SALT RIVER PROJECT

PostOffice Box 52025

Phoenix, AZ 85072-2025

(602) 236-6699

E-mail: Richard.Hayslip@srpnet.com

December 12, 2008

RICHARD M. HAYSLIP

Associate General Manager

Deborah Jordan

Director, Air Division

United States Environmental Protection Agency

Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

Dear Ms. Jordan:

DEC 1 " Z008

U.S. EPA, REGION 9

Enclosed is the revised Best Available Retrofit Technology (BART) report for the Navajo

Generating Station (NGS) under the visibility provisions of the Clean Air Act, as you requested

in your letter of July 1, 2008. Based on an assessment of emission control costs and costeffectiveness, visibility impacts for relevant Class I areas, and the other BART factors, the report

demonstrates that the appropriate BART emission limitations for this facility are 0.20-0.24

Ib/mmBtu for oxides of nitrogen (NOx) and 0.05 lb/rnmlstu for particulate matter (PM). The

report does not address sulfur dioxide (S02) in detail because EPA has determined that the

plant's existing S02 emission controls satisfy applicable BART requirements.

As a significant part of its BART assessment for this facility, SRP has conducted a detailed

modeling analysis of visibility impacts of NGS NOx emissions. The enclosed report describes

this analysis, which, together with an evaluation of the cost-related and other BART factors.

demonstrates that advanced combustion controls (low-NOx burners) in conjunction with

separated overfire air is BART. Use of this control technology is projected to satisfy the

applicable NOx presumptive limits promulgated by EPA in its BART Guidelines and is

consistent with keeping the visibility impact of the plant's NOx emissions at a low level. The

analysis also shows that use of post-combustion NOx control technologies -- in particular,

selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) -- would not

produce a humanly perceptible average incremental improvement in visibility and in any event

would clearly not be cost-effective whether costs are measured on a dollar-per-ton or a dollarper-deciview-improvement basis.

In establishing presumptive NOx emission limits in its BART Guidelines (codified as Appendix

Y to 40 C.F.R. Part 51), EPA rejected the imposition of presumptive limits that reflect postcombustion technologies for NOx at coal-fired boilers with units such as those at NGS. 70 Fed.

Reg. 39104,39171-72 (July 6, 2005). Moreover, use of these technologies would give rise to

substantial risks and create adverse energy and environmental impacts due to the need to

transport ammonia. Any interest by EPA or Federal Land Manager representatives in having the

plant be subject to a BART emission limit for NOx that is significantly below the applicable

/3666./20S Environmental. Human Resources. Land. Risk Management. Telecom
Page 2

December 12, 2008

Deborah Jordan, Director, Air Division

United States Environmental Protection Agency

presumptive limits based on post-combustion technologies would, in our view, be inconsistent

with EPA's own Guidelines. This is particularly so in light of the fact that, as described in the

enclosed report, compliance with such below-presumptive limits would be extraordinarily costly

and result in, at best, only modest improvement in visibility, and in some cases is projected to

decrease visibility in nearby Class I areas.

In addition, in its letter of July 1, 2008, EPA asked SRP to undertake additional modeling using

new modeling assumptions on key parameters, with the apparent objective of projecting greater

visibility improvement from use of SNCR or SCR. Thus, for example, EPA asked us to perform

additional modeling simulations assuming "ammonia removal efficiencies of 50% and 90% for

the three meteorological years" on the basis that "true ammonia emissions are uncertain."

Although we have undertaken -- and the enclosed report provides the results of -- additional

sensitivity modeling representing a range of hypothetical ammonia removal percentages, we note

that b_a~j[.lg BART visibilitymodeling on unsupported assumptions of a high degree of ammonia

removal in connection with use of SNCR or SCR appears to be inconsistent with EPA's own

BART Guidelines, which require use in BART visibility impact analyses of "the 24-hour average

actual emission rate from the highest emitting day of the meteorological period modeled." 70

r Fed. Reg. at 39170. Likewise, there is no justification for requiring BART visibility modeling l

analyses to rely on an unsupported assumption of reduction of sulfuric acid emissions associated

. with operation of SCR.

Similarly, although we have conducted new modeling analyses with alternative meteorological

inputs as requested by your July 1 letter, and the results of those new analyses are described in

the report, we emphasize that the original modeling and meteorological inputs are consistent with

those accepted for the WRAP modeling protocol and are, in our view, well justified. Again, it

appears that the substitution of new meteorological data inputs may have been requested for the

purpose of increasing the degree of projected visibility improvement from certain NOx control

options, but without adequate technical justification provided to support the change in modeling

inputs.

Beyond all the reasons described in the attached report for the determination that no basis exists

to impose BART emission limitations for NOx that would require post-combustion controls,

important practical considerations also support that determination. Given the already

exceedingly low level of contribution to Class I area visibility impairment that is associated with

NOx emissions at NGS when those emissions are controlled with low NOx burners and

separated overfire air, it is unlikely that even greater reductions in those emissions would be

deemed necessary to achieve reasonable progress goals for those Class I areas. In any event,

however, whether and to what extent any such further reductions might be warranted could be

addressed inthe"coritexfofthe next se(c;(comprehensive reasonable progress assessments under

EPA's Regional Haze Rule. Moreover, at the time these future assessments are undertaken, it is

likely that national policies concerning possible carbon dioxide emission limitations for electric

generating units will have been established. Such policies may affect decisions by SRP

136661208
Page 3

December 12, 2008

Deborah Jordan, Director, Air Division

United States Environmental Protection Agency

regarding dispatch of coal-fired power plants such as NGS - decisions that, in turn, could result

in even greater reductions in those plants' NOx emissions. Thus, it would make far more sense

as a practical matter to address at the time whether and to what extent any further NOx controls

may be needed to address Class I area visibility objectives.

Finally, EPA Region 9 has indicated its interest in pursuing BART emission limits for direct

particulate matter emissions from stacks andlor from materials handling or other fugitive sources

at NGS even though any resulting marginal reduction in particulate emissions would have

negligible or no impact on visibility -- and certainly no humanly perceptible impact -- in the

relevant Class I areas. Existing particulate controls at the facility are effective in reducing

emissions that may have an effect on visibility in those areas, and no additional particulate

controls can be shown to be cost-effective or otherwise justified under the BART Guidelines.

We appreciate the opportunity to provide our BART recommendations for NGS and believe that

these recommendations are fully supported and justified for the reasons stated in our original

report and in the enclosed revised report. If you would like to discuss our recommendations or

report, please contact me or Kevin Wanttaja, Manager, Environmental Services at 602-236-2968.

Sincerely,

Richard

\~~+ M. Hayslip

cc: Steve Frey, EPA Region IX (wi enclosure)

/3666./2IJ8
Prepared for: 

Salt River Project – Navajo Generating Station 

Tempe, AZ 

Revised BART Analysis for the Navajo 

Generating Station Units 1 - 3 

ENSR Corporation 

January 2009 

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

Salt River Project – Navajo Generating Station 

Tempe, AZ 

Revised BART Analysis for the Navajo 

Generating Station Units 1 - 3 

__________________________________________________________ 

Prepared By: Olga Kostrova and Robert Paine 

_____________________________ 

Reviewed By: Ian Thomson 

ENSR Corporation 

January 2009 

Document No.: 05830-012-300 
i January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

Contents 

Executive Summary ...........................................................................................................................................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.................................................................................................. 1-3

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 Change Calculations ............................................................................ 2-4

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

3.1 BART-Eligibility 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............................................................................................ 4-4

4.1.5 ECOTUBETM...................................................................................................................... 4-5

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

4.2 Technical Feasibility of Alternative NOx Controls ........................................................................... 4-6

4.3 Effectiveness of Technically Feasible NOx Controls ...................................................................... 4-6

4.4 Analysis of Alternative NOx Controls............................................................................................... 4-8

4.4.1 Economic Issues................................................................................................................ 4-8

4.4.2 Non-Air Quality Environmental Issues .............................................................................. 4-9
ii January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

4.4.3 Energy Impacts................................................................................................................ 4-11

4.4.4 Remaining Useful Life ..................................................................................................... 4-11

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 Effectiveness 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 and Ammonia Slip Sensitivity Analysis

Appendix C Review of Data from the IMPROVE Monitoring Network

Appendix D CALPUFF Modeling and Cost Effectiveness Results for Each Year from Potential Plant 

Contributions to Visibility Changes

Appendix E CALPUFF Modeling Results Using Background plus Potential Plant-Caused Visibility Impairment 

for Each Year

Appendix F EPA Region 9 Letter to Salt River Project (July 1, 2008)

Appendix G 98th Percentile Regional Haze Results During Entire Year and April – October Period

List of Tables 

Table ES-1 Total Capital and Annual Costs Associated with BART Control Options.............................ES-5

Table ES-2 Annual Costs vs. Visibility Improvements/Degradation (Average of the 11 Class I Areas) ....ES-5

Table ES-3 Best Available Retrofit Technology – Low NOx Burners / Separated Overfire Air ..............ES-7

Table ES-4 Summary of BART Analysis for NOx..................................................................................... Es-8

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 Effects Due to Baseline Emissions................................................................. 3-6

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

through 3 (lb/MMBtu)................................................................................................................ 4-7
iii January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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

Units 1 through 3 ...................................................................................................................... 4-8

Table 4-3 Summary of Non-Air Quality Environmental Effects ............................................................. 4-10

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

Table 4-5 Navajo Generating Station SOFA/LNB Emission Controls (Alternative Option 1)............... 4-13

Table 4-6 Navajo Generating Station SOFA/LNB/SNCR Emission Controls (Option 2)...................... 4-14

Table 4-6 Navajo Generating Station SOFA/LNB/SNCR Emission Controls (Option 2) cont.............. 4-15

Table 4-7 Navajo Generating Station SOFA/LNB/SCR (Option 3) ....................................................... 4-16

Table 4-8 Navajo Generating Station SOFA/LNB/SCR (Option 4) ....................................................... 4-18

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

Table 5-2 Regional Haze Results of BART Controls for Each Year and Class I Areas......................... 5-6

Table 5-2 Regional Haze Results of BART Controls for Each Year and Class I Areas, continued....... 5-7

Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average.................................................... 5-8

Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average, continued.................................. 5-9

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

................................................................................................................................................... 6-1

Table 6-2 Summary of BART Analysis for NOx........................................................................................ 6-3

List of Figures 

Figure ES-1 8th Highest Regional Haze Deciview Changes from NGS BART Control Options ..............ES-3

Figure ES-2 Annual Costs vs. Visibility Improvements/Degradations, 3-Year Average...........................ES-6

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 Changes for Each Modeled Year Due to Baseline Emissions.... 3-7

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

Case Emissions........................................................................................................................ 5-5

Figure 5-2 Annual Costs vs. Visibility Improvements/Degradation, 3-Year Average............................. 5-10
ES-1 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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, about 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 review 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 report was submitted to EPA Region 9 in November 2007. After its review, EPA requested a 

revised analysis in a letter dated July 1, 2008 (provided in Appendix F to this report). The EPA asked SRP 

to revise the meteorological data used in the CALPUFF modeling, to provide additional results for some 

Class I areas, to provide additional information on calculations and cost estimates, and to address sensitivity 

issues regarding NOx control modeling cases. This report provides the requested revised BART analysis. 

