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./2IJ8Prepared 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.: 05830-012-300Prepared 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.: 05830-012-300i January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Contents

Executive Summary .............................................................................................................. .............................1

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

1.1 Source De scription ............................................................................................................. ............. 1-1

1.2 Reasonably Attributable BART A nalysis ........................................................................................ 1- 1

1.3 BART Requir ements.............................................................................................................. .......... 1-1

1.4 Sulfur Dioxide Em ission Co ntrol................................................................................................ ...... 1-2

1.5 Particulate Matter Emission C ontrol............................................................................................ .... 1-2

1.6 Nitrogen Oxides Emi ssion C ontrol............................................................................................... ... 1-3

1.7 Report Ou tline................................................................................................................. ................. 1-3

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

2.1 CALMET Pr ocessing .............................................................................................................. ......... 2-1

2.2 CALPUFF Modeli ng Proc edures.................................................................................................... . 2-1

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

2.4 Light Extinction and Haze Change Calcul ations ............................................................................ 2-4

3.0 BART Applicabil ity Analysis .................................................................................................... ............ 3-1

3.1 BART-Eligibility Requireme nts.................................................................................................. ...... 3-1

3.2 Existing Control Equipmen t and Emission Rates........................................................................... 3-1

3.3 Affected Cl ass I Areas......................................................................................................... ............ 3-4

3.4 Baseline CALPUFF M odeling Resu lts............................................................................................ 3- 6

4.0 BART Engineering Analysis for NO x Emissions ............................................................................... 4-1

4.1 Identification of Alternative NO x Contro ls........................................................................................ 4-1
4.1.1 Low-NO x Burners and Separated Over fire Air (LNB /SOFA)............................................ 4-1
4.1.2 Flue Gas Recirc ulation ...................................................................................................... 4-1
4.1.3 Selective Non-Cataly tic Reducti on.................................................................................... 4-2
4.1.4 Selective Catalyti c Reducti on............................................................................................ 4-4
4.1.5 ECOTUBETM...................................................................................................................... 4 -5
4.1.6 ROFATM/ROTA MIXTM........................................................................................................ 4-5

4.2 Technical Feasibility of Alternative NO x Contro ls ........................................................................... 4-6

4.3 Effectiveness of Technically Feasible NO x Contro ls ...................................................................... 4-6

4.4 Analysis of Alternative NO x Contro ls............................................................................................... 4-8
4.4.1 Economic Issues................................................................................................................ 4-8
4.4.2 Non-Air Quality Envir onmental I ssues .............................................................................. 4-9ii January 2009 BART Analysis for Navajo Generating Station 05830-012-300 4.4.3 Energy Im pacts................................................................................................................ 4 -11
4.4.4 Remaining Usef ul Life ..................................................................................................... 4-11

5.0 BART Control Options Modeling Analys is......................................................................................... 5-1

5.1 Modeled Contro l Scenar ios...................................................................................................... ....... 5-1

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

5.3 Cost Effectiveness of BAR T Control Op tions ................................................................................. 5-2

6.0 BART Recomme ndations ........................................................................................................... .......... 6-1

7.0 Refere nces..................................................................................................................... ......................... 7-1



## List of Appendices

Appendix A CALMET/CALPUFF Processing Refinements

Appendix B Factors Influencing NO x 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 pl us Potential Plant-Caus ed 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 Associat ed with BART Contro l Option s.............................ES-5
Table ES-2 Annual Costs vs. Visibility Improvement s/Degradation (Average of the 11 Class I Areas) ....ES-5

Table ES-3 Best Available Retrofit Technology – Low NO x Burners / Separated Overfire Air ..............ES-7

Table ES-4 Summary of BART Analysis for NO x ..................................................................................... Es-8

Table 2-1 Annual Average Natural Ba ckground Concent rations ............................................................ 2-2

Table 3-1 Navajo Generating Statio n Baseline Em issions ...................................................................... 3-3

Table 3-2 Navajo Generating Station M odeling Stack Pa rameters ........................................................ 3-4

Table 3-3 Regional Haze Effects Due to Baseline E missions ................................................................. 3-6

Table 4-1 Annual NO x Emission Rates Resulting from Application of Control Options to NGS Units 1 through 3 (l b/MMBtu)........................................................................................................... ..... 4-7iii 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 th rough 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 Emissi on Controls (Alterna tive Opti on 1)............... 4-13

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

Table 4-6 Navajo Generating Station SOFA/LNB/SNCR E mission Controls (Opt ion 2) cont.............. 4-15

Table 4-7 Navajo Generating Station SO FA/LNB/SCR (Opt ion 3) ....................................................... 4-16

Table 4-8 Navajo Generating Station SO FA/LNB/SCR (Opt ion 4) ....................................................... 4-18

Table 5-1 Regional Haze Benefit of BART Cont rols................................................................................ 5-4

Table 5-2 Regional Haze Results of BART Controls for Each Year and Class I Ar eas......................... 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 Impr ovements, 3-Year Average .................................................... 5-8

Table 5-3 Annual Costs vs. Visibility Improvemen ts, 3-Year Average, continue d.................................. 5-9

Table 6-1 Recommended Best Available Retrofit Technology – Low NO x Burners / Separated Overfire Air

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

Table 6-2 Summary of BART Analysis for NO x ........................................................................................ 6-3



## List of Figures

Figure ES-1 8 th Highest Regional Haze Deciview Changes from NGS BART C ontrol Opti ons ..............ES-3
Figure ES-2 Annual Costs vs. Visibility Improvem ents/Degradations, 3- Year Aver age...........................ES-6
Figure 2-1 NGS CALPUFF Computational Grid in Re lation to WRAP Ar izona Doma in ......................... 2-3
Figure 3-1 Class I Areas within 300 km of t he Navajo Generati ng Statio n.............................................. 3-5
Figure 3-2 8 th Highest Regional Haze Changes for Each Modeled Year Due to Baseline Emissions.... 3-7
Figure 5-1 8 th 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 Improvemen ts/Degradation, 3-Y ear Averag e............................. 5-10ES-1 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Executive Summary

The Salt River Project Agricultural Improvement and Power District (S RP) 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 fa cility became operational in st ages 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 kilome ters from the northern boundary of Grand Canyon National Park (GCNP).

