been successfully applied to 

new utility coal-fired boilers, as well as retrofitted to existing utility coal-fired boilers. The effectiveness of these 

technologies in reducing NOx emissions is dependent primarily on the inlet NOx concentrations, residence 

time, and operating temperatures. Staged combustion techniques have been demonstrated to achieve up to 

50% reduction in uncontrolled NOx emissions from coal-fired utility boilers. SNCR has been demonstrated to 

achieve NOx control efficiencies ranging from 25% to 50% with inlet NOx concentrations of 300 to 400 ppmvd. 

If staged combustion is used to reduce inlet NOx concentrations to less than 150 ppmvd, SNCR is capable of 

achieving NOx control efficiencies of only 10 to 25%. Likewise, SCR can achieve NOx control efficiencies as 

high as 90% with inlet NOx concentrations in the range of 300 to 400 ppmvd. If inlet NOx concentrations are 

less than 150 ppmvd, SCR can achieve NOx control efficiencies of only 50 to 70%. 

Based on information provided by equipment vendors, it is estimated that LNB/SOFA will reduce NOx

emissions to an emission level of approximately 0.24 lb/MMBtu. Due to the lower inlet NOx concentrations, it 

is estimated that the addition of SNCR will reduce NOx emissions by another 15%, which corresponds to a 

NOx emission level of approximately 0.20 lb/MMBtu. SCR is estimated to reduce NOx emissions to 

approximately 0.080 lb/MMBtu. Table 3-1 summarizes the annual NOx emissions resulting from the 

application of LNB/SOFA, SCR, and SNCR to Units 1, 2, or 3. 

An alternative Control Option 1 is also evaluated assuming LNB/SOFA can achieve a NOx emission rate of 

0.20 lb/MMBtu. This emission rate represents an optimal outcome for LNB/SOFA technology at NGS which 

may not be realized. The uncertainty associated with this rate is largely based on the very limited practical 

experience with LNB/SOFA retrofits at plants burning western bituminous fuels comparable to that which is 

burned at NGS. In addition, the units at NGS are relatively small and do not provide adequate residence time 

for effective staging of combustion and achieving lower NOx rates. 
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Table 4-1: Annual NOx Emission Rates Resulting from Application of Control Options to NGS Units 1 

– 3 (lb/MMBtu) 

Control Option Control Technology Unit 1 Unit 2 Unit 3 

Baseline 

Emissions Good Combustion & CCOFA 0.49 0.45 0.46 

1 LNB/SOFA (Units 1-3) 0.24 0.24 0.24 

1 Alternative LNB/SOFA (Units 1-3) 0.20 0.20 0.20 

2 LNB/SOFA&SNCR (Units 1-3) 0.20 0.20 0.20 

3 LNB/SOFA (Unit 2); 

LNB/SOFA&SCR (Units1&3) 0.08 0.24 0.08 

4 LNB/SOFA&SCR (Units 1-3) 0.08 0.08 0.08 

To assess the effectiveness of the alternative NOx control technologies in reducing visibility impairment 

attributable to Units 1 through 3, we developed the stack and emission parameters for the following control 

options: 

• Option 1 and 1 Alternative. This option involves the retrofit of LNB/SOFA to Units 1 through 3 to 

control NOx emissions from all three units to 0.24 lb/MMBtu (0.20 lb/MMBtu for Option 1 Alternative). 

• Option 2. This option involves the retrofit of LNB/ SOFA, and SNCR to Units 1 through 3 to control 

NOx emissions from all three units to 0.20 lb/MMBtu. 

• Option 3. This option involves the retrofit of LNB/SOFA to Unit 2 to control NOx emissions from this 

unit to 0.24 lb/MMBtu, and the retrofit of LNB/SOFA and SCR to Units 1 and 3 to control NOx

emissions from these two units to 0.08 lb/MMBtu. 

• Option 4. This option involves the retrofit of LNB/SOFA, and SCR to Units 1 through 3 to control NOx

emissions from all three units to 0.08 lb/MMBtu. 

The alternative control technologies will not only affect PM, SO2, and NOx emission levels from Units 1 through 

3, but will also affect the emissions and speciation of PM10. The PM10 emissions and speciation were 

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% of the filterable PM emissions are 

filterable PM10 and 29% 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% 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-D98-046, 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 2007. For 

coal-fired boilers equipped with SCR, H2SO4 emissions are determined by the following relationship: 
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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 (0.00111 for western bituminous coal), 

S2 is the SCR catalyst SO2 oxidation rate (0.01 for PRB coal; which is the closest 

coal type to the fuel used at NGS) 

F2 is the control factor (0.63 for a hot-side ESP, 0.56 for an air pre-heater, and 

0.60 for wet FGD). 

Note that, for units not equipped with SCR, the factor, S2, is eliminated from the above relationship. 

• For coal-fired boilers with FGD, the total condensable organic PM10 emission factor is 0.004 lb/MMBtu 

based on AP-42, Table 1.1-5. 

The stack parameters for Units 1, 2, and 3 under all four control options are presented in Table 3-2. The NOx, 

SO2, and PM10 emissions from Units 1, 2, and 3 under the four control options are then summarized in Tables 

4-2, 4-3, 4-4, and 4-5 respectively. Option 1 Alternative simply reduces the NOx emission rates by 16.7% from 

those listed in Table 4-2. 

4.4 Impacts of Alternative NOx Controls 

The alternative control technologies available to control NOx emissions from Units 1 through 3 are LNB/SOFA, 

SCR, and SNCR. This section documents the economic, non-air environmental, and energy impacts 

associated with applying either LNB/SOFA, SCR or SNCR to Units 1 through 3. 

4.4.1 Economic Impacts 

Table 4-2 summarizes the total capital and annual costs associated with applying LNB/SOFA, SCR, and 

SNCR to Units 1 through 3. 