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

Reasonably Attributable BART Program, involving effects on visibility 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. With reference to 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, stating that “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. 

Based on annual performance tests, these controls have limited 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. 

Because of limited historical performance test data, SRP is recommending a short-term PM BART limit of 

0.05 lb/MMBtu. 

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 
ES-2 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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 BART Guidelines. Consistent with those 

guidelines, the five steps for a case-by-case BART analysis were followed. 

• Step 1 – Identify all available retrofit 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 effects 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 NOx control technologies that are 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 plotted in Figure ES-1. This 

figure compares the total visibility impairment (expressed in deciviews) for the modeled results with output 

from the 3 modeled years averaged for each case and the 11 Class I areas located within 300 km of NGS. 

The order of the Class I areas plotted is by increasing distance from NGS, from left to right. The visibility 

effects stated throughout this report are relative to natural conditions and represent potential changes since 

it is conservatively assumed that all BART units are continuously at peak operation. 

After installation of controls for BART Option 1 (and 1-alternative), visibility at the 11 Class I areas shows a 

measurable reduction. However, when considering the additional controls in Options 2 through 4, there is 

only a relatively modest benefit (if any) when looking at the full year of modeling results. In addition, we find 

that during the high visitation months of April – October, these benefits are either reduced substantially or 

are replaced with a degradation of visibility. 

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 this emission control technology at NGS. This combustion modification produced visibility 

improvements across the 11 parks averaging 0.37 deciviews. For comparison, a deciview change of 1.0 is 

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

demonstrated the greatest visibility improvement relative to baseline emissions with a change of 0.54 

deciviews. The hardware capital costs of this retrofit option were estimated at $42 million dollars with 

negligible operation and maintenance (O&M) costs relative to the other options. 
ES-3 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

Figure ES-1 8th Highest Regional Haze Deciview Changes from NGS BART Control Options 

0.0

0.5

1.0

1.5

2.0

2.5

3.0

Grand

Canyon

Capitol Reef Bryce

Canyon

Zion Canyonlands Sycamore

Canyon

Petrified

Forest

Arches Mesa Verde Mazatzal Pine

Mountain

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

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 rate represents a desired 

“optimal” outcome for LNB/SOFA technology at NGS, but it 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 relative to the baseline across the 11 

parks averaging 0.47 deciviews. Canyonlands National Park demonstrated the greatest visibility 

improvement relative to baseline with a change of 0.70 deciviews. The hardware capital costs of this retrofit 

option were also estimated at $42 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 excess ammonia. These additional fine particulate and 

precursor emissions negatively affected visibility at all areas relative to Option 1a, especially at Capitol Reef 

and Grand Canyon National Parks. The increased ammonia ambient concentrations were ignored in the 

modeling at all parks except Capitol Reef and Grand Canyon due to the lower values at the more distant 

parks. Therefore, for most parks, the reported modeled visibility changes are the same as Option 1a, but 

the visibility impairment for BART Option 2 would have slightly exceeded that for BART Option 1a if the 

increased ammonia concentrations at the parks had been taken into account. Therefore, this BART control 

option is not effective relative to Option 1a in improving visibility. Option 2 also bears a high cost as well, 

almost 7 times the annualized cost of BART Option 1a, as noted in Table ES-1. 
ES-4 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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 specific 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 11 parks relative to Option 1a, with an average of about 0.10 deciviews. 

Canyonlands National Park demonstrated the greatest visibility improvement relative to Option 1a with a 

change of 0.24 deciviews. However, modeled changes at Grand Canyon NP showed degradation in 

visibility relative to Option 1a (of 0.05 deciviews) due to its proximity to NGS and the increased H2SO4

emissions due to the deployment of SCR. This mixed visibility effect comes at a very high annualized cost 

of 12 times that of BART Option 1a, as noted in Table ES-1. 

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

associated with this option (above that required for SOFA/LNB) are estimated at $663 million dollars with 

annual O&M costs of about $13.2 million dollars each year, amounting to an annualized cost that is almost 

20 times that of BART Option 1a. This option produced an average visibility improvement of 0.22 deciviews 

relative to that for Option #1a. Canyonlands National Park demonstrated the greatest visibility improvement 

relative to Option 1a with a change of 0.42 deciviews. Similar to Option 3, modeled changes at the Grand 

Canyon showed degradation in visibility relative to Option 1a (of 0.09 deciviews) due to its proximity to NGS 

and the increased H2SO4 emissions due to the deployment of SCR. As is the case for 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. The modeled visibility improvements/degradations relative to the calculated cost in 

terms of dollars per deciview are shown in Figure ES-2. In all cases, the improvements for Option 1 are 

computed relative to baseline, for Option 1a relative to Option 1, and for Options 2, 3, and 4 relative to 

Option 1a. 

The slope of the connected points for each Class I area depicts the relative cost effectiveness of the BART 

options. A steep slope indicates a very high cost for relatively little visibility benefit, while a backward slope 

(toward higher deciviews) indicates that the BART control option could actually degrade visibility. The 

tabulated values in Table ES-2 and the graph in Figure ES-2 show that the relative cost for additional 

visibility improvement (if any) beyond the LNB/SOFA controls increases very substantially. Therefore, 

ENSR and SRP recommend LNB/SOFA for all three units as BART for NGS 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 relatively small or nonexistent 

incremental improvement in visibility over that resulting from use of LNB/SOFA; increased emissions of 

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

capital and O&M compliance costs for these technologies; increased generation needed (which was not 

considered in the modeling); and other considerations associated with the shipping, storage, and injection of 

anhydrous ammonia. A summary of the recommended BART controls is presented in Table ES-3 and a 

summary of the BART guideline steps is presented in Table ES-4. 
ES-5 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

Table ES-1 Total Capital and Annual Costs Associated with BART Control Options 

Control 

Option Control Technology 

Total Capital 

Cost 

($) 

Fixed Capital 

Costs 

($/yr)a

Annual O&M 

Costs 

($/yr)c

Total Annual 

Costs 

($/yr) 

1/alt. 1 LNB/SOFA (Units 1-3) $42,000,000 $4,866,000 $0 $4,866,000 

2 LNB/SOFA&SNCR (Units 1-3) $78,000,000 $9,037,000 $17,391,000 $26,428,000 

3 LNB/SOFA (Unit 2); 

LNB/SOFA&SCR (Units1&3) $438,000,000b $50,747,000 $8,778,000 $59,525,000 

4 LNB/SOFA&SCR (Units 1-3) $705,000,000 $81,681,000 $13,167,000 $94,848,000 

(a) Fixed capital costs based on a CRF of 0.1159, assuming an interest rate of 9.8% 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.

Table ES-2 Annual Costs vs. Visibility Improvements/Degradation (Average of the 11 Class I Areas) 

Options BART Controls 

8th Highest 

Ave over 3 

Years and 

11 Class I 

Areas 

(total deltadeciview) 

Annualized 

Cost 

($/Year) 

Incremental 

Cost Relative 

to Baseline or 

Option 1/1a 

($/Year) 

Incremental 

Cost 

Effectiveness 

Relative to 

Baseline or 

Option 1/1a 

($/deciview) 

Baseline None 1.75 $0 $0 $0 

Option 1 LNB/SOFA on 

Units 1-3 1.38 $4,866,000 $4,866,000 $13,160,000 

Alternative 

Option 1 

LNB/SOFA on 

Units 1-3 1.27 $4,866,000 $0 $47,780,000 

Option 2 LNB/SOFA/SNCR 

on Units 1-3 1.36 $26,428,000 $21,562,000 

not cost effective 

(degrades 

visibility) 

Option 3 

LNB/SOFA/SCR on 

Units 1&3 and 

SOFA/LNB on Unit 

2 

1.17 $59,525,000 $54,659,000 $528,030,000 

Option 4 LNB/SOFA/SCR on 

Units 1-3 1.05 $94,848,000 $89,982,000 $400,080,000 

* For Options 1 and 1a, the previous applicable control scenario is the baseline case. For Options 2, 3, and 

4, the previous applicable control scenario is Option 1a.
ES-6 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

Figure ES-2 Annual Costs vs. Visibility Improvements/Degradations, 3-Year Average 

$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

$90,000,000

$100,000,000

3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0

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

Cost ($/year)

Arches

Bryce Canyon

Canyonlands

Capitol Reef

Grand Canyon

Mazatzal

Mesa Verde

Petrified Forest

Pine Mountain

Sycamore Canyon

Zion

Baseline

Option 1 & 1-alt

Option 2

Option 3

Option 4
ES-7 January 2009 BART Analysis for Navajo Generating Station 

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Table ES-3 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 At least 48% at 0.24 lb/MMBtu 

Estimated NOx Reduction (TPY) at 85% 

utilization

22,675 tons per year at 0.24 lb/MMBtu (Option 1), 

and 26,755 tons per year at 0.20 lb/MMBtu (Option 

1a) 

Costs of Compliance • $42 million capital cost 

• $4.9 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 Changes 

• 0.54 – 0.70 deciview improvement at 

Arches and Canyonlands NP (largest Class 

I area improvements for Options 1 and 1a)

• 0.37 – 0.47 deciview improvement (3-year 

and 11-park average)
ES-8 

BART Analysis for Navajo Generating Station 05830-012-300

Table ES-4 Summary of BART Analysis for NOx

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

Identify Control 

Technologies 

Feasible 

Control 

Technology? 