The Clean Air Act’s Regional Haze Rule (RHR) contai ns a requirement for each State or Tribe to address the Best Available Retrofit Technology (BART) require ment when preparing the State’s Regional Haze State Implementation Plan (SIP). Since the Navajo EPA doe s not have an approved Tribal Implementation Plan, the Environmental Protecti on 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 Retr ofit Technology (BART) De terminations; Final Rule” (“BART Guidelines”). The BART Guidelines include pres umptive 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 reta ined ENSR to perform a BART analysis for all three units at NGS. The BART review was performed for two pollutants: ox ides of nitrogen (NO x ) and particulate matter (PM). A BART analysis was not performed for SO 2 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 No vember 2007. After its review, EPA requested a revised analysis in a letter dated July 1, 2008 (provided in Appendix F to this repo rt). The EPA asked SRP to revise the meteorological data used in the CALP UFF modeling, to provide additional results for some Class I areas, to provide additional information on calc ulations and cost estimates, and to address sensitivity issues regarding NO x control modeling cases. This report pr ovides the requested revised BART analysis.

A BART review was previously conducted for the Nava jo 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 im pairment in the Grand Canyon. As a result, NGS installed flue gas desulfurization equipment on all of their uni ts by 1999. With reference to a recent Federal Implementation Plan (FIP) for the Four Corners Powe r 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 SO 2 emission limits in the 1991 FIP for the Nava jo Generating Station provide for greater reasonable progress toward the nati onal visibility goal t han would BART.” See 71 FR at 53633 and 72 FR at 25698 and 25700.

PM emissions are controlled with hot-side electrosta tic 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 PM 10 emissions is not included in this report. Because of limited historical perfo rmance test data, SRP is recommending a short-term PM BART limit of 0.05 lb/MMBtu.

NO x emissions are currently controlled by good co mbustion practices and close coupled overfire air (CCOFA). The baseline peak daily NO x 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 boilersES-2 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 burning bituminous coal. Therefore, NO x controls were considered in this BART analysis for the Navajo Generating Station.

The BART analysis for NO x was conducted in accordance with the BART Guidelines. Cons istent with those guidelines, the five steps for a case-by-case BART analysis were followed.

• Step 1 – Identify all available retrofit control te chnologies, 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 th e remaining technologies based on current pollutant concentrations, flue gas properties and com position, control technology performance, etc.

• Step 4 – Evaluate the annual and incremental co sts of each feasible option using approved EPA methods, as well as the associated energy and non-ai r quality environmental effects of compliance.

• Step 5 – Determine the visibility impairment asso ciated with baseline emissions and the visibility improvements provided by the control technologies considered in the engineering analysis.

The NO x control technologies that are feasible at NGS include: low NO x burners and separated overfire air (LNB/SOFA), selective non-cata lytic reduction (SNCR), and select ive catalytic reduction (SCR).

The results of the visibility modelin g for the candidate BART control options are plotted in Figure ES-1. This figure compares the total visibility impairment (expre ssed 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 BA RT units are continuously at peak operation.

After installation of controls for BART Option 1 (and 1-alternativ e), visibility at the 11 Class I areas shows a measurable reduction. However, when considering the addi tional controls in Options 2 through 4, there is only a relatively modest benefit (if any) when looking at t he full year of modeling results. In addition, we find that during the high visitation months of April – Octo ber, these benefits are eit her reduced substantially or are replaced with a degrad ation of visibility.

Option #1 evaluated the installation of low NO x 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 NG S. This combustion modi fication 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 vi sibility improvement rela tive to baseline emissions with a change of 0.54 deciviews. The hardware capital costs of this retrof it 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 8 th 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 Area8th 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 NO x burners and separated overfire air (LNB/SOFA) with a reduced emission rate of 0.20 lb/M MBtu. This lower emission rate represents a desired “optimal” outcome for LNB/SOFA te chnology at NGS, but it may no t be achievable. Although many tangentially fired units firing western sub-bituminous coal s such as those from the Powder River Basin have achieved rates well below this rate, there is very litt le experience with LNB/SOFA retrofits with western bituminous fuels comparable to the c oal burned at NGS. Lowering the NO x 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 Nati onal Park demonstrated th e greatest visibility improvement relative to baseline with a change of 0.70 dec iviews. The hardware capital costs of this retrofit option were also estimated at $42 m illion 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 (NH 3 ) or urea ((NH 2 ) 2 CO) into the boiler further lowers NO x emissions, but produces the detriment of increasing stack emissions of ammonia salts and exce ss ammonia. These additional fine particulate and precursor emissions negatively affected vi sibility at all areas relative to Op tion 1a, especially at Capitol Reef and Grand Canyon National Parks. The increased amm onia ambient concentrations were ignored in the modeling at all parks except Capitol Reef and Grand Cany on due to the lower values at the more distant parks. Therefore, for most parks, the reported modele d 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 ta ken 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 catalyti c 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 no t expected that emission char acteristics 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 s hown 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 visibi lity 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 decivie ws) due to its proximity to NGS and the increased H 2 SO 4 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 improv ement of 0.22 deciviews relative to that for Option #1a. Canyonlands National Park demonstrated the greates t visibility improvement relative to Option 1a with a change of 0.42 deciviews . Similar to Option 3, m odeled changes at the Grand Canyon showed degradation in visibility relative to Option 1a (of 0.09 deciv iews) due to its proximity to NGS and the increased H 2 SO 4 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 wo uld be required to determine if the technology would be applied with or without LNB/SOFA.