Table 4-2: Total Capital and Annual Costs Associated with LNB/SOFA, SCR and SNCR Applied to 

NGS Units 1 through 3 

Control 

Option Control Technology 

Total Capital 

Cost 

($) 

 Fixed Capital 

Costs 

($/yr)a

Annual O&M 

Costs 

($/yr) 

Total Annual 

Costs 

($/yr) 

1/alt. 1 LNB/SOFA (Units 1-3) 30,000,000 2,831,700 0 2,831,700 

2 LNB/SOFA&SNCR (Units 1-3) 60,000,000 5,663,000 9,478,000c 15,141,000 

3 LNB/SOFA (Unit 2); 

LNB/SOFA&SCR (Units1&3) 396,000,000b

 37,378,440 8,316,000 45,694,440 

4 LNB/SOFA&SCR (Units 1-3) 660,000,000b 62,297,000 12,474,000 74,771,000 

a

 Fixed capital costs based on a CRF of 0.09439, assuming an interest rate of 7% and amortization period of 20 years. b Total capital costs include costs associated with outages required for installation of control equipment. c

 Annual O&M costs include the lost revenues resulting from ammonia contamination of fly ash from SNCR. 

4.4.2 Non-Air Quality Environmental Impacts 

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% 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 
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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% 

anhydrous ammonia is subject to the general duty clause of the RMP Program. 

Because the nearest rail access is about 150 miles from the NGS, the anhydrous ammonia required for the 

SCR option would have to be delivered to the site via tanker trucks. To achieve the projected NOx reduction 

of 53 tons per day, approximately 21 tons of anhydrous ammonia would be required each day in the three 

units at the NGS. Assuming each tanker truck has a capacity of 6,000 gallons, this would require one to two 

truck deliveries of anhydrous ammonia each day to the NGS. This truck traffic would add to the 

atmospheric burden of air pollution in the region. 

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, and insufficient residence time. These physical limitations may be compensated for 

by injecting a larger amount of ammonia than stoichiometrically required and essentially achieving lower NOx

emissions at the expense of ammonia slip. Typically, the ammonia slip associated with SCR is approximately 

2 ppm at 6% O2, while that associated with SNCR is approximately 5 ppm at 6% O2. This excess 

ammonia may react with SO3 or H2SO4 in the flue to form ammonium bisulfate ((NH4)HSO4) and ammonium 

sulfate ((NH4)2SO4). These ammonium salts may condense as the flue gases cool and can lead to increased 

emissions of both PM10 and PM2.5. In SCR systems, the catalyst promotes the partial oxidation of SO2 to SO3, 

which in turn increases the formation of ammonium bisulfate and ammonium sulfate. The enhanced formation 

of these ammonia salts further increases the potential emissions of PM10 and PM2.5. 

Ammonia associated with fly ash has the potential to present several problems with the disposal and/or the 

use of the fly ash. Once the fly ash is exposed to the SNCR process, there will be a significant quantity of 

soluble salts associated with the fly ash. These salts are expected to be NH4HSO4 and (NH4)2SO4. Ash 

buyers have expressed concerns about the presence of ammonia on ash. The issues appear to be 

perception and odor, rather than actual impacts on product quality (e.g., when used for concrete). The level 

of concern may be regional in nature (i.e., less concern in a non-freezing climate) and the ultimate market 

for the ash (i.e., commercial versus residential use). The tendency of fly ash to adsorb ammonia is a 

function of many factors in addition to the amount of ammonia slip. Ash characteristics such as pH, alkali 

mineral content, and volatile sulfur and chlorine content help to determine whether or not ammonia will be 

adsorbed readily by the fly ash. Elevated pH will cause ammonia release to the air and resulting odor. In 

some applications, properly designed SNCR systems can keep the ammonia slip levels low enough so that 

the salability of the ash is unaffected. 

Dry disposal of fly ash can cause the leachate and/or runoff water to contain increased concentrations of 

ammonia. If and when these salts are contacted by water, they will most likely be dissolved and the 

resulting aqueous concentration of nitrogen-containing compounds can increase in the waters associated 

with the ash. 

Table 4-3 summarizes the non-air quality environmental impacts associated with the proposed BART control 

options. 
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Table 4-3: Summary of Non-Air Quality Environmental Impacts 

Control Alternative Summary of Non-Air Quality Environmental Impacts 

LNB/SOFA • Potential to the increase LOI of flyash which could reduce recycling sales 

• Slight increase in CO2 emissions/kwh associated with reduced boiler 

efficiency 

• Potential for poor combustion and increased CO emissions 

• Potential for increased corrosion and more frequent replacement of 

furnace waterwall tubes 

SNCR • Addition of ammonia or urea storage and handling systems present higher 

risk to NGS workers and the community. 

• Truck deliveries of ammonia/urea via long haul from nearest source 

• Anhydrous ammonia and aqueous ammonia above 20 percent are 

considered dangerous to human health, and accidental releases are 

reportable to local, state, and federal agencies. 

• The site must develop, implement, and maintain a Risk Management Plan 

(RMP) and Process Safety Measures (PSM) Program. 

• Excess ammonia injected into the boiler reacts with SO3 or H2SO4 in the 

flue to form ammonium bisulfate (NH4)HSO4 and ammonium sulfate 

(NH4)2SO4. 

• Sulfuric acid in the flue gas can cause various power plant operating and 

maintenance problems. Condensation of sulfuric acid has a significant 

detrimental effect on downstream pollution control equipment, including 

fouling and corrosion of heat transfer surfaces in the air pre-heater. 

• Ammonia associated with fly ash has the potential to present several 

problems with the disposal and/or the use of the fly ash. 

• Dry disposal of fly ash can cause leachate and/or runoff water to contain 

increased concentrations of ammonia and/or nitrogen-containing 

compounds. 

SCR • Addition of ammonia handling systems. Anhydrous ammonia and 

aqueous ammonia above 20 percent are considered dangerous to human 

health, and accidental releases are reportable to local, state, and federal 

agencies. 