Evaluate Control 

Effectiveness for 

Technically 

Feasible Control 

Technologies 

Calculate 

Cost 

Effectiveness 

for Control 

Technologies 

(relative to 

baseline) 

Determine 

Non-Air Quality 

Environmental and 

Energy Impacts 

Eval

Visib

Chang

Contro

base

Control 

Option 1 

Low NOx burners, 

separated overfire air Yes 48% NOx reduction from baseline Annualized cost = $4.9 MM Increase in fuel consumption, LOI of fly ash, corrosion, increase in CO average 

improve

0.37 d

Alternative 

to Control 

Option 1 

Low NOx burners, 

separated overfire air Yes 

57% NOx reduction 

from coal-fired 

baseline (9% 

reduction relative to 

Option 1) 

Annualized 

cost = $4.9 

MM 

Increase in fuel 

consumption, LOI of fly 

ash, corrosion, 

increase in CO 

average 

improve

0.47 delta

reductio

to Op

Control 

Option 2 

Low NOx burners, 

separated overfire air, 

and SNCR 

Yes 

57% NOx reduction 

from coal-fired 

baseline (no 

additional reduction 

from Option 1a) 

Annualized 

cost = $26.4 

MM 

Excess NH3 emissions; 

1% plant energy 

consumption; NH3 risk 

to workers and public, 

air emissions of NH3

transport 

average 

improve

0.39 d

(degrada

Optio

Control 

Option 3 

Low NOx burners, 

separated overfire air, 

and SCR (Units 1,3) 

Yes 

71% NOx reduction 

from coal-fired 

baseline (14% 

reduction relative to 

Option 1a) 

Annualized 

cost = $59.5 

MM 

Excess sulfate 

emissions; 1% plant 

energy consumption; 

NH3 risk to workers and 

public, air emissions of 

NH3 transport 

average 

improve

0.57 delta

reductio

to Opt

Control 

Option 4 

Low NOx burners, 

separated overfire air, 

and SCR (all units) 

Yes 

83% NOx reduction 

from coal-fired 

baseline (26% 

reduction relative to 

Option 1a) 

Annualized 

cost = $94.8 

MM 

Excess sulfate 

emissions; 1% plant 

energy consumption; 

NH3 risk to workers and 

public, air emissions of 

NH3 transport 

average 

improve

0.70 delta

reductio

to Opt
1-1 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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 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 a proposal published by EPA in February 1991. The 

recommendation proposed a 90 percent reduction in sulfur dioxide emissions through controls to be installed 

on each of the three units in stages, with a final completion date in 1999. 

Subsequently, in October 1991, 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 by November 19, 1997, two units by November 19, 1998, and the 

third unit by August 19, 1999. NGS fulfilled the rule’s 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 at designated 

Class I areas in order to help meet the targets for visibility improvement in those 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. 
1-2 January 2009 BART Analysis for Navajo Generating Station 

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2. The sum of the potential 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 RHR. 

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 changes with 

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

A BART report was submitted to EPA Region 9 in November 2007. After its review, EPA requested a revised 

analysis in a letter dated July 1, 2008 (provided in Appendix F to this report). EPA asked SRP to revise the 

meteorological data used in the CALPUFF modeling, to provide additional results for some Class I areas, to 

provide additional information on calculations and cost estimates, and to address sensitivity issues regarding 

NOx control modeling cases. This report provides the requested revised BART analysis. 

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 rule. 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 averages about 0.03 

lb/MMBtu, an emission rate which was used in the BART modeling, although peak short-term PM filterable 

emissions could potentially range up to 0.05 lb/MMBtu. However, CALPUFF modeling results indicate that 

filterable PM emissions are generally responsible for less than 10% of the visibility impairment at the modeled 

Class I areas. The expected average PM filterable emission 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 or visibility impairment, and an evaluation of PM controls is 

not included in this document. BART for PM is considered to be the current control configuration at a 

proposed short-term emission rate of 0.05 lb/MMBtu. 
1-3 January 2009 BART Analysis for Navajo Generating Station 

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1.6 Nitrogen Oxides Emission Control 

NOx emissions at NGS are controlled by good combustion practices and close coupled overfire air (CCOFA). 

Baseline peak daily NOx emissions for NGS range from about 0.45 to 0.50 lb/MMBtu, which is higher than 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 BART 

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

followed. 

• Step 1 – Identify all available retrofit control technologies for the unit, 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, 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 benefits analysis. A presentation of the baseline emission effects on the 

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

that the incremental visibility change due to 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. 
2-1 January 2009 BART Analysis for Navajo Generating Station 

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2.0 CALPUFF Modeling Procedures 

For the CALPUFF modeling, SRP followed the Western Regional Air Partnership (WRAP) common BART 

modeling protocol with the exception of the model version and a few refinements to CALMET settings. These 

differences are discussed in Section 2.2 and Appendix A. 

2.1 CALMET Processing 

The 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) and adjustments requested by EPA Region 9 (described in 

Appendix F). 

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. 
2-2 January 2009 BART Analysis for Navajo Generating Station 

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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 

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 and 

the ammonia slip sensitivity analysis is also presented in Appendix B. 

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

Eleven Class I areas were modeled for NGS. 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 

2003a, 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, 2003b) Appendix A, Table A-3. 
2-3 January 2009 BART Analysis for Navajo Generating Station 

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Figure 2-1 NGS CALPUFF Computational Grid in Relation to WRAP Arizona Domain 
2-4 January 2009 BART Analysis for Navajo Generating Station 

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2.4 Light Extinction and Haze Change Calculations 

The CALPOST postprocessor was used for the calculation of the effect of 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 estimating natural visibility 

conditions (EPA, 2003a). 

The assessment of visibility effects 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. 
3-1 January 2009 BART Analysis for Navajo Generating Station 

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3.0 BART Applicability Analysis 

3.1 BART-Eligibility 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 potential 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 RHR. 

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 potential emissions contribute to a threshold visibility change 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 

of 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. 
3-2 January 2009 BART Analysis for Navajo Generating Station 

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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 2008, and R. 

Hardman, et al. 1998. 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, 0.90 for an air pre-heater, and 

 0.47 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. For all 

emission tables, the SO4 emission rate is 96/98 times the H2SO4 emission rate (the molecular weight ratio). 

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 
3-4 January 2009 BART Analysis for Navajo Generating Station 

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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 
3-5 January 2009 BART Analysis for Navajo Generating Station 

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Figure 3-1 Class I Areas within 300 km of the Navajo Generating Station 
3-6 January 2009 BART Analysis for 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. Figure 3-2 shows the 8th highest 

deciview changes from natural conditions. Appendix E contains the same graph with the natural background 

visibility component included. The figure indicates that the higher potential visibility effects generally occur at 

Grand Canyon National Park, Capitol Reef National Park, and Canyonlands National Park. Higher potential 

visibility effects at these Class I areas 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 changes 

relative to natural background 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 Effects Due to Baseline Emissions 
3-7 January 2009 BART Analysis for Navajo Generating Station 

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

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

Grand Canyon NP

Capitol Reef NP

Bryce Canyon NP

Zion NP

Canyonlands NP

Sycamore Canyon W

Petrified Forest NP

Arches NP

Mesa Verde NP

Mazatzal W

Pine Mountain W

Class I Area

8th Highest deciview

Met Year 2001 Met Year 2002 Met Year 2003

At EPA’s request, the modeling results graphically shown in Figure 3-2 are the deciview changes from the 

source alone relative to natural background, and thus they do not include the natural background component 

that would actually be present for the full visibility result. SRP believes that the complete visibility results are 

appropriate to present as well to view the modeled changes relative to the total visibility effects that are 

actually seen, so they are included in Appendix E for completeness.
4-1 January 2009 BART Analysis for Navajo Generating Station 

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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 effects 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 Units 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 
4-2 January 2009 BART Analysis for Navajo Generating Station 

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from the boiler unit, additional ductwork, fans, and a fly ash collecting device. The fly ash collector 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 NOx reduction efficiency of less than 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 + 4NH3 + 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 un-reacted 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 
4-3 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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

EPA Region 9’s letter requesting a revised BART analysis (see Appendix F) mentioned that the calculations 

and assumptions for H2SO4 emission rates and assumptions for reactions with ammonia be provided for the 

SCR option. This discussion is also relevant for the SNCR option, so it is provided here. 

A sulfur conversion rate of 95% to SO2 (for purposes of computing H2SO4 emissions) is assumed (EPRI, 2008, 

page 4-5). The average ammonia slip (that amount of ammonium that does not react to remove NOx) 

assumed for the SNCR option (5 ppm; see EPRI, 2008, page 4-8) is used to determine the pound moles of 

ammonia molecules that will combine with the available pound moles of H2SO4 from coal combustion to form 

ammonium sulfate or ammonium bisulfate. As noted in EPRI (2008, page 3-4), when ammonia is present in 

an amount over twice the mole content of the H2SO4, the reaction product will almost always be ammonium 

sulfate. That is always the case for SNCR controls, for which the available ammonia is far higher than the 

available H2SO4 on a mole basis. It is assumed that for the SNCR case, all of the available H2SO4 is 

converted to ammonium sulfate within the boiler, which precipitates out in the air preheater at temperatures 

between 300° and 450°F. The remaining excess ammonia is available for reaction with SO2 and NOx

discharged from the boiler, as noted in tables referenced below. For modeling purposes, the effective direct 

sulfate emissions are the same (whether in the form of H2SO4 or ammonium sulfate). 