The associated annual costs, derived from capital ex penditures and annual O&M costs, are shown in Table ES-1. The modeled visibility improvements and the calc ulated cost in terms of dollars per deciview are provided in Table ES-2. The modeled visibility improv ements/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 rela tively little visi bility benefit, while a backward slope (toward higher deciviews) indicates that the BART cont rol option could actually degrade visibility. The tabulated values in Table ES-2 and the graph in Figur e 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 reje cted due to the relatively small or nonexistent incremental improvement in visibility over that re sulting from use of LNB/SOFA; increased emissions of ammonia, ammonia salts, and sulfuric acid aerosols, which negatively affe ct 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 a ssociated with the shipping, storage, and injection of anhydrous ammonia. A summary of the recommended BA RT 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 Cost s 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) $438,000,000 b $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 Improvemen ts/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 sc enario 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 Im provements/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

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 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 4ES-7 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table ES-3 Best Available Retrofit Technology – Low NO x Burners / Separated Overfire Air

Estimated NO x Emission Rate 0.24 lbs/MMBtu, with possible reduction to 0.20 lb/MMBtu with experience and optimization of operations

NO x Emission Limit Reduction from Baseline At least 48% at 0.24 lb/MMBtu

Estimated NO x 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 CO 2 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-8January 2009BART Analysis for Navajo Generating Station05830-012-300Table ES-4 Summary of BART Analysis for NOxStep 1Step 2Step 3Step 4aStep 4bStep 5Identify ControlTechnologiesFeasibleControlTechnology?Evaluate ControlEffectiveness forTechnicallyFeasible ControlTechnologiesCalculateCostEffectivenessfor ControlTechnologies(relative tobaseline)DetermineNon-Air QualityEnvironmental andEnergy ImpactsEvaluateVisibilityChanges ofControls vs.baselineIdentify BARTControl ResultsControlOption 1Low NOxburners,separated overfire airYes48% NOxreductionfrom baselineAnnualizedcost = $4.9MMIncrease in fuelconsumption, LOI of flyash, corrosion,increase in COaverage visibilityimprovement =0.37 delta-dvAchieves betterthanpresumptive NOxlimit with modestvisibility benefitAlternativeto ControlOption 1Low NOxburners,separated overfire airYes57% NOxreductionfrom coal-firedbaseline (9%reduction relative toOption 1)Annualizedcost = $4.9MMIncrease in fuelconsumption, LOI of flyash, corrosion,increase in COaverage visibilityimprovement =0.47 delta-dv (0.10reduction relativeto Option 1)Achieves betterthanpresumptive NOxlimit withadditionalvisibility benefitControlOption 2Low NOxburners,separated overfire air,and SNCRYes57% NOxreductionfrom coal-firedbaseline (noadditional reductionfrom Option 1a)Annualizedcost = $26.4MMExcess NH3emissions;1% plant energyconsumption; NH3riskto workers and public,air emissions of NH3transportaverage visibilityimprovement =0.39 delta-dv(degradation fromOption 1a)No additionalvisibility benefitat high costControlOption 3Low NOxburners,separated overfire air,and SCR (Units 1,3)Yes71% NOxreductionfrom coal-firedbaseline (14%reduction relative toOption 1a)Annualizedcost = $59.5MMExcess sulfateemissions; 1% plantenergy consumption;NH3risk to workers andpublic, air emissions ofNH3transportaverage visibilityimprovement =0.57 delta-dv (0.10reduction relativeto Option 1a)Marginaladditionalvisibility benefitat very high costControlOption 4Low NOxburners,separated overfire air,and SCR (all units)Yes83% NOxreductionfrom coal-firedbaseline (26%reduction relative toOption 1a)Annualizedcost = $94.8MMExcess sulfateemissions; 1% plantenergy consumption;NH3risk to workers andpublic, air emissions ofNH3transportaverage visibilityimprovement =0.70 delta-dv (0.22reduction relativeto Option 1a)Marginaladditionalvisibility benefitat very high cost1-1 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 fac ility became operational in stages between 1974 and 1976 and consists of three coal-fired units with a combin ed power generating capacity of 2,250 MW. Each unit has a single stack with a height of 236 meters. The fa cility is approximately 20 kilo meters from the northern boundary of Grand Canyon National Park (GCNP), wh ich 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 Inte rior (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 “Gui delines for Determining Best Available Retrofit Technology for Coal-Fired Power Plants and Other Existi ng 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 fac ility 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 fulf illed the rule’s requirement with the in stallation of sulfur dioxide controls on the final unit in 1999.



### 1.3 BART Requirements

Federal regulations under 40 CFR 51, Appendix Y, provid e guidance and regulatory authority for conducting a visibility impairment analysi s for designated eligible sources. The program requires the application of BART to those existing eligible sources that are believed to c ause or contribute to visibi lity impairment at designated Class I areas in order to help meet the targets for visib ility improvement in those ar eas. 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 05830-012-300 2. The sum of the potential emissions of any single vi sibility-impairing pollutant from the affected units is greater than 250 tons/year.

3. NGS is a “fossil-fuel fired st eam 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 Cla ss I area are subject to BART. The contribution threshold for visibility impairment is a 0.5 deciview change. ENSR has conduc ted BART exemption modeling of Units 1-3, and the results indicate that these units are subject to BAR T review because the predicted visibility changes with baseline emissions exceed 0.5 delta decivie ws in at least one Class I area.

A BART report was submitted to EPA Region 9 in Novem ber 2007. After its review, EPA requested a revised analysis in a letter dated July 1, 2008 (provided in App endix 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 calcul ations and cost estimates, and to address sensitivity issues regarding NO x control modeling cases. This report pr ovides the requested re vised BART analysis.