• The site must develop, implement, and maintain a Risk Management Plan 

(RMP) and Process Safety Measures (PSM) Program 

• Truck deliveries of ammonia via long haul from nearest source 
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4.4.3 Energy Impacts 

SCR would consume significantly more electrical energy than SNCR. The higher electrical energy 

consumption for SCR 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 

evaporator blower. Assuming a pressure drop of 14 inches W.G. across the catalyst bed, SCR applied to all 

three units would consume approximately 22,500 kWh more electrical power than SNCR (approximately 1% of 

the total power generation of NGS). The increased emissions of criteria pollutants required to maintain the net 

electrical output have not been incorporated into the visibility modeling, but the reviewer should be aware that 

any reported visibility improvements due to SCR operation do not consider potential negative visibility impacts 

of the resulting increase in air emissions. 

4.4.4 Remaining Useful Life 

A 20-year amortization period for NGS was used for purposes of the BART analysis. 
4-11 

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Table 4-4: Navajo Generating Station SOFA/LNB Emission Controls (Option 1) 
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Table 4-5: Navajo Generating Station SOFA/LNB Emission Controls (Alternative Option 1) 
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Table 4-6: Navajo Generating Station SOFA/LNB/SNCR Emission Controls (Option 2) 
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Table 4-7: Navajo Generating Station SOFA/LNB/SCR (Option 3) 
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Table 4-8: Navajo Generating Station SOFA/LNB/SCR (Option 4) 
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5.0 BART Control Options Modeling Analysis 

This section provides a summary of the modeled visibility improvement as a result of installing BART control 

options on Navajo Units 1 - 3. 

5.1 Modeled Control Scenarios 

Four BART control scenarios were modeled for each meteorological year (2001-2003) and for all 11 Class I 

areas within 300 km. However, 3 of the 11 Class I areas are beyond others that are closer to NGS in the 

same direction. To summarize the impacts over the nearest Class I areas in several directions from the plant, 

we report average impacts over these closest 8 areas in some of the summary statistics. Emission rates that 

were used in modeling the four BART control options are listed in Tables 4-4 through 4-8. These control 

scenarios, which are more fully discussed in Section 4, are: 

Options 1 and 1 Alternative: Advanced combustion controls (LNB/SOFA) on Units 1-3. 

Option 2: Advanced combustion controls with SNCR on Units 1-3. 

Option 3: Advanced combustion controls with SCR on Units 1 and 3 and advanced combustion controls 

(LNB/SOFA) on Unit 2. 

Option 4: Advanced combustion controls with SCR on Units 1-3. 

5.2 CALPUFF Modeling Results for Control Options 

The results of the BART control options modeling are presented in Tables 5-1 and 5-2 and graphically plotted 

in Figure 5-1. Table 5-1 is an overall summary, averaged over the eight closest Class I areas and the three 

modeled years, of the predicted visibility changes due to installation of the candidate BART controls on the 

Navajo units. Table 5-2 shows detailed information on the visibility impacts of the BART control options for 

each modeled Class I area and meteorological year. Figure 5-1 compares the total visibility impairment 

(expressed in deciviews) for the modeled results with output from the three modeled years averaged for each 

case and Class I area. 

The tables and the figure indicate that some of the BART emission controls are predicted to result in visibility 

benefits, while others would result in visibility degradation (shown in red). Results for each candidate BART 

control option are discussed in more detail below. 

Option 1: The results show that the averaged regional haze impacts may improve visibility by about 0.28 

delta-dv (relative to the baseline case) with the installation of LNB/SOFA controls. These controls result in a 

NOx emission rate that is below the presumptive limit, thus complying with the requirements of the EPA BART 

rule for large electric generating plants. The results indicate that for the two most heavily impacted Class I 

areas, Grand Canyon and Capitol Reef National Parks, this option produces the best result for visibility 

improvement, and addition of post-combustion controls for NOx may actually degrade visibility in some cases, 

especially in the closest Class I areas. For the other Class I areas, the visibility improvements associated with 

additional control options are relatively minor. 

Option 1 Alternative: The results show that the averaged regional haze impacts may improve visibility by 

about 0.36 delta-dv (relative to the baseline case) with the installation of LNB/SOFA controls and optimization 

over time. This level of improvement is somewhat higher than that from Option 1. These controls also result 

in a NOx emission rate that is well below the presumptive limit, thus complying with the requirements of the 

EPA BART rule for large electric generating plants. The results indicate that for the two most heavily impacted 

Class I areas, Grand Canyon and Capitol Reef National Parks, this option also results in the best result for 
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visibility improvement, and addition of post-combustion controls for NOx may actually degrade visibility, as 

noted for Option 1. For the other Class I areas, the visibility improvements associated with additional control 

options are relatively minor. 

Option 2: Addition of SNCR on all three units will negatively impact visibility at Capitol Reef, Grand Canyon, 

and Bryce Canyon National Parks. Moreover, on average, across the eight parks the visibility impacts will not 

change from the baseline conditions. Therefore, BART control Option 2 is not effective in improving visibility 

and is not recommended. 

Option 3: Installation of SCR on Units 1 and 3 in addition to the Option 1 NOx controls may improve visibility 

by 0.40 delta-dv from the baseline, and only 0.12 delta-dv from Option 1 (0.04 delta-dv from Option 1a). It is 

noteworthy that the installation of SCR would create new emissions of primary sulfates (H2SO4) and excess 

ammonia, and would lead to increased gross generation to run the SCR equipment. Therefore, NOx emission 

controls involving SCR are relatively ineffective in this case, especially taking into account the high cost of the 

controls. 

Option 4: Addition of SCR on all three units in addition to the Option 1 controls may improve visibility by 0.53 

delta-dv from the baseline case and by 0.25 delta-dv from control Option 1. The relatively small incremental 

improvement in visibility is due in part to the small role that nitrates play in the total regional haze contribution. 

Moreover, for the same reasons described for Option 3 (addition of primary sulfates, excess ammonia, 

increased generation, and high cost), the installation of SCR is relatively ineffective. 