 

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. 
4-4 January 2009 BART Analysis for Navajo Generating Station 

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The ammonium sulfate that is formed due to the SNCR control equipment is emitted in the CALPUFF model 

as primary sulfate, since this is the only mechanism to provide CALPUFF with direct emissions of hygroscopic 

sulfate (in the form of either ammonium bisulfate or H2SO4). Controls for removal of ammonium sulfate by the 

wet scrubber and air pre-heater are assumed to be the same as those specified for H2SO4 in EPRI (2008) – 

10% for the air pre-heater and 47% for the wet scrubber. 

For the requested sensitivity analysis involving excess ammonia emissions, we have simplified the analysis to 

either assume the values associated with 5 ppm ammonia slip (less that mass converted to ammonium 

sulfate) or zero excess ammonia emissions as an implausible extreme sensitivity case to provide limits to the 

possible range of modeling results. The results of this analysis are provided in Appendix B. 

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. 

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 
4-5 January 2009 BART Analysis for Navajo Generating Station 

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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. 

The average ammonia assumed for the SCR option (0.75 ppm; see EPRI, 2008, page 4-8) is used to 

determine the pound moles of ammonia molecules that will combine with the available pound moles of H2SO4

from coal combustion to form ammonium sulfate or ammonium bisulfate. As noted in EPRI (2008, page 3-4), 

when ammonia is present in an amount less than the mole content of the H2SO4, the reaction product will 

almost always be ammonium bisulfate. That is always the case for SCR controls, for which the available 

ammonia is much lower than the available H2SO4 on a mole basis. It is assumed that for the SCR case, all of 

the available ammonia is converted to ammonium bisulfate within the SCR system, which precipitates out in 

the air pre-heater at temperatures between 300° and 450°F. Consequently, there is no excess ammonia 

available for reaction with SO2 and NOx discharged from the boiler, as noted in tables referenced below. 

Therefore, no sensitivity modeling of ammonia slip is necessary for the SCR BART control cases. 

The ammonium bisulfate that is formed in the SCR control equipment (plus the un-reacted H2SO4) is emitted in 

the CALPUFF model as primary sulfate, as noted for the SNCR case. Controls for removal of newly created 

ammonium bisulfate and remaining H2SO4 by the wet scrubber and air pre-heater are assumed to be the same 

as those specified for H2SO4 in EPRI (2008) – 10% for the air pre-heater and 47% for the wet scrubber. 

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. 

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 
4-6 January 2009 BART Analysis for Navajo Generating Station 

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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%. 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 

through 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 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 is 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 2008, and R. 

Hardman, et al. 1998. For coal-fired boilers equipped with SCR, H2SO4 emissions are determined by 

the following relationship: 

E = (Q)(98.06/64.04)(F1+S2)(F2) 
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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, 0.90 for an air pre-heater, and 

0.47 for wet FGD). 

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

As discussed above, the reaction of ammonia with the H2SO4 in the control equipment will deplete the 

ammonia and H2SO4 as ammonium sulfate or bisulfate is formed. The total mass of ammonium 

sulfate (or bisulfate) and remaining H2SO4 are converted to equivalent lb/hr of primary sulfates, 

subjected to controls by the downstream control equipment (air pre-heater and wet scrubber) and a 

final primary sulfate emission rate is computed for input to CALPUFF. 

• 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 

4-4 through 4-8. Option 1 Alternative simply reduces the NOx emission rates by 16.7% from those listed in 

Table 4-4. 

4.4 Analysis 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 Issues 

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

SNCR to Units 1 through 3. These costs are based upon an analysis conducted by Sargent & Lundy (2008). 

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) $42,000,000 $4,866,000 $0 $4,866,000 

2 LNB/SOFA&SNCR (Units 

1-3) $78,000,000 $9,037,000 $17,391,000c

 $26,428,000 

3 

LNB/SOFA (Unit 2); 

LNB/SOFA&SCR 

(Units1&3) 

$438,000,000b

 $50,747,000 $8,778,000 $59,525,000 

4 LNB/SOFA&SCR (Units 1-

3) $705,000,000b

 $81,681,000 $13,167,000 $94,848,000 

(a) Fixed capital costs based on a CRF of 0.1159, assuming an interest rate of 9.8% 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.
4-9 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

4.4.2 Non-Air Quality Environmental Issues 

One of the most significant consequences 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% 

are considered dangerous to human health. An accidental release of anhydrous ammonia or 20% or 

greater aqueous ammonia may pose a risk to workers and the public, and is reportable to local, state, and 

federal agencies. In anticipation of such an incident, the site would need to develop, implement, and 

maintain a Risk Management Plan (RMP) and Process Safety Measures (PSM) Program. Risk 

communication to the general public typically includes a worst-case analysis with potential effects 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 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 31 tons of anhydrous ammonia would be required each day in the three 

units at 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 NGS. This truck traffic would add to the atmospheric 

burden of NOx, VOCs, CO, CO2 and PM10 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 average ammonia slip associated with SCR is 

approximately 0.75 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 effects 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 effects associated with the proposed BART control 

options. 
4-10 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

Table 4-3 Summary of Non-Air Quality Environmental Effects 

Control Alternative Summary of Non-Air Quality Environmental Effects 

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

• Slight increase in CO2 emissions/kwh due to 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 will 

result in NOx, VOC, CO, CO2, and PM10 air emissions. 

• Anhydrous ammonia and aqueous ammonia above 20% 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% 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 will result 

in NOx, VOC, CO, CO2, and PM10 air emissions. 
4-11 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

4.4.3 Energy Impacts 

SCR would consume significantly more electrical energy than any of the other BART options, including 

SNCR. The higher electrical energy consumption for SCR relative to the other BART options 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. For example, assuming a pressure drop of 

14 inches water gauge (W.G.) across the catalyst bed, SCR applied to all three units would consume 

approximately 22,500 kW more electrical power than SNCR (approximately 1% of the total power generation 

of NGS) for each hour of operation. The increased emissions of 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 effects 

of the increase in air emissions associated with SCR’s higher energy demands. 

4.4.4 Remaining Useful Life 

A 20-year amortization period for NGS was used for purposes of the BART analysis. 
4-12 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-4 Navajo Generating Station SOFA/LNB Emission Controls (Option 1) 
4-13 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-5 Navajo Generating Station SOFA/LNB Emission Controls (Alternative Option 1) 
4-14 

BART Analysis for Navajo Generating Station 05830-012-300

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

fine total fine soil 

MMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtu lb/MMBtu(e) lb/hr lb/hr lb/hr lb/hr lb/hr 

Navajo 1

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, SNCR, hot side ESP, wet FGD

211,074 8,795 0.593 5.85 487.75 0.055 59% 21.11 1,759 0.200 0.026 228.7 153.20 (f) 86.89 (f) 66.31 (f) 63.9 (g) 

Navajo 2

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, SNCR, hot side ESP, wet FGD

226,163 9,423 0.593 6.32 526.92 0.056 55% 22.62 1,885 0.200 0.021 197.9 132.59 (f) 75.20 (f) 57.39 (f) 55.3 (g) 

Navajo 3

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, SNCR, hot side ESP, wet FGD

219,778 9,157 0.593 6.91 576.17 0.063 56% 21.98 1,831 0.200 0.031 283.9 190.20 (f) 107.87 (f) 82.33 (f) 79.3 (g) 

NH3 5.00 ppmvd at 6% O2

0.00302 lb/MMBtu

unit 1 26.60 lb/hrunit 2 28.50 lb/hrunit 3 27.69 lb/hr

(l) Ammonia is assumed to react with SO4 to form ammonium sulfate per EPRI 2008 if the molecules of NH3 are at least twice those of H2SO4; otherwise, ammonium bisulfate is formed. In this case, it is assumed that the wet FGD system will not removwould remove H2SO4.(j) Organic condensable PM10 is 0.20 x 0.02 lb/MMBtu = 0.004 lb/MMBtu with FGD based on AP-42, Table 1.1-5, September 1998. (h) Total condensable PM10 is the sum of H2SO4 and organic condensible PM10 emissions. 

Facility Unit Description

Maximum Heat Input (a)

Maximum 

Sulfur 

Content (b)

Maximum Filterable

PM Emissions

Filterable PM10 

total coarse

Fine

(k) Ammonia slip is 5 ppmvd at 6% O2 for SNCR.

Maximum SO2 Emissions (c) Maximum NOx Emissions (d)

(i) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants", Electric Power Research Institute, Technical Update, March, 2008 and Hardman et al., 1998. Oxidation of fuel S is 0.111% during combustion (ba

and the heating value is 10,496 Btu/lb. H2SO4 control efficiency is 37% for a hot side ESP, 10% for an air preheater, and 53% for wet FGD. 100% of the flue gas is controlled by wet FGD. Therefore, H2SO4 emissions are determined by: 0.00111 x 0.593

98.06/32.07 x 0.63 x 0.9 x 0.47. EPRI (2008) Eqn 4-2b indicates that 95% of fuel sulfur is converted to SO2.(g) Elemental carbon is 3.7% of fine PM 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 (e) Maximum of 6 stack test results for the 2001 to 2006 period.(f) For a dry bottom boiler with an ESP, 67% of filterable PM is PM10 and 29% is fine PM10 (PM2.5) based on AP-42, Table 1.1-6, September 1998.