### 1.4 Sulfur Dioxide Emission Control

SO 2 emissions at NGS are controlled by wet limestone forced-oxidation flue gas desulfurization (FGD) scrubbers, in response to the previous Reasonably At tributable BART rule. In a recent Federal Implementation Plan (FIP) for the Four Corners Powe r 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 SO 2 on the Navajo Reservation that are potentially subject to the BART requi rements--Navajo Generating Station and FCPP. See 71 FR at 53633 and 72 FR at 25698 and 25700. EPA determined previously that the SO 2 emission limits in the 1991 FIP for the Navajo Gener ating Station provide for greater reasonable progress toward the national visibili ty goal than would BART.”

Based on stack test data, the SO 2 removal efficiencies are on the order of 95%. The existing SO 2 emission limit for Navajo is 0.10 lbs/MMBtu on a 3 65-day boiler operating day average. This SO 2 emission limit is more restrictive than the presumptive BAR T limit for tangentially fired boile rs burning bituminous coal of 0.15 lb/MMBtu. Consequently, no further analysis of BART controls for SO 2 is presented in this report.



### 1.5 Particulate Matter Emission Control

The use of hot-side ESPs and wet scrubbers effectively limi ts the PM emissions from Navajo Units 1 through 3 at the Navajo Generating Station. During historic st ack tests at the plant, filterable PM averages about 0.03 lb/MMBtu, an emission rate which was used in the BA RT 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 cons idered 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 05830-012-300 

### 1.6 Nitrogen Oxides Emission Control

NO x emissions at NGS are controlled by good combustion practices and close coupled overfire air (CCOFA). Baseline peak daily NO x 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/M MBtu for dry-bottom, tangentially-fir ed boilers burning bituminous coal. Therefore, this BART analysis cons iders BART control options for NO x .
The BART analysis for NO x was conducted in accordance with th e procedures contained in the BART Guidelines. Consistent with the BART Guidelines, t he 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, operat ing problems and reliability, and adverse side effects on the rest of the facility.

• Step 3 – Evaluate the control effectiveness of th e remaining technologies based on current pollutant concentrations, flue gas properties and compos ition, control technology performance, and other factors.

• Step 4 – Evaluate the annual and incremental co sts of each feasible option in accordance with approved EPA methods, as well as the associated energy and non-air qualit y environmental impacts of compliance.

• Step 5 – Determine the visibility impairment asso ciated 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 NO x emissions from Units 1 through 3 at the Navajo Generating Station.



### 1.7 Report Outline

Section 2 of this report discusses the general CALPU FF modeling approach. It refers to more detailed discussions in appendices attached to this report for me teorological 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 pr ovided 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 NO x 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 05830-012-300 

## 2.0 CALPUFF Modeling Procedures

For the CALPUFF modeling, SRP followed the Wester n Regional Air Partnership (WRAP) common BART modeling protocol with the exception of the model vers ion and a few refinements to CALMET settings. These differences are discussed in Section 2.2 and Appendix A.



### 2.1 CALMET Processing

The WRAP has developed six 4-km CALMET meteorol ogical 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/bar t/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) file s 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 us ed 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 us ed by WRAP to generate the 4-km sub-regional meteorological datasets. Section 2 of the WRAP pr otocol discusses MM5 data extraction. The BART CALPUFF modeling for NGS was done using the Arizona 4-km CALMET database with application-specific modifications (described in Appendix A) and adjustm ents requested by EPA Region 9 (described in Appendix F).



### 2.2 CALPUFF Modeling Procedures

SRP and ENSR used the EPA-approved version of CA LPUFF (Version 5.8, Leve l 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 CA LPUFF 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 ba sis. 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 do cumentation 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 Ariz ona 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 computatio nal 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 05830-012-300 WRAP has developed hourly ozone measurement f iles for three years (2001-2003), available at http://pah.cert.ucr.edu/aq m/308/bart/calpuff/ozone_dat/ . Data collection and processing are described in Section 3.1.2.7 of the WRAP protocol. These ozone 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 sensit ivity analysis is also presented in Appendix B.



### 2.3 Natural Conditions and Mont hly 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 natur al background light extinctions shown in Table 2-1, modified as noted below with site -specific considerations, and co rresponding 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 Re trofit Technology (BART) De terminations”, 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 necessa ry to convert the deciviews to extinction using the equation:

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

For example, for Arches, 4.43 deciv iews 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. Theref ore, 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 μ g/m 3 in CALPOST, since the extinction efficiency of soil (PM-fine) is 1.0 and there is no f(RH) com ponent. The concentration entries for all other particle constituents would be set to zero, and the fine soil concent ration would be kept the same for each month of the
year.

The monthly values for f(RH) that CALPOST needs we re 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 05830-012-300 Figure 2-1 NGS CALPUFF Computational Grid in Relation to WRAP Arizona Domain2-4 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

### 2.4 Light Extinction and Ha ze 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 exti nction. 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 concentra tions. Using the notation of CALPOST, the formula is the following:

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

The concentrations, in square brackets, are in μ g/m 3 and b ext is in units of Mm -1 . The Rayleigh scattering term (b Ray ) has a default value of 10 Mm -1 , as recommended in EPA guidance for 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 usi ng the hygroscopic components of the source-caused concentrations, due to ammonium sulfate and nitrate, and monthly Class I area-specific f(RH) values. The contribution to the total source-caus ed extinction from ammonium sulfat e and nitrate is then added to the other, non-hygroscopic components of the particulate concentration (from coarse and fine soil, secondary organic aerosols, and elemental carbon) to yiel d the total hourly source-caused extinction.3-1 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## 3.0 BART Applicability Analysis

3.1 BART-Eligibilit y 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 vi sibility-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 MM Btu/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 greate r than 750 MW, it is subj ect 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 vi sibility 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 SO 2 and NO x baseline emissions were determined by ENSR using CEMS data compiled in baseline calend ar 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 SO 2 and NO x 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 y ears 2001-2003. The determination of the highest daily emissions did not consider emissions associated with malfunctions, start-up, and s hutdown, consistent with the WRAP BART protocol. Filterable PM baseline emi ssions 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 cons istent 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 PM 10 and 29% of the PM emissions are fine filterable PM 10 emissions (less than 2.5 microns in size).