5.3 Cost of BART Control Options 

Table 5-3 summarizes the annualized control cost that is the product of the $/ton removed and the number of 

tons of NOx removed by each control strategy, as well as an incremental computation of each control option’s 

visibility improvement/degradation effectiveness and cost. The visibility results in Table 5-3 are based on the 

average of the three years and the eight closest modeled Class I areas. Figure 5-2 shows a graph of visibility 

improvements/degradation as a function of the cost for each control option. BART options associated with 

incremental improvements in visibility relative to a previous beneficial control option are connected with a blue 

line. Table 5-3 and Figure 5-2 indicate that the visibility would, on average, not improve in the eight Class I 

areas if the Option 2 controls (using SNCR) were adopted. 

A similar table and figure were prepared for Class I areas with the highest and lowest modeled visibility 

impacts. Figure 5-1 indicates that the Petrified Forest National Park is among the least impacted Class I 

areas. Figure 5-3 and Table D-1 (in Appendix D) show the annual cost compared to the visibility 

improvements/degradation at Petrified Forest National Park. 

Capitol Reef and Grand Canyon National Parks experience the highest impacts, with the impacts at 

Canyonlands slightly lower. After control Option 1 (or 1-alternative), the visibility at both Capitol Reef and 

Grand Canyon either degrades or shows a minimal benefit with all other control options. The results at 

Canyonlands National Park are plotted in Figure 5-4 and tabulated in Table D-2. Even though the overall 

impacts at Petrified Forest and Canyonlands are different in magnitude, the visibility improvement results 

respond similarly to the proposed BART control options. Specifically, the visibility is expected to improve with 

Option 1 controls and degrade with Option 2 controls. Options 3 and 4 controls are predicted to improve 

visibility only slightly and at a very high cost. Moreover, those two options also would result in NOx emission 

rates far below the EPA-established presumptive NOx emission rate limit for the NGS units of 0.28 lb/MMBtu. 

Unlike Options 1 and 1-alternative -- which, as discussed above, would also meet the presumptive NOx limit -- 

Options 2, 3, and 4 would all require use of post-combustion controls that EPA specifically determined would 

not be used as the basis for presumptive NOx limits for coal-fired utility boilers (other than cyclone units). See 

70 Fed. Reg. at 39134, 39171-72 (July 6, 2005). 
5-3 

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Table 5-1: Regional Haze Benefit of BART Controls 
5-4 

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Figure 5-1: 8th Highest Regional Haze Total Impacts Averaged Over 3 Years for Baseline and BART Control Case Emissio

0.01.02.03.04.05.06.07.08.09.0

Bryce Canyon Canyonlands Capitol Reef Grand Canyon Mesa Verde Petrified Forest Sycamore

Canyon

Z

Class I Area

8th Highest delta-deciview

BaselineOption 1: SOFA/LNB on Units 1-3 (0.24 lb NOx/MMBtu)Option 1-alt: SOFA/LNB on Units 1-3 (0.20 lb NOx/MMBtuOption 2: SOFA/LNB/SNCR on Units 1-3Option 3: SOFA/LNB/SCR on Units 1&3 and SOFA/LNB oOption 4: SOFA/LNB/SCR on Units 1-3
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Table 5-2: Regional Haze Results of BART Controls for Each Year and Class I Areas 
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Table 5-3: Annual Costs vs. Visibility Improvements/Degradation (Average of the Eight Class I Areas) 

Options BART Controls 

8th Highest 

Ave over 3 

Years and 8 

Class I 

Areas 

(total deltadeciview) 

Annualized 

Cost 

($/Year) 

Incremental 

Cost from 

Previous 

Control 

Scenario 

($/Year) 

Incremental 

Cost 

Effectiveness 

Relative to the 

Previous 

Control 

Scenario 

($/deciview)) 

Baseline None 6.27 $0 $0 $0 

Option 1 

LNB/SOFA on Units 

1-3 5.99 $2,831,700 $2,831,700 $10,031,114 

Alternative 

Option 1 

Optimal LNB/SOFA 

on Units 1-3 5.91 $2,831,700 $0 $0 

Option 2 

LNB/SOFA/SNCR 

on Units 1-3 6.27 $15,141,400 $12,309,700 

Not effective; 

visibility does 

not improve 

from baseline 

Option 3 

LNB/SOFA/SCR on 

Units 1&3 and 

SOFA/LNB on Unit 

2 

5.88 $45,694,440 $30,553,040 $77,349,468 

Option 4 

LNB/SOFA/SCR on 

Units 1-3 5.74 $74,771,400 $29,076,960 $212,369,763 
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Figure 5-2: Annual Costs vs. Visibility Improvements/Degradation (Average of Eight Class I Areas) 

Baseline

Option 1

Option 2

Option 3

Option 4

Option 1-alt

$0

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

$80,000,000

6.30 6.20 6.10 6.00 5.90 5.80 5.70

8th Highest delta-dv (Average of 3-Years and 8 Class I Areas)

Cost ($/year)
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Figure 5-3: Annual Costs vs. Visibility Improvements/Degradations at Petrified Forest NP 

Option 1-alt Baseline

Option 1

Option 2

Option 3

Option 4

$0

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

$80,000,000

5.90 5.80 5.70 5.60 5.50 5.40 5.30 5.20

8th Highest delta-dv (3-Year Average)

Cost ($/year)
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Figure 5-4: Annual Costs vs. Visibility Improvements/Degradations at Canyonlands NP 

Baseline

Option 1

Option 2

Option 3

Option 4

Option 1-alt

$0

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

$80,000,000

7.00 6.80 6.60 6.40 6.20 6.00 5.80

8th Highest delta-dv (3-Year Average)

Cost ($/year)
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6.0 BART Recommendations 

ENSR and SRP recommend LNB/SOFA for all three units as the Best Available Retrofit Technology 

alternative for the Navajo Generating Station based on the expected incremental visibility improvement, the 

cost of compliance, energy impacts, and non-air quality environmental impacts. 