(a) Maximum daily 24 hour actual heat input based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 12/09/03, Unit 2 based on 11/13/02, and Unit 3 based on 01/31/02.(b) Maximum fuel sulfur content is based on daily data for the 2001 to 2003 period. Maximum sulfur content is 0.593% with a heating value of 10,496 Btu/lb based on 01/08/03.(d) Maximum daily/24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 04/15/01, Unit 2 based on 03/12/01, and Unit 3 based on 03/26/01.(c) Maximum daily 24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 05/19/03, Unit 2 based on 05/07/03, and Unit 3 based on 03/31/03. An average of 9 days/unit over the 3 year period were excluded 

or malfunction.
4-15 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-6 Navajo Generating Station SOFA/LNB/SNCR Emission Controls (Option 2) cont. 
4-16 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-7 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 3) 

fine total fine soil 

MMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtu lb/MMBtu(e) lb/hr lb/hr lb/hr lb/hr lb/hr 

Navajo 1

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR wet FGD

211,074 8,795 0.593 5.85 487.75 0.055 84% 8.44 704 0.080 0.026 228.66 153.20 (f) 86.89 (f) 66.31 (f) 63.9 (g) 

Navajo 2

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, wet FGD

226,163 9,423 0.593 6.32 526.92 0.056 46% 27.14 2,262 0.240 0.021 197.89 132.59 (f) 75.20 (f) 57.39 (f) 55.3 (g) 

Navajo 3

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

219,778 9,157 0.593 6.91 576.17 0.063 82% 8.79 733 0.080 0.031 283.88 190.20 (f) 107.87 (f) 82.33 (f) 79.3 (g) 

NH3 0.75 ppmvd at 6% O2

0.00045 lb/MMBtu

unit 1 3.99 lb/hrunit 2 0.00 lb/hrunit 3 4.15 lb/hr

Filterable PM10 

Fine

Maximum Filterable

PM Emissions

Unit Description

(a) Maximum daily 24 hour actual heat input based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 12/09/03, Unit 2 based on 11/13/02, and Unit 3 based on 01/31/02.(e) Maximum of 6 stack test results for the 2001 to 2006 period.(g) Elemental carbon is 3.7% of fine PM 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 (b) Maximum fuel sulfur content is based on daily data for the 2001 to 2003 period. Maximum sulfur content is 0.593% with a heating value of 10,496 Btu/lb based on 01/08/03.(d) Maximum daily/24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 04/15/01, Unit 2 based on 03/12/01, and Unit 3 based on 03/26/01.(c) Maximum daily 24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 05/19/03, Unit 2 based on 05/07/03, and Unit 3 based on 03/31/03. An average of 9 days/unit over the 3 year period were excluded or malfunction.(f) For a dry bottom boiler with an ESP, 67% of filterable PM is PM10 and 29% is fine PM10 (PM2.5) based on AP-42, Table 1.1-6, September 1998.(l) Ammonia is assumed to react with SO4 to form ammonium sulfate per EPRI 2008 if the molecules of NH3 are at least twice those of H2SO4; otherwise, ammonium bisulfate is formed. 

Facility

Maximum SO2 Emissions (c) Maximum NOx Emissions (d) Maximum Heat Input (a)

Maximum 

Sulfur 

Content (b)

(h) Total condensable PM10 is the sum of H2SO4 and organic condensable PM10 emissions. (k) Ammonia slip is 0.75 ppmvd at 6% O2 for SCR.(i) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants", Electric Power Research Institute, Technical Update, March, 2008 and Hardman et al., 1998. Oxidation of fuel S is 0.111% during combustion (ba

and the heating value is 10,496 Btu/lb. H2SO4 control efficiency is 37% for a hot side ESP, 10% for an air preheater, and 53% for wet FGD. 100% of the flue gas is controlled by wet FGD. Therefore, H2SO4 emissions from fuel are determined by: 0.001

Input x 98.06/32.07 x 0.63 x 0.9 x 0.47. SCR rate of oxidation of SO2 to SO3 is assumed to be 1.0%. EPRI (2008) Eqn 4-2b indicates that 95% of fuel sulfur is converted to SO2.(j) Organic condensable PM10 is 0.20 x 0.02 lb/MMBtu = 0.004 lb/MMBtu with FGD based on AP-42, Table 1.1-5, September 1998. 

total 

coarse 
4-17 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-7 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 3) cont. 

lb/hr lb/hr lb mole/hr lb mole/hr lb mole/hr lb/hr lb/hr lb/hr lb/hr 

Navajo 1

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR wet FGD

154.48 3.99 (k) 0.234 1.575 -1.34 (l) 0.00 131.51 22.97 65.35 

Navajo 2

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, wet FGD

4.58 0.00 (k) 0.000 0.047 -0.05 (l) 0.00 4.58 0.00 4.58 

Navajo 3

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

160.85 4.15 (k) 0.244 1.640 -1.40 (l) 0.00 136.93 23.92 68.04 

Total 

H2SO4 

before NH3 

Unit Description interaction Facility

NH3 Slip NH3 H2SO4 Excess NH3 (Slip) H2SO4 

(NH4)2SO4

/NH4HSO4 

(as H2SO4)

Total 

Effectiv

H2SO4 

Modelin
4-18 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-8 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 4) 

fine total fine soil 

MMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtu lb/MMBtu(e) lb/hr lb/hr lb/hr lb/hr lb/hr 

Navajo 1

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

211,074 8,795 0.593 5.85 487.75 0.055 84% 8.44 704 0.080 0.026 228.66 153.20 (f) 86.89 (f) 66.31 (f) 63.9 (g) 

Navajo 2

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

226,163 9,423 0.593 6.32 526.92 0.056 82% 9.05 754 0.080 0.021 197.89 132.59 (f) 75.20 (f) 57.39 (f) 55.3 (g) 

Navajo 3

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

219,778 9,157 0.593 6.91 576.17 0.063 82% 8.79 733 0.080 0.031 283.88 190.20 (f) 107.87 (f) 82.33 (f) 79.3 (g) 

NH3 0.75 ppmvd at 6% O2

0.00045 lb/MMBtu

unit 1 3.99 lb/hrunit 2 4.27 lb/hrunit 3 4.15 lb/hr

Facility Unit Description

Maximum Heat Input (a) Maximum NOx Emissions (d)

(h) Total condensable PM10 is the sum of H2SO4 and organic condensable PM10 emissions. (f) For a dry bottom boiler with an ESP, 67% of filterable PM is PM10 and 29% is fine PM10 (PM2.5) based on AP-42, Table 1.1-6, September 1998.

total coarse

Fine

Maximum 

Sulfur 

Content (b)

Maximum SO2 Emissions (c) Maximum Filterable PM Emissions

Filterable PM10

(j) Organic condensable PM10 is 0.20 x 0.02 lb/MMBtu = 0.004 lb/MMBtu with FGD based on AP-42, Table 1.1-5, September 1998. (k) Ammonia slip is 0.75 ppmvd at 6% O2 for SCR.(l) Ammonia is assumed to react with SO4 to form ammonium sulfate per EPRI 2008 if the molecules of NH3 are at least twice those of H2SO4; otherwise, ammonium bisulfate is formed. (c) Maximum daily 24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 05/19/03, Unit 2 based on 05/07/03, and Unit 3 based on 03/31/03. An average of 9 days/unit over the 3 year period were excluded 

or malfunction.(d) Maximum daily/24 hour actual emissions based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 04/15/01, Unit 2 based on 03/12/01, and Unit 3 based on 03/26/01.(e) Maximum of 6 stack test results for the 2001 to 2006 period.(g) Elemental carbon is 3.7% of fine PM 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 (i) H2SO4 emissions are based on "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants", Electric Power Research Institute, Technical Update, March, 2008 and Hardman et al., 1998. Oxidation of fuel S is 0.111% during combustion (baand the heating value is 10,496 Btu/lb. H2SO4 control efficiency is 37% for a hot side ESP, 10% for an air preheater, and 53% for wet FGD. 100% of the flue gas is controlled by wet FGD. Therefore, H2SO4 emissions are determined by: 0.00111 x 0.593

98.06/32.07 x 0.63 x 0.9 x 0.47. EPRI (2008) Eqn 4-2b indicates that 95% of fuel sulfur is converted to SO2.(a) Maximum daily 24 hour actual heat input based on Part 75 monitoring data for the 2001 - 2003 period. Unit 1 based on 12/09/03, Unit 2 based on 11/13/02, and Unit 3 based on 01/31/02.(b) Maximum fuel sulfur content is based on daily data for the 2001 to 2003 period. Maximum sulfur content is 0.593% with a heating value of 10,496 Btu/lb based on 01/08/03.
4-19 

BART Analysis for Navajo Generating Station 05830-012-300

Table 4-8 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 4) cont. 

lb/hr lb/hr lb mole/hr lb mole/hr lb mole/hr lb/hr lb/hr lb/hr lb/hr 

Navajo 1

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

154.48 3.99 (k) 0.234 1.575 -1.34 (l) 0.00 131.51 22.97 65.35 

Navajo 2

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

165.52 4.27 (k) 0.251 1.688 -1.44 (l) 0.00 140.91 24.61 70.02 

Navajo 3

750 MW, PC, bituminous coal, dry bottom, tangential fired, LNB, SOFA, hot side ESP, SCR, wet FGD

160.85 4.15 (k) 0.244 1.640 -1.40 (l) 0.00 136.93 23.92 68.04 

Facility Unit Description

NH3 Slip

Tota

Effecti

H2SO4 

Modeli

Excess NH3 (Slip)

(NH4)2SO4

/NH4HSO4 

(as H2SO4)

H2SO4 

NH3 H2SO4

Total H2SO4 

before NH3 

interaction
5-1 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

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. 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. These controls 

would also be in place for all subsequent BART options described below, so the change in visibility for these 

other options is most appropriate compared to BART Option 1a. 

Option 2: Advanced combustion controls with SNCR on Units 1 through 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 through 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 11 Class I areas and the three modeled 

years, of the predicted visibility changes due to installation of the candidate BART controls on the NGS units. 

Table 5-2 shows detailed information on the visibility effects 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. Appendix E contains the same tables and graphs with the natural background visibility 

component included. 

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

Option 1: The results show that the averaged regional haze changes will improve visibility by about 0.37 

delta-deciview (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 BART 

Guidelines for large electric generating plants. 