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine PM 10 based on the best estimate for electric utility coal combustion in Table 6 of “Catal og of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, Willia m Battye and Kathy Boyer, EPA Contract No. 68-D98-046, January 2002.3-2 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 • Condensable inorganic PM 10 emissions, assumed to consist of H 2 SO 4 , are based on “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008, and R. Hardman, et al. 1998. For coal-fired boilers, H 2 SO 4 emissions are determined by the following relationship:
E = (Q)(98.06/64.04)(F1)(F2)

where: E is the H 2 SO 2 emission rate (lb/hr), Q is the baseline SO 2 emission rate (lb/hr), F1 is the fuel factor (0.00111 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 PM 10 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 SO 4 emission rate is 96/98 times the H 2 SO 4 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.3-3January 2009BART Analysis for Navajo Generating Station05830-012-300Table 3-1 Navajo Generating Station Baseline Emissions3-4 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 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 Park3-5 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure 3-1 Class I Areas within 300 km of the Navajo Generating Station3-6 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

### 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 y ears of CALMET meteorological data (2001-2003).

For each Class I area and year, Table 3-3 lists the 8 th highest delta-deciview. Figure 3-2 shows the 8 th 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 NG S and local meteorological conditions.

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

The results of the baseline emissions analysis indicate that the 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 s ubject 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 visibili ty 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 Emissions3-7 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure 3-2 8 th 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 3.5Grand Canyon NPCapitol Reef NPBryce Canyon NPZion NPCanyonlands NPSycamore Canyon WPetrified Forest NPArches NPMesa Verde NPMazatzal WPine Mountain W

Class I Area8th Highest deciview Met Year 2001 Met Year 2002 Met Year 2003

At EPA’s request, the modeling results graphically s hown 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 th at the complete visibility results are appropriate to present as well to view the modeled changes relative to the total vi sibility effects that are actually seen, so they are included in Appendix E for completeness.4-1 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## 4.0 BART Engineering Analysis for NO x 

## Emissions

Nitrogen oxides (NO x ) formed during the combustion of coal are gen erally classified as either thermal NO x or fuel-bound NO x . Thermal NO x is formed when elemental nitrogen in the combustion air is oxidized at the high temperatures in the primary combustion zone, yi elding nitrogen oxide (NO) and nitrogen dioxide (NO 2 ). The rate of formation of thermal NO x is a function of residence time and free oxygen, and increases exponentially with peak flame temperatures. Thermal NO x from coal combustion can be ef fectively controlled by techniques that limit available oxygen or r educe peak flame temperatures in the primary combustion zone. Fuel-bound NO x is formed by the oxidation of c hemically bound nitrogen in the fuel. The rate of formation of fuel-bound NO x 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 NO x emissions from coal fired power plants, (2) the feasibility of applying such c ontrols to NGS, (3) the expected effect iveness of such controls if used at NGS, and (4) the effects of impl ementing such controls at NGS.



### 4.1 Identification of Alternative NO x 

### Controls

The alternative NO x control technologies available for limiting NO x 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 NO x control technologies are evaluated below in terms of their possible application to Units 1 through 3.



### 4.1.1 Low-NO x 

### Burners and Separated Overfire Air (LNB/SOFA)
LNB/SOFA systems in tangentially fi red boilers are designed to control fuel and air mixing to reduce peak flame temperatures, resulting in less NO x formation. Combustion, reduction, and burnout are achieved in three stages within a conventional low NO xburner. In the initial stage, combustion occurs in a fuel-rich, oxygendeficient zone where the NO x is formed. A reducing atmosphere follo ws where hydrocarbons are formed that react with the already formed NO x . In the third stage, internal air staging completes the combustion, but may result in additional NO xformation. This, however, can be minimized by completing the combustion in an airlean environment. Combustion air is separated into prima ry and secondary flow sections to achieve complete burnout and to encourage the formation of nitrogen, rather than NO x . 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 NO x . Secondary air representing 10-30% of t he 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 fl ame volume. Hence, the relatively low-temperature secondary stage limits th e production of thermal NO x . The location of the injection ports and mixing of overfire air are critical to maintain efficient combustion. Retrof itting 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 NO x is influenced by a number of site specific factors including fuel characteristics (e.g., nitrogen cont ent, ratio of fixed to volatile carbon, heat content), furnace geometry, structural factor s that may limit options for lo cations of SOFA ports, etc.



### 4.1.2 Flue Gas Recirculation
Flue gas recirculation for NO x 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 temp erature and availability of oxygen, thereby reducing thermal NO x formation. When flue gas recirculation into the burner is used in low NO x burners, the flue gas is usually recirculated subject to the operational cons traints of flame stability and impingement. Retrofitting an existing coal-fired unit with flue gas recirculation invo lves installation of a system to extract the flue gas4-2 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 from the boiler unit, additional ductwork, fans, and a fl y ash collecting device. The fly ash collector is necessary in order to clean the flue gas of particulate ma tter prior to recirculation. Heat distribution in the furnace may be affected due to the increase in throughpu t. Excessive flue gas recirculation can also result in flame instability problems and increased steam temperat ures. Flue gas recirculation alone in coal-fired boilers achieves a NO x reduction efficiency of less than 20%. This is because the ratio of thermal NO x to total NO x 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 NO x . An amine-based compound, such as ammonia, NH 3 , or urea, (NH 2 ) 2 CO, is used as the NO x reducing agent in SNCR processes. When ammonia or ur ea is injected into the flue gas st ream, it selectively reduces the NO x into molecular nitrogen, N 2 , and water, H 2 O. At stoichiometric conditi ons, when the adequate residence time is reached, the overall reactions th at occur may be characterized by:

Ammonia

4NO + 4NH 3 + 0 2 → 4N 2 + 6H 2 0

2NO 2 + 4NH 3 + 0 2 → 3N 2 + 6H 2 0

Urea

2(NH 2 ) 2 CO + 4NO + O 2 → 4N 2 + 2CO 2 + 4H 2 O

In an SNCR system, NO x 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 NO x . Consequently, the SNCR process operates at higher temperatures than the S CR process. Critical to the successful reduction of NO x 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, resi dence time at operating temper atures, 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 ox idation becomes predominant. Nitrogen monoxide is formed as a product of this reaction of ammonia oxidatio n. As a result, when the flue gas temperature at reagent injection locations is higher than the appropria te temperature window, the SNCR process results in NO x formation, rather than NO x reduction. At temperat ures lower than the required temperature window, the NO x 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 a mmonia injection rate than is stoichiometrically required to achieve higher NO x control efficiencies. The various SN CR vendors typically will not provide a guarantee against ammonia slip of less t han 5 ppm for systems designed for high NO x performance levels. This excess ammonia may react with SO 3 and water vapor to form amm onium bisulfate and ammonium sulfate. Although no SO 2 is oxidized by the SNCR system, naturally occurring SO 3 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 c ool and can lead to increased emissions of both PM 10 and PM 2.5 . Ammonia slip from SNCR systems occurs either from injection at temperatures too low for effective reaction with NO x or from over-injection of reagent, leading to une ven 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 because4-3 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 NO x distribution varies within the cross section. An inje ction system that has too few injection control points or fails to inject a uniform amount of ammonia across the entir e section of the boiler will almost certainly lead to a poor distribution ratio and high ammonia slip. Distributi on of the reagent can be especially difficult in larger coal-fired boilers because of the long injection distance r equired 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 M W), SNCR has been demonstrated to achieve NO x reductions ranging from 25% to 50% with acceptable levels of ammonia slip. This variation in NO x reduction depends on site-specific considerations and the amount of am monia slip considered acceptable. In practical applications, non-uniformities in velocity and temper ature at the reagent injection location can pose operational difficulties because of the inherent sensitiv ity of the process to thes e 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. Fo r 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 wi thin the convective passes. Demonstrations at the Port Jefferson, Morro Bay, and Merrimac plants have show n 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 mode ling program to evaluate the performance of SNCR on Southern Company Service’s Wans ley Unit 1 located in Roopville, G eorgia. This 880-MW unit is a tangentially-fired boiler equipped with a low-NO X burner and separated overfire air. The modeling results demonstrated that SNCR has the potential to reduce NO x emissions by only 22% with an acceptable ammonia slip of 6 ppm. The firing characteristics of the boiler make achieving higher levels of NO x reduction impractical. The most influential factor is the separated overfire air system, which elevates upper furnace temperatures by causing the combustion pr ocess to extend beyond the furnace nose and into the convection section. 3

EPA Region 9’s letter requesting a re vised BART analysis (see Appendix F) mentioned that the calculations and assumptions for H 2 SO 4 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 SO 2 (for purposes of computing H 2 SO 4 emissions) is assumed (EPRI, 2008, page 4-5). The average ammonia slip (that amount of ammonium that does not react to remove NO x ) 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 H 2 SO 4 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 H 2 SO 4 , 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 H 2 SO 4 on a mole basis. It is assumed that for the SNCR case, all of the available H 2 SO 4 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 SO 2 and NO x discharged from the boiler, as noted in tables referenc ed below. For modeling purposes, the effective direct sulfate emissions are the same (whether in the form of H 2 SO 4 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 NO x Control, May 1993.
2 Lin, Chin-I, " Full Scale Tests of SNCR Technol ogy on a Gas-Fired Boiler," EPRI Workshop on NO x 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 NO x Emissions, Durham, NC, March 1998.4-4 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 The ammonium sulfate that is formed due to the S NCR 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 eit her ammonium bisulfate or H 2 SO 4 ). Controls for removal of ammonium sulfate by the wet scrubber and air pre-heater are assumed to be the same as those specified for H 2 SO 4 in EPRI (2008) – 10% for the air pre-heater and 47% for the wet scrubber.

For the requested sensitivity analysis involving excess am monia emissions, we have si mplified the analysis to either assume the values associated with 5 ppm a mmonia slip (less that mass converted to ammonium sulfate) or zero excess ammonia emissions as an implausible extrem e 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 t hat involves post-combustion removal of NO x from flue gas utilizing a catalytic reactor. In the SCR process, ammonia inject ed into the flue gas reacts with nitrogen oxides and oxygen to form nitrogen and water vapor. The SCR process converts NO x to nitrogen and water by the following general reactions:

4NO + 4NH 3 + O 2 → 4N 2 + 6H 2 O

2NO 2 + 4NH 3 + O 2 → 3N 2 + 6H 2 O

The reactions take place on the surface of a catalyst. T he function of the catalyst is to effectively lower the activation energy of the NO x decomposition reaction to about 375° to 750°F, depending on the specific catalyst and other contaminants in the flue gas. The factors af fecting 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, incl uding the SCR reactor, ammonia injection system, and ammonia storage and delivery system. The SCR reac tor 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 desi gned to provide optimal mixing of ammonia with flue gas. The ammonia-treated flue gas then flows through t he catalyst bed and exits to the air pre-heater. The SCR system for a pulverized coal boile r typically uses a fixed bed catalyst in a vertical down-flow, multi-stage reactor.

Reduction catalysts are divided into two groups: base meta l, primarily vanadium, platin um, or titanium (lower temperature); and zeolite (higher tem perature). Both groups exhibit advantages and disadvantages in terms of operating temperature, ammonia-NO x ratio, and optimum oxygen c oncentration. The optimum operating temperature for a vanadium-titanium cata lyst 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 NO x , thereby actually increasing NO x emissions.