SNCR and SCR were rejected due to the small (if any) incremental improvement in visibility over that resulting 

from use of LNB/SOFA; increased emissions of ammonia, ammonia salts, and sulfuric acid aerosols, which 

negatively impact local plume visibility; the high capital and O&M compliance costs for these technologies; 

increased generation requirements; and other considerations associated with the shipping, storage, and 

injection of anhydrous or aqueous ammonia. A summary of the BART controls is presented in Table 6-1. 

Table 6-1: Recommended Best Available Retrofit Technology – Low NOx Burners / Separated Overfire 

Air 

Estimated NOx Emission Rate 0.24 lbs/MMBtu, with possible reduction to 0.20 

lb/MMBtu with experience and optimization of 

operations 

NOx Emission Limit Reduction from Baseline 48% at 0.24 lb/MMBtu 

Estimated NOx Reduction (TPY) at 85% utilization 22,675 tons per year at 0.24 lb/MMBtu 

Costs of Compliance • $125/ton of NOx removed 

• $30 million capital cost 

• $2.8 million/year annualized cost 

Energy Impacts Slight increase in fuel consumption associated with 

reduced boiler efficiency 

Non-Air Quality Environmental Impacts • Increased LOI of fly ash, which could reduce 

recycling sales 

• Slight increase in CO2 emissions/kwh 

associated with reduced unit efficiency 

• Potential for poor combustion and increased 

CO emissions 

• Potential for increased corrosion and more 

frequent replacement of furnace waterwall 

tubes 

Modeled Visibility Impacts • 0.38 deciview improvement at Canyonlands 

(largest Class I area improvement)

• 0.28 deciview improvement (8-park average)

ENSR conducted CALPUFF modeling of the baseline emissions and four NOx control emission scenarios, 

all involving NOx emission reductions and any associated increased emissions of H2SO4 and ammonia. The 

BART control options that were analyzed include the retrofit of advanced post-combustion NOx controls, i.e., 

SNCR and SCR, even though EPA determined that these kinds of controls are more stringent than those 

that may be needed to meet the BART presumptive limits for boilers of the type at NGS. Each control 
6-2 November 2007

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option was modeled to assess visibility changes at eleven Class I areas within 300 km of NGS, while the 

primary visibility improvement/degradation results are reported for the closest eight Class I areas.

The 98th percentile prediction results indicate that the installation of the post-combustion NOx controls in 

addition to LNB/OFA would have a detrimental, or at best an insignificant, effect on visibility at the two closest 

and most heavily impacted Class I areas: Grand Canyon and Capitol Reef National Parks. Indeed, at the 

closest Class I area -- Grand Canyon National Park -- the selected option produces decidedly better visibility 

than would Options 2, 3, or 4; Option 2 would worsen visibility at that park, and Options 3 and 4 would produce 

virtually no change from baseline conditions. At other Class I areas, the improvement in visibility (i.e., from 

Option 1a to Option 3 or Option 4) as depicted by the 98th percentile result is always less than the 0.5-deciview 

contribution (half the perceptible limit) that EPA describes in the BART rule. It is also evident from the cost 

information reported in Section 5 that the $/deciview cost for post-combustion controls is extremely high (many 

tens of millions of dollars per deciview) for those areas for which any improvement in visibility is projected. 

Therefore, post-combustion NOx emission controls are relatively ineffective in this case, especially taking into 

account the extraordinarily high cost of those controls. Consequently, none of the post-combustion-control 

options can be recommended as BART for the NGS units. Finally, as noted above, the use of combustion 

controls for Navajo Units 1 - 3 is estimated to produce a NOx emission rate (0.24 lb/MMBtu), which exceeds 

the requirements of the BART presumptive limit. 
7-1 November 2007

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7.0 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, USEPA Contract No. 68-D-98-046, available at http://www.cleanairnet.org/asia/1412/articles37073_resource_1.pdf. 

E.H. Pechan and Associates, Inc. 1991. Best Available Retrofit (BART) Analysis for the Navajo Generating 

Station in Page, Arizona, United States Environmental Protection Agency. EPA Contract #68-02-4400, January 

31, 1991. 

Electric Power Research Institute. 2007. Estimating Total Sulfuric Acid Emissions from Stationary Power Plants.

Technical Update, March, 2007. 

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 

EPA. 2003a. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program, EPA-454/B03-005. September 2003. 

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

Table A-3, September 2003. 

EPA. 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. 

EPA. 1995. AP 42, Fifth Edition, Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and 

Area Sources, January 1995 

National Research Council, 1990. Haze in the Canyon: An Evaluation of the Winter Haze Intensive Tracer 

Experiment, Committee on Haze in National Parks and Wilderness Areas, National Research Council, National 

Academy Press, Washington, D.C., October 1990. 

Paise, J.W. 2006a. Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations. Memorandum to Kay Prince, Branch Chief EPA Region 4. Attachment A to April 20, 2006 DC 

Circuit Court document UARG vs. EPA, No. 06-1056. 

Paise, J.W. 2006b. Letter to Mel S. Schulze, Esq., Hunton and Williams representing the Utility Air Regulatory 

Group (UARG). Attachment B to April 20, 2006 DC Circuit Court document UARG vs. EPA, No. 06-1056. 

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). 

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. 
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Appendix A 

CALMET/CALPUFF Processing Refinements 
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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 A-1 through A-3 and listed in Table A-1, and 

are further discussed below. Figure A-1 shows the CALMET/CALPUFF modeling domain established by the 

WRAP for Arizona. 

Figure A-1: WRAP CALMET Modeling Domain for Arizona 

Enhancements to the WRAP CALMET Database 

ENSR made two refinements to the 4-km Arizona CALMET WRAP database. They are as follows: 

1. Weighting Factors for Modifying the Step 1 Wind Field. 

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 A-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 
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National Park Service (personal correspondence between John Notar of the NPS and Bob Paine of ENSR). 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. 