Option 1 Alternative: The results show that the averaged regional haze changes will improve visibility by 

about 0.47 delta-deciview (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 BART Guidelines for large electric generating plants. 

Option 2: The modeling results averaged over all 11 Class I areas show that addition of SNCR on all three 

units after installing LNB/SOFA will improve visibility by about 0.39 delta-deciview relative to the baseline case. 

However, this BART option would not improve visibility relative to the results of Option 1a at any of the Class I 

areas. This lack of visibility improvement/degradation occurs because NOx emissions are exactly the same as 

those for BART Option 1a, with the complication that the installation of SNCR would create new emissions of 

excess ammonia in an area with low levels of ambient ammonia. As discussed in Appendix B, the higher 
5-2 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

resulting levels of ambient ammonia concentrations at the Class I areas due to increased stack emissions of 

ammonia would cause higher concentrations of ammonia nitrate particulates, and result in more visibility 

degradation. Therefore, NOx emission controls involving SNCR are ineffective relative to BART Option 1a. 

Since BART control option 2 is not effective in improving visibility relative to Option 1a, it is not recommended 

in addition to the installation of LNB/SOFA. 

Option 3: The modeling results averaged over all 11 Class I areas show that installation of SCR on Units 1 

and 3 in addition to the Option 1 NOx controls will improve visibility by about 0.57 delta-deciview over the 

baseline case. However, the average visibility improvement over BART Option 1a is only 0.10 delta-deciview. 

It is noteworthy that the installation of SCR would create new emissions of primary sulfates (H2SO4 and 

ammonium bisulfate), and would lead to increased gross generation to run the SCR equipment, which has not 

even been factored into the modeling analysis. The increased emissions of sulfates due to SCR operation will 

cause additional visibility impairment in all seasons of the year, especially during the high visitation season of 

summer. In contrast, the NOx reductions will generally have a benefit only during the wintertime months due to 

the nature of the nitrate equilibrium that is discussed in Appendix B. Therefore, NOx emission controls 

involving SCR are relatively ineffective for improving visibility in this case, especially taking into account the 

very high cost of the controls, which are discussed further in Section 5.3. 

Option 4: The modeling results averaged over all 11 Class I areas show that addition of SCR on all three units 

in addition to the Option 1 controls will improve visibility by about 0.70 delta-deciview over the baseline case. 

The average visibility improvement over BART Option 1a is about 0.22 delta-deciview, which is less than onethird of this overall improvement. This incremental improvement in visibility over Option 1a is imperceptible in 

spite of the NOx emission reductions, for the same reasons stated above for BART Option 3.. Therefore, as 

noted above, NOx emission controls involving SCR produce low incremental improvements in visibility in this 

case, especially taking into account the very high cost of the controls for retrofitting Unit 2 in addition to the 

other units, as discussed in Section 5.3. 

5.3 Cost Effectiveness of BART Control Options 

Table 5-3 summarizes the annualized control cost, as well as an incremental computation of each control 

option’s visibility improvement effectiveness and cost (on a dollar-per-deciview basis). The visibility results in 

Table 5-3 are based on the average of the three years. Tables D-2, D-3, and D-4 in Appendix D show the 

visibility and cost effectiveness results for each meteorological year, while Table D-1 presents annualized cost 

data and information on dollars-per-NOx-ton removed. Figure 5-2 shows a graph of visibility 

improvements/degradations as a function of the cost of each control option and each Class I area and is 

based on the average of the three years. Table 5-2 and Figure 5-2 indicate that, if Option 2 (SNCR) were 

adopted, the visibility would degrade in Grand Canyon National Park and Capitol Reef National Park, and 

would not improve in the rest of the Class I areas, as compared to Option 1a. 

For the baseline and all BART control options in general, Capitol Reef and Grand Canyon National Parks are 

modeled to experience the highest potential visibility effects from NGS because they are the closest Class I 

areas. The “penalty” of SCR-related increased emissions of primary sulfates is most important in the these 

closest and most heavily affected Class I areas, especially the Grand Canyon National Park. This is due to the 

fact that the formation of secondary sulfates from SO2 emissions, which are the same for all NOx BART control 

options, are relatively low for short distances. In contrast, the primary sulfates become visibility impairing 

particles immediately and have an important and adverse effect on visibility in the closest Class I areas 

mentioned above. 

Beyond installation of controls for BART Option 1 (or 1-alternative), the visibility at these closest two parks 

show only a relatively modest benefit (if any) from adoption of any of the additional control options considered. 

As noted above, the installation of SNCR is not a beneficial option. BART options 3 and 4 controls are 
5-3 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

predicted to have only modest visibility improvements relative to BART Option 1a, and at a very high cost. In 

fact, at Grand Canyon National Park, the visibility would degrade (compared with Option 1a) with SCR 

installation due to addition of primary sulfates and excess ammonia. 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). 

As mentioned in Section 5.2, the visibility benefits from BART Option 3 (SCR on Units 1 and 3) is, on average, 

0.57 delta-deciviews relative to the baseline case, but only 0.10 delta-deciview of that improvement occurs 

with the installation of the SCR equipment; most of the improvement comes from LNB/SOFA controls. 

Moreover, the annualized cost to obtain the first 0.47 delta-deciview of the average visibility improvement is 

about $5 million per year, while the cost to obtain the remaining 0.10 delta-deciview improvement for BART 

Option 3 is nearly $60 million per year (12 times the cost of LNB/SOFA). As shown in Figure 5-2, this dollarper-deciview calculation can be seen graphically as a very steep increase in the slopes of the plotted lines 

relative to the slope for Option 1a. This analysis clearly indicates that not only is the additional visibility benefit 

in adding SCR on Units 1 and 3 rather minimal, the cost for this additional small improvement is very high. 

The same analysis can be done for BART Option 4 (SCR on all units). In this case, the visibility benefits for 

this BART option are, on average, 0.70 delta-deciviews relative to the baseline case, but less than a third of 

this amount, 0.22 delta-deciviews, occurs with the installation of the SCR equipment. While the annualized 

cost to obtain the first 0.47 delta-deciview of the average visibility improvement is about $5 million per year, 

the cost to obtain the remaining 0.22 delta-deciview improvement for BART Option 4 is nearly $95 million per 

year (19 times the cost of LNB/SOFA). As shown in Figure 5-2, this dollar-per-deciview calculation can be 

also be seen graphically as a very steep increase in the slopes of the plotted lines relative to the slope for 

Option 1a. Similar to BART Option 3, this analysis clearly indicates that not only is the additional visibility 

benefit in adding SCR all units small, the cost for this additional small improvement is extremely high. 

It is noteworthy that the effect of nitrates on visibility in Class I areas is highly seasonal, as described in 

Appendix B and shown with actual data in Appendix C. Basically, the visibility impairment from sulfate 

emissions is important year-round, while the visibility impairment from nitrate emissions is important only in 

cold-weather months. Unfortunately, the SCR operation increases sulfate emissions during all periods 

(including the period of high tourist visitation to the National Parks), while the reduction of NOx emissions is 

only effective during the period of low tourist visitation. While there are modest visibility benefits of SCR 

controls relative to LNB/SOFA controls on an annual basis, benefits during the high visitation months of April 

through October are either reduced substantially or become nonexistent and are replaced by a degradation of 

visibility in some cases. More information in this regard is presented in Appendix G. This supplemental 

information lends additional justification for the rejection of post-combustion NOx controls as BART. 
5-4 

BART Analysis for Navajo Generating Station 05830-012-300

Table 5-1 Regional Haze Benefit of BART Controls 

2001 2002 2003 2001-2003 

Ave 

Benefit of Controls from Option 1/ 1a, delta-dv 

Class I Area 

Option BART Controls 

8th Highest delta deciview 

Baseline None 1.79 1.76 1.69 1.75 n/a Option 1 SOFA/LNB on Units 1-3 (0.24 

lb NOx/MMBtu) 

1.42 1.41 1.29 1.38 n/a 

Option 1-alt 

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

1.31 1.32 1.19 1.27 0.10 

Option 2 SOFA/LNB/SNCR on Units 

1-3 

1.39 1.43 1.26 1.36 -0.08 

Option 3 SOFA/LNB/SCR on Units 

1&3 and SOFA/LNB on Unit 2 

1.19 1.22 1.10 1.17 0.10 

Average of 11 Class I Areas Option 4 SOFA/LNB/SCR on Units 1-3 1.04 1.10 1.01 1.05 0.22 
5-5 

BART Analysis for Navajo Generating Station 05830-012-300

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

0.00.51.01.52.02.53.0

Grand

Canyon

Capitol Reef Bryce

Canyon

Zion Canyonlands Sycamore

Canyon

Petrified

Forest

Arches Mesa Verde Mazatzal Pine

Mountain

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/MMBtu)Option 2: SOFA/LNB/SNCR on Units 1-3Option 3: SOFA/LNB/SCR on Units 1&3 and SOFA/LNB on Unit 2Option 4: SOFA/LNB/SCR on Units 1-3
5-6 January 2009 BART Analysis for Navajo Generating Station 

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Table 5-2 Regional Haze Results of BART Controls for Each Year and Class I Areas 
5-7 January 2009 BART Analysis for Navajo Generating Station 

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Table 5-2 Regional Haze Results of BART Controls for Each Year and Class I Areas, continued 
5-8 January 2009 BART Analysis for Navajo Generating Station 

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Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average 
5-9 January 2009 BART Analysis for Navajo Generating Station 

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Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average, continued 
5-10 January 2009 BART Analysis for Navajo Generating Station 

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Figure 5-2 Annual Costs vs. Visibility Improvements/Degradation, 3-Year Average 

$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

$90,000,000

$100,000,000

3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0

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

Cost ($/year)

Arches

Bryce Canyon

Canyonlands

Capitol Reef

Grand Canyon

Mazatzal

Mesa Verde

Petrified Forest

Pine Mountain

Sycamore Canyon

Zion

Baseline

Option 1 & 1-alt

Option 2

Option 3

Option 4
6-1 January 2009 BART Analysis for Navajo Generating Station 

05830-012-300

6.0 BART Recommendations 

ENSR and SRP recommend LNB/SOFA for all three units as BART for NGS, 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 affect local 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 recommended BART controls is presented in Table 6-1, 

and Table 6-2 presents an overall summary of the BART determination. 