To achieve high NO x control efficiencies, the SCR vendors sugges t a higher ammonia injection rate than is stoichiometrically required to react all of the NO xin 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 NO x performance levels. This excess ammonia may react with SO 3 and water vapor to form ammonium bisulfate (NH 4 )HSO 4 and ammonium sulfate (NH 4 ) 2 SO 4 . Higher levels of ammonia and SO 2 result in higher levels of ammonium bisulfate and ammonia sulfate. These ammonium salts may condense as the flue gases c ool and can lead to increased emissions of both PM 10 and4-5 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 PM 2.5 . Furthermore, the catalyst promotes the partial oxidation of SO 2 to SO 3 , which in turn combines with water, increasing the formation of these ammonia salts and potential emissions of PM 10 and PM 2.5

.
Some SCR installations have experienced significant ai r pre-heater plugging and corrosion resulting from the deposition of ammonium bisulfate. The plug ging 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 primar y factors for controlling the formation and deposition of ammonium bisulfate are the level of ammonia, the level of SO 3 , the air pre-heater surface temperature profile, the air pre-heater surface material, and the air pre-heater physical configur ation. 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 SO 3 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 deacti vation and chemical poisoning. Phys ical deactivation generally results from either prolonged exposure to excessive temperatur es or masking of the cataly st 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 limit ed lifetime for high performance catalyst systems. Fly ash pl ugging generally results from excessive fly ash carryover to the ca talyst 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 wi ll combine with the available pound moles of H 2 SO 4 from coal combustion to form ammonium sulfate or a mmonium bisulfate. As not ed in EPRI (2008, page 3-4), when ammonia is present in an amount less than the mole content of the H 2 SO 4 , the reaction product will almost always be ammonium bisulfate. That is alwa ys the case for SCR controls, for which the available ammonia is much lower than the available H 2 SO 4 on a mole basis. It is assumed that for the SCR case, all of the available ammonia is converted to ammonium bisulf ate 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 SO 2 and NO x 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 th e SCR control equipment (plus the un-reacted H 2 SO 4 ) is emitted in the CALPUFF model as primary sulfate, as noted for t he SNCR case. Controls for removal of newly created ammonium bisulfate and remaining H 2 SO 4 by the wet scrubber and air pre-heater are assumed to be the same as those specified for H 2 SO 4 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 NO x 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 residen ce time for the air/fuel mixture. The water-cooled ECOTUBEs are automatically retracted from the boile r on a regular basis and cleaned to remove layers of soot and other depositions.



### 4.1.6 ROFATM/ROTAMIXTM
Mobotec provides a NO x reduction system that combines OFA and SNCR technologies into an integrated system. The system uses a modified OFA system wi th 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 RO FA nozzles with the reagent injection results in4-6 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 improved mixing and a more homogeneous temperature profile in the boiler. This NO x reduction system has primarily been applied to smaller units, with the vendor reporting NO x reductions of up to 75%.



### 4.2 Technical Feasibilit y of Alternative NO x 

### Controls

Of the technologies discussed above, the following ar e 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 NO x 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 NO x 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 NO x 

### Controls

The alternative NO x control technologies, LNB/SOFA, SCR, and SNCR, have been successfully applied to new utility coal-fired boilers, as well as retrofitted to ex isting utility coal-fired boilers. The effectiveness of these technologies in reducing NO x emissions is dependent primarily on the inlet NO x concentrations, residence time, and operating temperatures. Staged combustion techniques have been demonstrated to achieve up to 50% reduction in uncontrolled NO x emissions from coal-fired utility bo ilers. SNCR has been demonstrated to achieve NO x control efficiencies ranging from 25% to 50% with inlet NO x concentrations of 300 to 400 ppmvd. If staged combustion is used to reduce inlet NO x concentrations to less than 150 ppmvd, SNCR is capable of achieving NO x control efficiencies of only 10% to 25%. SCR can achieve NO x control efficiencies as high as 90% with inlet NO x concentrations in the range of 300 to 400 ppmvd. If inlet NO x concentrations are less than 150 ppmvd, SCR can achieve NO x control efficiencies of only 50% to 70%.

Based on information provided by equipment vendors, it is estimated that LN B/SOFA will reduce NO x emissions to an emission level of approximately 0.24 lb/MMBtu. Due to the lower inlet NO x concentrations, it is estimated that the addition of SNCR will reduce NO x emissions by another 15%, which corresponds to a NO x emission level of approximately 0.20 lb /MMBtu. SCR is estimated to reduce NO x emissions to approximately 0.080 lb/MMBtu. Table 3-1 summarizes the annual NO x 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 NO x emission rate of 0.20 lb/MMBtu. This emission rate represents an opti mal 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 NO x rates.4-7 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table 4-1 Annual NO x 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 & CCO FA 0.49 0.45 0.46

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

1 Alternative LNB/SOFA (U nits 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 NO x control technologies in r educing 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 NO x 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 NO x 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 NO x emissions from this unit to 0.24 lb/MMBtu, and the retrofit of LNB/SOFA and SCR to Units 1 and 3 to control NO x emissions from these two units to 0.08 lb/MMBtu.

• Option 4 . This option involves the retrofit of LNB/SO FA and SCR to Units 1 through 3 to control NO x emissions from all three units to 0.08 lb/MMBtu.

The alternative control technologi es will not only affect NO x emission levels from Units 1 through 3, but will also affect the emissions and speciation of PM 10 . The PM 10 emissions and speciation were determined using the following approach:

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

• For coal-fired boilers, elemental carbon is expected to be 3.7% of fine PM 10 based on the best estimate for electric utility coal combustion in Table 6 of “Catal og of Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, Willia m Battye and Kathy Boyer, EPA Contract No. 68-D98-046, January 2002.