Figure A-2: CALMET Windfields with WRAP Settings 

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 A-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. 
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Figure A-3: CALMET Windfields with ENSR Settings 

2. Official EPA CALPUFF Version. 

When rerunning CALMET, ENSR used the latest EPA-approved version of the CALPUFF modeling system 

CALMET (Version 5.8, Level 070623) instead of Version 6.211 that was used by WRAP, available at 

http://www.src.com/calpuff/download/download.htm#EPA_VERSION. CALPUFF version 6 is basically equivalent 

to the VISTAS version of CALPUFF, Version 5.756. At the time of the WRAP BART protocol development 

process, the VISTAS version and Version 6 were generally acknowledged to be the latest and best versions 

available. However, EPA’s deliberate attempt to review the nature of the changes between the previous official 

version (5.711a) and the VISTAS version (and Version 6) uncovered a number of issues that were of concern to 

EPA. These issues were discussed in a presentation by Mr. Dennis Atkinson of EPA’s Office of Air Quality 

Planning and Standards at the 2007 annual modelers workshop (see 

http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/agenda.htm; “CALPUFF_status_update.pdf”). 

The basic issues of concern with the VISTAS version (and equivalent Version 6) are as follows: 

• There were unexplained and unresolved large differences between Versions 5.711a and 5.756. 

• Incomplete model documentation has been a problem with the last model users guides now 7 years old. 
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• The VISTAS code changes went beyond just fixing coding errors in Version 5.711a, contrary to what 

TRC, the model developer, asserted. 

• EPA’s annotated in-code documentation identified several categories of changes, including: 

− Bug fixes 

− Non-optional technical enhancements 

− Optional technical enhancements 

− Non-technical enhancements 

− Enhancement adjustments 

− Coordinate conversion fixes 

• EPA had serious technical concerns regarding how the optional technical enhancements, e.g., for mixing 

height, were implemented in CALMET 

The new approved Version 5.8 disables some of the VISTAS “optional technical enhancements”. Therefore, use 

of Version 5.756 or Version 6 of CALPUFF would appear to be inconsistent with the current EPA approved 

version. Default values of technical options specified in the newly approved version are adopted by ENSR. 

Table A-1: CALMET Options Comparison 

Variable Description WRAP Value ENSR Value 

RMAX1 Maximum radius of influence over land in 

the surface layer 

50 30 

R1 Relative weighting of the first-guess field 

and observations in the surface layer 

100 18 

R2 Relative weighting of the first-guess field 

and observations in the layers aloft 200 20 

3. Background Ammonia Values

The POSTUTIL utility program was used to repartition HNO3 and NO3 using appropriate ammonia background 

values that were approved by the Federal Land managers for the nearby Desert Rock Energy Facility (DREF) 

PSD permit application. For that project, located nearby in northwestern New Mexico, it was realized that the 

likely over-prediction by CALPUFF of nitrates in winter can be partially addressed by using a monthly variation of 

background ammonia concentrations. The default value of 1.0 ppb for arid lands as referenced in the IWAQM 

Phase 2 document is valid at 20 deg C, but the same document cites a strong dependence with ambient 

temperature, with variations of a factor of 3-4. This same dependence is seen at the CASTNET monitor at 

Bondville, Illinois (see page 5 at http://www.ladco.org/tech/monitoring/docs_gifs/NH3proposal-revised3.pdf). In 

addition, a study of light-affecting particles in SW Wyoming indicated that nitrates were over-predicted by a factor 

of 3 for a constant ammonia concentration of 1.0 ppb, and by a factor of 2 for an ammonia concentration of 0.5 

ppb (see slide 57 at 

http://www.air.dnr.state.ga.us/airpermit/psd/dockets/longleaf/facilitydocs/050711_CALPUFF_eval.pdf). Since 

there are no large sources of ammonia due to agricultural activities near the Class I areas being analyzed (see 

Figure 1 in http://www.ladco.org/tech/monitoring/docs_gifs/ammonia_role_midwest_haze.pdf), it is appropriate to 

introduce a monthly varying ammonia background concentration to the CALPUFF modeling. Table A-2 lists the 

values that were used in CALPUFF and have been agreed to by the National Park Service for DREF and other 

PSD submittals. Note that these values were used only for modeling the baseline and BART Option 1 (and 
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alternate Option 1) emissions. A refined set of ammonia background values was developed for modeling BART 

Option 2, 3, and 4 and further discussed in Appendix B. These proposed values are consistent with the CMAQ 

modeled values provided in Appendix A of www.vistassesarm.org/BART/CMAQ2002_evaluation_Dec31_2005.pdf. 

Table A-2: Ambient Ammonia Background Concentration 

Month Ambient Ammonia 

Background Concentration (ppb) 

January – February 0.2 

March – April 0.5 

May – September 1.0 

October – November 0.5 

December 0.2 
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Appendix B 

Factors Influencing NOx Emissions Effects on Visibility 

-
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Secondary pollutants such as nitrates and sulfates are significant contributors to the visibility extinction in Class I 

areas. The CALPUFF model was used to determine the effect of these pollutants on Class I areas, associated 

with BART control options. CALPUFF uses the EPA-approved MESOPUFF II chemical reaction mechanism to 

convert SO2 and NOx emissions to secondary sulfates and nitrates. The discussion below describes how the 

secondary pollutants are formed and the factors affecting their formation. 

Formation of Sulfates 

The rate of transformation of gaseous SO2 to ammonium sulfate (NH4)2SO4 aerosol is dependent upon solar 

radiation, ambient ozone concentration, atmospheric stability, and relative humidity, as shown in Figure B-1 (taken 

from the CALPUFF users guide, 2000). Homogeneous gas phase reaction is the dominant SO2 oxidation 

pathway during clear, dry conditions (Calvert et al., 1978). CALPUFF assumes that the sulfate reacts 

preferentially with ammonia (NH3) to form ammonium sulfate and that any remaining ammonia is available to form 

ammonium nitrate (NH4NO3). 

Figure B-1: MESOPUFF II SO2 Oxidation 

Formation of Nitrates 

The oxidation of NOx to nitric acid (HNO3) depends on the NOx concentration, ambient ozone concentration, and 

atmospheric stability. Some of the nitric acid is then combined with available ammonia in the atmosphere to form 

ammonium nitrate aerosol in an equilibrium state that is a function of temperature, relative humidity, and ambient 

ammonia concentration, as shown in Figure B-2 (from the CALPUFF users guide). 