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 At least 48% at 0.24 lb/MMBtu 

Estimated NOx Reduction (TPY) at 85% utilization 

About 22,675 tons per year at 0.24 lb/MMBtu (Option 

1), and about 26,755 tons per year at 0.20 lb/MMBtu 

(Option 1a) 

Costs of Compliance • $42 million capital cost 

• $4.9 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 Changes 

• 0.54 – 0.70 deciview improvement at Arches 

and Canyonlands NP (largest Class I area 

improvements for Options 1 and 1a) 

• 0.37 – 0.47 deciview improvement (3-year 

and 11-park average) 
6-2 January 2009 BART Analysis for Navajo Generating Station 

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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 are ordinarily needed to meet the BART presumptive limits for boilers of the type at NGS. Each control 

option was modeled to assess visibility changes at 11 Class I areas within 300 km of NGS. 

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

addition to LNB/SOFA would have a detrimental, or at best only a modest beneficial effect on visibility at the 

closest Class I area: Grand Canyon National Park. Option 2 (adding SCNR to all units in addition to 

LNB/SOFA) would produce virtually no change from Option 1 or Option 1a (except that it would degrade 

visibility at Grand Canyon National Park and Capitol Reef National Park). Options 3 and 4 (adding SCR to 

LNB/SOFA at two or three units) would produce minimal visibility improvements at high cost and cause 

increased emissions of ammonia salts and sulfuric acid aerosols (and in fact are predicted to degrade visibility 

at Grand Canyon National Park). 

At those Class I areas at which BART Options 3 and 4 are not predicted to degrade visibility, the visibility 

improvement predicted (i.e., by going from Option 1a to Option 3 or Option 4), as indicated by the 98th

percentile results, is in all cases less than the 0.5-deciview contribution threshold (half the perceptible limit) 

that EPA describes in the BART Guidelines. It is also evident from the cost information reported in Section 5 

that the dollar-per-deciview cost for post-combustion controls is extremely high for those areas for which any 

improvement in visibility is projected. Therefore, post-combustion NOx emission controls are not cost-effective. 

Consequently, none of the post-combustion-control options are 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, with a possible reduction to 0.20 lb/MMBtu), that is lower than the applicable 

BART presumptive limit of 0.28 lb/MMBtu. 
6-3 

BART Analysis for Navajo Generating Station 05830-012-300

Table 6-2 Summary of BART Analysis for NOx

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

Identify 

Control 

Technologies 

Feasible 

Control 

Technology

? 

Evaluate Control 

Effectiveness for 

Technically 

Feasible Control 

Technologies 

Calculate Cost 

Effectiveness 

for Control 

Technologies 

(relative to 

baseline) 

Determine 

Non-Air Quality 

Environmental and 

Energy Impacts 

Evaluate Vis

Changes 

Controls 

baselin

Control 

Option 1 

Low NOx

burners, 

separated 

overfire air 

Yes 48% NOx reduction from baseline Annualized cost = $4.9 MM 

Increase in fuel 

consumption, LOI of fly 

ash, corrosion, 

increase in CO 

average vis

improvement 

delta-dv 

Alternative 

to Control 

Option 1 

Low NOx

burners, 

separated 

overfire air 

Yes 

57% NOx reduction 

from coal-fired 

baseline (9% 

reduction relative to 

Option 1) 

Annualized cost 

= $4.9 MM 

Increase in fuel 

consumption, LOI of fly 

ash, corrosion, 

increase in CO 

average vis

improvement 

delta-dv (0

reduction rela

Option 1

Control 

Option 2 

Low NOx

burners, 

separated 

overfire air, and 

SNCR 

Yes 

57% NOx reduction 

from coal-fired 

baseline (no 

additional reduction 

from Option 1a) 

Annualized cost 

= $26.4 MM 

Excess NH3 emissions; 

1% plant energy 

consumption; NH3 risk 

to workers and public, 

air emissions of NH3

transport 

average vis

improvement 

delta-dv 

(degradation 

Option 1

Control 

Option 3 

Low NOx

burners, 

separated 

overfire air, and 

SCR (Units 1,3) 

Yes 

71% NOx reduction 

from coal-fired 

baseline (14% 

reduction relative to 

Option 1a) 

Annualized cost 

= $59.5 MM 

Excess sulfate 

emissions; 1% plant 

energy consumption; 

NH3 risk to workers and 

public, air emissions of 

NH3 transport 

average vis

improvement 

delta-dv (0

reduction rela

Option 1

Control 

Option 4 

Low NOx

burners, 

separated 

overfire air, and 

SCR (all units) 

Yes 

83% NOx reduction 

from coal-fired 

baseline (26% 

reduction relative to 

Option 1a) 

Annualized cost 

= $94.8 MM 

Excess sulfate 

emissions; 1% plant 

energy consumption; 

NH3 risk to workers and 

public, air emissions of 

NH3 transport 

average vis

improvement 

delta-dv (0

reduction rela

Option 1
7-1 January 2009 BART Analysis for Navajo Generating Station 

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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 

Hardman, R., R. Stacy and E. Dismukes. 1998. Estimating Total Sulfuric Acid Emissions from Coal-Fired Power 

Plants. Southern Company Services. 

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). 

Sargent & Lundy, 2008. Salt River Project Navajo Generating Station: SCR & SNCR Cost Study. Project No. 

11234-028, August 28, 2008. 

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. 
BART Analysis for Navajo Generating Station January 2009

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Appendix A 

CALMET/CALPUFF Processing Refinements 
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Enhancements to the WRAP CALMET Database 

ENSR suggested two modifications/enhancements to the 4-km Arizona CALMET WRAP database. They are as 

follows: 

The 4-km Arizona CALMET database has been produced by ENSR using the downloaded CALMET inputs from 

the WRAP website http://pah.cert.ucr.edu/aqm/308/bart/calpuff/calmet_inputs/az/. ENSR initially ran CALMET 

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

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

CALDESK. Figure A-1 graphically shows wind fields with the WRAP settings for a typical hour. Arrows represent 

wind direction and wind speed for that hour at 10 meter height. Circular areas in these figures with common winds 

and abrupt transitions at the edge of the circles indicate a radius of influence of surface stations, R1, which was 

set to 100 km, as suggested in the WRAP BART protocol. The R1 value was coupled with R1MAX = 50 km so 

that the influence of the surface stations is established out to 50 km and then it abruptly ends beyond that 

distance. Setting R1 and R1MAX to such high values is not recommended by the model developer and Federal 

Land Managers, especially with MM5 data resolution of 36 km with areas of complex terrain. Typically, R1 is set 

to a fairly small value, generally not exceeding half of the MM5 data resolution (18 km), according to recent 

guidance on multiple PSD projects involving CALPUFF modeling in the WRAP region from John Notar of the 

National Park Service (personal correspondence 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. 

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-2. The adjusted R1 and R1MAX 

values blend the surface observations into the MM5 observations much better, creating a more uniform wind field 

throughout the domain. Therefore, ENSR used the smaller R1 and R1MAX values to be more consistent with 

FLM guidance and due to the better performance in the wind field depiction associated with the smaller values. 

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

CALMET Version 5.8 instead of Version 6.211 that was used by WRAP, available at 

http://www.src.com/calpuff/download/download.htm#EPA_VERSION. 

In accordance with recent CALPUFF modeling guidance from the EPA Region IX and National Park Service (see 

Appendix F), ENSR used the technical options listed below. 

• Included upper air soundings in a Step 2 analysis; the WRAP BART protocol does not include these 

observations. Figure A-3 shows upper air and surface station locations. 

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

• Set IEXTRP = -4, to extrapolate surface wind observations to the upper layers using similarity theory, 

and ignore layer 1 from the upper air soundings. 

• Set ITPROG = 1, to use surface station temperature and the MM5 for upper air temperature 

interpolation. 
BART Analysis for Navajo Generating Station January 2009

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Figure A-1 CALMET Windfields with WRAP Settings 
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Figure A-2 CALMET Windfields with ENSR Settings 
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Figure A-3 Location of Surface and Upper Air Stations used for Arizona CALMET Domain 
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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. 

• 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 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. 

Specific CALMET options selected by ENSR are listed in Table A-1. 

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 
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Ambient 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. These proposed values are consistent with the CMAQ modeled values provided in Appendix A of 

www.vistas-sesarm.org/BART/CMAQ2002_evaluation_Dec31_2005.pdf. 

Ammonia slip sensitivity analysis is discussed in Appendix B. 

Table A-2 Ambient Ammonia Background Concentrations 

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 
BART Analysis for Navajo Generating Station January 2009

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Appendix B 

Factors Influencing NOx Emissions Effects on Visibility and 

Ammonia Slip Sensitivity Analysis 

-
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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 
BART Analysis for Navajo Generating Station January 2009

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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 

Ammonia Slip Sensitivity Analysis 

To address an EPA Region 9 request, ENSR has conducted ammonia slip sensitivity modeling analysis of emitted 

ammonia ranging from 0% to 100% of that expected. The 100% ammonia emissions case involves adding 100% 

of the modeled stack excess ammonia result to the ammonia background values, the 50% ammonia emissions 

case involves adding 50% of the modeled stack excess ammonia result to the ammonia background values, and 

the 0% ammonia emissions case means using unaltered ambient ammonia background values. This range 

covers the extremes of the analysis requested by EPA Region 9. 

The modeling analysis was limited to the SNCR case (control option 2) because that is the only case with excess 

ammonia emissions. The SCR cases (control options 3 and 4) resulted in no excess ammonia because all of the 

available ammonia (after NOx control) was assumed to combine with H2SO4 to result in additional primary sulfate 

emissions. Therefore, ammonia sensitivity modeling was not required for the SCR cases. 
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Excess ammonia emissions associated with SNCR operations were modeled in CALPUFF to determine the 8th

highest 24-hour ammonia concentration at the following six Class I area: Grand Canyon NP, Arches NP, Bryce 

Canyon NP, Canyonlands NP, Capitol Reef NP, and Zion NP. 

Predicted excess ammonia concentrations associated with SNCR operation are listed in Table B-1. The 8th

highest ammonia concentrations were first produced in μg/m3

 and then were converted to ppb. The results show 

that the predicted excess ammonia concentrations averaged over 2001-2003 are the highest at Grand Canyon NP 

(0.09 ppb with 100% of ammonia emissions) and Capitol Reef NP (0.08 ppb with 100% of ammonia emissions) 

due to their close proximity to the source. The predicted excess ammonia concentrations at the other four Class I 

area are so low (below 0.05 ppb) that adding them to the ambient background concentrations and re-computing 

modeling results would likely not make a noticeable difference in the regional haze results. Therefore, ammonia 

sensitivity modeling was conducted only for Grand Canyon NP and Capitol Reef NP. 

The resultant ammonia concentrations (with 100% and 50% of ammonia emissions) were added to the monthly 

ambient background values, as shown in Table B-2. Then the POSTUTIL program (CALPUFF post-processor) 

was used to re-compute regional haze effects with the adjusted ammonia background at Grand Canyon NP and 

Capitol Reef NP to demonstrate 0% removal efficiency. The POSTUTIL program was used to calculate regional 

haze effects with the ambient ammonia background at Grand Canyon NP and Capitol Reef NP for the case with 

no ammonia emissions. The ammonia slip sensitivity modeling results for ammonia emissions for the three 

extreme cases (0%, 50%, and 100% of expected ammonia emissions) are presented in Table B-3. 

The results show that the regional haze effects at Grand Canyon NP, averaged over 2001-2003, would increase 

by about 0.23 delta-deciview with 50% of expected ammonia emissions and by about 0.48 delta-deciview with 

100% of expected ammonia emissions. 

At Capitol Reef NP, regional haze changes would involve an increase by about 0.21 delta-deciview with 50% of 

expected ammonia emissions and by about 0.43 delta-deciview with 100% of expected ammonia emissions. 

Table B-1 Predicted Ammonia Concentrations due to SNCR Operation 

2001-2003 Average 8th highest 24-hr 

Predicted Ammonia Concentration 

Class I Area (ppb) 

100% ammonia 

emissions 

50% ammonia 

emissions 

Arches NP 0.03 0.013 

Bryce Canyon NP 0.04 0.02 

Canyonlands NP 0.04 0.02 

Capitol Reef NP 0.08 0.040 

Grand Canyon NP 0.09 0.045 

Zion NP 0.03 0.017 
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Table B-2 Background Ammonia Concentrations used for Sensitivity Modeling 

Ambient 

Ammonia 

Background 

Concentration 

at Grand 

Canyon NP and 

Capitol Reef NP 

(ppb) 

Ambient NH3

Background 

Concentration 

Plus Predicted 

Excess NH3 at 

Grand Canyon 

NP (ppb) 

Ambient NH3

Background 

Concentration 

Plus Predicted 

Excess NH3 at 

Capitol Reef NP 

(ppb) 

Ambient NH3

Background 

Concentration 

Plus Predicted 

Excess NH3 at 

Grand Canyon 

NP (ppb) 

Ambient NH3

Background 

Concentration 

Plus Predicted 

Excess NH3 at 

Capitol Reef NP 

(ppb) 

Month 

0% Ammonia 

Emissions 

50% Ammonia 

Emissions 

50% Ammonia 

Emissions 

100% Ammonia 

Emissions 

100% Ammonia 

Emissions 

January – 

February 0.2 0.245 0.24 0.29 0.28 

March – April 0.5 0.545 0.54 0.59 0.58 

May – 

September 1.0 1.045 1.04 1.09 1.08 

October – 

November 0.5 0.545 0.54 0.59 0.58 

December 0.2 0.245 0.24 0.29 0.28 

Table B-3 Ammonia Sensitivity Modeling Results 

Met Year 2001 Met Year 2002 Met Year 2003 2001-2003 

Class I Ave 

Area Case NH3 Emissions 

8th Highest Δ dv 

SNCR 

(Option 2) 0% (1) 2.15 2.35 2.12 2.21 

SNCR 

(Option 2) 50% (2) 2.38 2.66 2.27 2.44 

Grand Canyon 

SNCR 

(Option 2) 100% (3) 2.62 2.95 2.49 2.69 

SNCR 

(Option 2) 0% (1) 2.12 2.37 2.16 2.22 

SNCR 

(Option 2) 50% (2) 2.26 2.69 2.34 2.43 

Capitol Reef 

SNCR 

(Option 2) 100% (3) 2.44 2.90 2.58 2.64 

(1) 0% ammonia emissions case means using unaltered ambient ammonia background values. 

(2) 50% ammonia removal efficiency means adding 50% of the expected stack excess ammonia effects to 

the ammonia background values. 

(3) 100% ammonia removal efficiency means adding 100% of the expected stack excess ammonia effects 

to the ammonia background values. 
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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 effects) 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 contributions were virtually nonexistent during the warm period of AprilOctober (during the period of the heaviest park visitation), while sulfate contributions 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 

The pie chart for Capitol Reef NP was not available on the VIEWS web site. 
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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 

The pie chart for Zion NP was not available on the VIEWS web site. 
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Appendix D 

CALPUFF Modeling and Cost Effectiveness Results for Each Year 

from Potential Plant Contributions to Visibility Changes 
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Table D-1 Annual Costs and Costs per NOx Ton Removed 

Control 

Option Control Technology Total Capital Cost ($) Fixed Capital Cost ($/yr) Annual O&M Cost ($/yr) Total Annual Cost ($/yr) NOx (T

Removed 

Utiliza

1a LNB/SOFA (Units 1-3) 

$42,000,000 $4,866,000 $0 $4,866,000 267

2 LNB/SOFA & SNCR (Units 1-3) $78,000,000 $9,037,000 $17,391,000 $26,428,000 2673 

LNB/SOFA (Unit 2) & 

LNB/SOFA & SCR (Units 1 

and 3) $438,000,000 $50,747,000 $8,778,000 $59,525,000 347

4 LNB/SOFA & SCR (Units 1-3) $705,000,000 $81,681,000 $13,167,000 $94,848,000 389
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Table D-2 Annual Costs vs. Visibility Improvements for Year 2001 
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Table D-2 Annual Costs vs. Visibility Improvements for Year 2001, continued 
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Table D-3 Annual Costs vs. Visibility Improvements for Year 2002 
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Table D-3 Annual Costs vs. Visibility Improvements for Year 2002, continued 
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Table D-4 Annual Costs vs. Visibility Improvements for Year 2003 
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Table D-4 Annual Costs vs. Visibility Improvements for Year 2003, continued 
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Appendix E 

CALPUFF Modeling Results Using Background plus Potential PlantCaused Visibility Impairment for Each Year 
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TableE-1 Regional Haze Changes from Natural Conditions Due to Baseline Emissions 
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Figure E-1 8th Highest Regional Haze Effects for Each Modeled Year Due to Baseline Emissions 

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Grand Canyon NP

Capitol Reef NP

Bryce Canyon NP

Zion NP

Canyonlands NP

Sycamore Canyon W

Petrified Forest NP

Arches NP

Mesa Verde NP

Mazatzal W

Pine Mountain W

Class I Area

8th Highest deciview

Met Year 2001 Met Year 2002 Met Year 2003

Table E-2 Regional Haze Benefit of BART Controls 
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Figure E-2 8th Highest Regional Haze Total Results Averaged Over 3 Years for Baseline and BART 

Control Case Emissions 

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Grand

Canyon

Capitol Reef Bryce

Canyon

Zion Canyonlands Sycamore

Canyon

Petrified

Forest

Arches Mesa Verde Mazatzal Pine

Mountain

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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Table E-3 Regional Haze Results of BART Controls for Each Year and Class I Areas 
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Table E-4 Annual Costs vs. Visibility Improvements/Degradation, 3-Year Average 
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Table E-4 Annual Costs vs. Visibility Improvements/Degradation, 3-Year Average, continued 
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Figure E-3 Annual Costs vs. Visibility Improvements/Degradations, 3-Year Average 

$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

7.5 7.0 6.5 6.0 5.5 5.0 4.5 4.0

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

Cost ($/year)

Arches

Bryce Canyon

Canyonlands

Capitol Reef

Grand Canyon

Mazatzal

Mesa Verde

Petrified Forest

Pine Mountain

Sycamore Canyon

Zion

Baseline

Option 1 & 1-alt

Option 2

Option 3

Option 4
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Appendix F 

EPA Region 9 Letter to Salt River Project (July 1, 2008) 
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Appendix G 

98th Percentile Regional Haze Results During Entire Year and April – 

October Period 
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Figure G-1 98th Percentile Regional Haze Results During Entire Year 

98th Percentile Regional Haze Impacts During Full Met Year

0.0

0.5

1.0

1.5

2.0

2.5

Grand Canyon Capitol Reef Bryce Canyon Zion Canyonlands Sycamore

Canyon

Petrified

Forest

Arches Mesa Verde Mazatzal Pine Mountain

Class I Area

98th Percentile (delta-dv)

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 4: SOFA/LNB/SCR on Units 1-3

Figure G-2 98th Percentile Regional Haze Results During April 1 – October 31 

98th Percentile Regional Haze Impacts During 7 Months (April 1 - October 31)

0.0

0.5

1.0

1.5

2.0

2.5

Grand Canyon Capitol Reef Bryce Canyon Zion Canyonlands Sycamore

Canyon

Petrified

Forest

Arches Mesa Verde Mazatzal Pine Mountain

Class I Area

98th Percentile (delta-dv)

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 4: SOFA/LNB/SCR on Units 1-3
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