Figure B-2 MESOPUFF II NOx Oxidation 

In CALPUFF, total nitrate (TNO3 =HNO3 + NO3) is partitioned into each species according to the equilibrium 

relationship between gaseous HNO3 and NO3 aerosol. This equilibrium is a function of ambient temperature and 

relative humidity. Moreover, the formation of nitrate strongly depends on availability of NH3 to form ammonium 
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nitrate, as shown in Figure B-3 (from CALPUFF courses given by TRC). The figure on the left shows that with 1 

ppb of available ammonia and fixed temperature and humidity (for example, 275 deg K and 80% humidity), only 

50% of the total nitrate forms particulate matter. When the available ammonia is increased to 2 ppb, as shown in 

the figure on the right, as much as 80% of the total nitrate is in the particulate form. Figure B-3 also shows that 

colder temperatures and higher relative humidity significantly favor nitrate formation and vice versa. A summary of 

the conditions affecting nitrate formation are listed below: 

• Colder temperature and higher relative humidity create favorable conditions to form nitrate particulate 

matter, and therefore more ammonium nitrate is formed; 

• Warm temperatures and lower relative humidity create less favorable conditions to form nitrate particulate 

matter, and therefore less ammonium nitrate is formed; 

• Sulfate preferentially scavenges ammonia over nitrates. In areas where sulfate concentrations are high 

and ambient ammonia concentrations are low, there is less ammonia available to react with nitrate, and 

therefore less ammonium nitrate is formed. 

For this BART analysis, the effects of temperature and background ammonia concentrations on the nitrate 

formation are the key to understanding the effects of various NOx control options. For parts of the country where 

sulfate concentrations are relatively high and ammonia emissions are quite low, the atmosphere is likely to be in 

an ammonia-limited regime relative to nitrate formation. Therefore, NOx emission controls are not very effective in 

improving regional haze, especially if there is very little ambient ammonia available. 

Figure B-3: NO3/HNO3 Equilibrium Dependency on Temperature and Humidity 

Refined Ambient Ammonia Background Concentrations 

As discussed above, the formation of nitrate is highly sensitive to availability of ammonia to form ammonium 

nitrate. Ammonium nitrate is a visibility-degrading pollutant. For the purpose of evaluating NOx emissions control 

options, the ambient ammonia background concentrations were refined to factor in excess ammonia emission 

increases associated with SNCR and SCR operations. Moreover, the installation of SCR creates primary sulfate 

emissions (H2SO4) that are also visibility-degrading. 

Excess ammonia emissions associated with SNCR and SCR operations were modeled in CALPUFF to determine 

the maximum 24-hour ammonia concentration at Grand Canyon National Park as well as the other Class I areas. 

Predicted excess ammonia concentrations associated with SNCR and SCR operation are listed in Table B-1. For 

simplicity in the post-processing, the predicted values of additional ambient ammonia concentrations were 

allocated to several values representing typical values covering the range of the CALPUFF predictions. 
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The resultant ammonia concentrations for the peak daily impact at the Class I areas (corresponding to a peak 

regional haze event) produced in μg/m3

 were converted to ppb and then added to the monthly ambient 

background values, as shown in Table B-1. Then POSTUTIL program (CALPUFF post-processor) was used to 

re-compute regional haze impacts with the adjusted ammonia background at each Class I areas. 

Table B-1: Refined Ambient Ammonia Background Concentration 
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Appendix C 

Review of Data from the IMPROVE Monitoring Network 
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The Visibility Information Exchange Web System (VIEWS) is an online database of air quality data designed to 

understand the effects of air pollution on visibility and to support the Regional Haze Rule enacted by the USEPA 

to reduce regional haze and improve visibility in national parks and wilderness areas 

(http://vista.cira.colostate.edu/views/). 

The VIEWS database contains annual summary of Class I area-specific charts of visibility-degrading pollutants. 

Bar charts depict seasonal pattern of pollution and pie charts show the average composition for the 20% best and 

20% worst pollution days. An example of a bar and pie chart for Canyonlands National Park (which also 

represents Arches National Park) is shown in Figure C-1. Bar and pie charts for the modeled eleven Class I areas 

for year 2002 are presented in this appendix. Year 2002 was chosen because it is the year for which WRAP has 

established the baseline emissions inventory. 

Figure C-1: Plot of Measured Visibility-Degrading Pollutants in Arches and Canyonlands NP, Year 2002 

Figure C-1 is typical of the composition of visibility-affecting particulate that is shown in the plots for other Class I 

areas provided below. The figure shows that for 2002, organic aerosols (probably associated with forest fires for 
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peak impacts) contributed about 40% and coarse particulate matter (due to wind-blown dust) contributed about 

22% on the worst 20% days to the visibility extinction at Canyonlands National Park. On the other hand, 

ammonium nitrate contributed only 8% and ammonium sulfate contributed 14% to the visibility extinction at the 

park. 

It is important to note that the nitrate impacts were virtually nonexistent during the warm period of April-October 

(during the period of the heaviest park visitation), while sulfate impacts were generally present throughout the 

entire year. In fact, very few of the worst 20% days (marked with a “W”) have substantial nitrate contributions. 

Therefore, reduction of NOx emissions would do very little to improve the visibility for this set of days that is 

specifically targeted by the Regional Haze Rule. On the other hand, several of the 20% worst days have some 

sulfate component, which would be increased by certain NOx controls, such as SCR, due to the collateral 

increases in sulfate and ammonia emissions associated with these controls. This overall pattern is generally 

present in all of the nearby Class I areas, as can be seen in the composition plots shown below. 

Figure C-2: Plot of Measured Visibility-Degrading Pollutants in Bryce Canyon NP, Year 2002 
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Figure C-3: Plot of Measured Visibility-Degrading Pollutants in Capitol Reef NP, Year 2002 

Pie chart for Capitol Reef NP was not available. 
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Figure C-4: Plot of Measured Visibility-Degrading Pollutants in Grand Canyon NP, Year 2002 
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Figure C-5: Plot of Measured Visibility-Degrading Pollutants in Mazatzal W and Pine Mountain W, Year 2002 
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Figure C-6 Plot of Measured Visibility-Degrading Pollutants in Mesa Verde NP, Year 2002 
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Figure C-7: Plot of Measured Visibility-Degrading Pollutants in Petrified Forest NP, Year 2002 
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Figure C-8: Plot of Measured Visibility-Degrading Pollutants in Sycamore Canyon W, Year 2002 
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Figure C-9: Plot of Measured Visibility-Degrading Pollutants in Zion NP, Year 2002 
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Appendix D 

CALPUFF Modeling Results 
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Table D-1: Annual Costs vs. Visibility Improvements/Degradation at Petrified Forest NP 

Options BART Controls 

8th Highest 

Ave over 3-

Years (deltadeciview) 

Annualized Cost 

($/Year) 

Incremental 

Cost from 

Previous 

Control 

Scenario 

($/Year) 

Incremental 

Cost 

Effectiveness 

Relative to the 

Previous 

Control 

Scenario 

($/deciview)) 

Baseline None 5.78 $0 $0 $0 

Option 1 SOFA/LNB on Units 1-3 5.51 $2,831,700 $2,831,700 $10,592,394 

Option 1-

alt 

SOFA/LNB on Units 1-3 5.43 $2,831,700 $0 $0 

Option 2 

SOFA/LNB/SNCR on 

Units 1-3 5.51 $15,141,400 $12,309,700 Not effective, 

visibility degrades

Option 3 

SOFA/LNB/SCR on 

Units 1&3 and 

SOFA/LNB on Unit 2 

5.41 $45,694,440 $30,553,040 $293,779,231 

Option 4 

SOFA/LNB/SCR on 

Units 1-3 5.24 $74,771,400 $29,076,960 $171,040,941 
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Table D-2: Annual Costs vs. Visibility Improvements/Degradation at Canyonlands NP 

Options BART Controls 

8th Highest 

Ave over 3-

Years (deltadeciview) 

Annualized Cost 

($/Year) 

Incremental 

Cost from 

Previous 

Control 

Scenario 

($/Year) 

Incremental 

Cost 

Effectiveness 

Relative to the 

Previous 

Control 

Scenario 

($/deciview)) 

Baseline None 6.78 $0 $0 $0 

Option 1 SOFA/LNB on Units 1-3 6.40 $2,831,700 $2,831,700 $7,531,117 

Option 1-

alt 

SOFA/LNB on Units 1-3 6.27 $2,831,700 $0 $0 

Option 2 

SOFA/LNB/SNCR on 

Units 1-3 6.45 $15,141,400 $12,309,700 Not effective, 

visibility degrades 

Option 3 

SOFA/LNB/SCR on 

Units 1&3 and 

SOFA/LNB on Unit 2 

6.12 $45,694,440 $30,553,040 $93,244,273 

Option 4 

SOFA/LNB/SCR on 

Units 1-3 5.86 $74,771,400 $29,076,960 $110,699,086 
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Appendix E 

BART Cost Information 
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Table E-1: BART Cost Information 
A Trusted Global Environmental, Health and Safety Partner 

U.S. Locations 

AK, Anchorage 

(907) 561-5700 

AL, Birmingham 

(205) 980-0054 

AL, Florence 

(256) 767-1210 

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CA, Camarillo 

(805) 388-3775 

CA, Orange 

(714) 973-9740 

CA, Sacramento 

(916) 362-7100 

CO, Ft. Collins 

(970) 493-8878 

CO, Ft. Collins Tox Lab. 

(970) 416-0916 

CT, Stamford 

(203) 323-6620 

CT, Willington 

(860) 429-5323 

FL, St. Petersburg 

(727) 577-5430 

FL, Tallahassee 

(850) 385-5006 

GA, Norcross 

(770) 381-1836 

IL, Chicago 

(630) 836-1700 

IL, Collinsville 

(618) 344-1545 

LA, Baton Rouge 

(225) 751-3012 

MA, Harvard Air Lab. 

(978) 772-2345 

MA, Sagamore Beach 

(508) 888-3900 

MA, Westford 

(978) 589-3000 

MA, Woods Hole 

(508) 457-7900 

MD, Columbia 

(410) 884-9280 

ME, Portland 

(207) 773-9501 

MI, Detroit 

(269) 385-4245 

MN, Minneapolis 

(952) 924-0117 

NC, Charlotte 

(704) 529-1755 

NC, Raleigh 

(919) 872-6600 

NH, Belmont 

(603) 524-8866 

NJ, Piscataway 

(732) 981-0200 

NY, Albany 

(518) 453-6444 

NY, Rochester 

(585) 381-2210 

NY, Syracuse 

(315) 432-0506 

NY, Syracuse Air Lab. 

(315) 432-0506 

OH, Cincinnati 

(513) 772-7800 

PA, Langhorne 

(215) 757-4900 

PA, Pittsburgh 

(412) 261-2910 

RI, Providence 

(401) 274-5685 

SC, Columbia 

(803) 216-0003 

TX, Dallas 

(972) 509-2250 

TX, Houston 

(713) 520-9900 

TX, San Antonio 

(210) 296-2125 

VA, Chesapeake 

(757) 312-0063 

VA, Glen Allen 

(804) 290-7920 

WA, Redmond 

(425) 881-7700 

WI, Milwaukee 

(262) 523-2040 

Headquarters 

MA, Westford 

(978) 589-3000 

Worldwide Locations 

Azerbaijan 

Belgium 

Bolivia 

Brazil 

China 

England 

France 

Germany 

Ireland 

Italy 

Japan 

Malaysia 

Netherlands 

Philippines 

Scotland 

Singapore 

Thailand 

Turkey 

Venezuela 

www.ensr.aecom.com