• Condensable inorganic PM 10 emissions, assumed to consist of H 2 SO 4 , are based on “Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, March 2008, and R. Hardman, et al. 1998. For coal -fired boilers equipped with SCR, H 2 SO 4 emissions are determined by the following relationship:
E = (Q)(98.06/64.04)(F1+S2)(F2)4-8 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 where: E is the H 2 SO 2 emission rate (lb/hr), Q is the baseline SO 2 emission rate (lb/hr), F1 is the fuel factor (0.00111 for western bituminous coal), S2 is the SCR catalyst SO 2 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 H 2 SO 4 in the control equipment will deplete the ammonia and H 2 SO 4 as ammonium sulfate or bisulfate is formed. The total mass of ammonium sulfate (or bisulfate) and remaining H 2 SO 4 are converted to equivalent lb/hr of primary sulfates, subjected to controls by the downstream contro l 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 PM 10 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 NO x , SO 2 , and PM 10 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 NO x emission rates by 16.7% from those listed in Table 4-4.



### 4.4 Analysis of Alternative NO x 

### Controls

The alternative control technologies available to control NO x emissions from Units 1 through 3 are LNB/SOFA, SCR, and SNCR. This section documents the economic, non-air environment al, 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 co sts 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 Associ ated 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 $17,391,000 c $26,428,000

3 LNB/SOFA (Unit 2); LNB/SOFA&SCR (Units1&3) $438,000,000 b $50,747,000 $8,778,000 $59,525,000

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

(a) Fixed capital costs based on a CRF of 0.1159, assuming an in terest 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 conseq uences 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 in cident, 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 deliver ed to the site via tanker trucks. To achieve the projected NO x 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 ca pacity 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 NO x , VOCs, CO, CO 2 and PM 10 in the region.

Theoretically, one mole of ammonia will react with one mole of NO x , forming elemental nitrogen and water in both SCR and SNCR. In reality, not all the inject ed reagent will react due to imperfect mixing, uneven temperature distribution, and insufficient residence time . These physical limitati ons may be compensated for by injecting a larger amount of ammonia than stoichio metrically required and essentially achieving lower NO x emissions at the expense of ammonia slip. Typically, the average ammonia slip associated with SCR is approximately 0.75 ppm at 6% O 2 , while that associated with SNCR is approximately 5 ppm at 6% O 2 . This excess ammonia may react with SO 3 or H 2 SO 4 in the flue to form ammonium bisulfate ((NH 4 )HSO 4 ) and ammonium sulfate ((NH 4 ) 2 SO 4 ). These ammonium salts may condense as the flue gases cool and can lead to increased emissions of both PM 10 and PM 2.5 . In SCR systems, the catalyst promotes the partial oxidation of SO 2 to SO 3 , which in turn increases the formation of a mmonium bisulfate and ammonium sulfate. The enhanced formation of these ammonia salts further increases the potential emissions of PM 10 and PM 2.5

.
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 w ill be a significant quantity of soluble salts associated with the fly as h. These salts are expected to be NH 4 HSO 4 and (NH 4 ) 2 SO 4 . 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 produc t quality (e.g., when used for concrete). The level of concern may be regional in nature (i.e., less concer n 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 a mmonia slip. Ash characteristics such as pH, alkali mineral content, and volatile sulfur and chlorine cont ent help to determine whether or not ammonia will be adsorbed readily by the fly ash. Elevated pH will ca use ammonia release to the air and resulting odor. In some applications, properly designed SNCR systems c an 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 CO 2 emissions/kwh due to reduced boiler efficiency

• Potential for poor combustion and increased CO emissions

• Potential for increased corrosio n and more frequent replacement of furnace waterwall tubes

SNCR • Addition of ammonia or urea stor age 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 NO x , VOC, CO, CO 2 , and PM 10 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 SO 3 or H 2 SO 4 in the flue to form ammonium bisulfate (NH 4 )HSO 4 and ammonium sulfate (NH 4 ) 2 SO 4

.

• 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 a mmonia and/or nitrogen-containing compounds.

SCR • Addition of ammonia handling sy stems. Anhydrous ammonia and aqueous ammonia above 20% are considered dangerous to human health, and accidental releases are repo rtable 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 NO x , VOC, CO, CO 2 , and PM 10 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 S CR 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 S NCR (approximately 1% of the total power generation of NGS) for each hour of operation. The increased e missions of pollutants required to maintain the net electrical output have not been incorporated into the visi bility modeling, but the re viewer should be aware that any reported visibility improvements due to SCR operati on do not consider potential negative visibility effects of the increase in air emissions asso ciated 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.4-12January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-4 Navajo Generating Station SOFA/LNB Emission Controls (Option 1)4-13January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-5 Navajo Generating Station SOFA/LNB Emission Controls (Alternative Option 1)4-14January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-6 Navajo GeneratingStation SOFA/LNB/SNCR Emission Controls (Option 2)fine total fine soil ECMMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtulb/MMBtu(e)lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hrNavajo 1750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,SNCR, hot side ESP,wet FGD211,074 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) 2.45 (g) 39.45 (h) 4.27 (i) 35.18(j)Navajo 2750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,SNCR, hot side ESP,wet FGD226,163 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) 2.12 (g) 42.27 (h) 4.58 (i) 37.69(j)Navajo 3750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,SNCR, hot side ESP,wet FGD219,778 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) 3.05 (g) 41.08 (h) 4.45 (i) 36.63(j)NH3 5.00 ppmvd at 6% O20.00302 lb/MMBtuunit 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 remove ammonium sulfate any more efficiently than itwould 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 DescriptionMaximum Heat Input(a)MaximumSulfurContent(b)Maximum FilterablePM EmissionsFilterable PM10Condensable PM10total coarseFinetotal H2SO4(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 (based on EPRI). Coal sulfur content is 0.593%and the heating value is 10,496 Btu/lb. H2SO4 control efficiencyis 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%/100 x 1/10,496 x 1,000,000 x Heat Input x98.06/32.07 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 estimatefor electric utility coal combustion in Table 6 of “Catalogof Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-D-98-046, January 2002.(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.organic(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 because emissions reflected startup, shutdownor malfunction.4-15January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-6 Navajo GeneratingStation SOFA/LNB/SNCR EmissionControls (Option 2) cont.4-16January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-7 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 3)fine total fine soil ECMMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtulb/MMBtu(e)lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hrNavajo 1750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCRwet FGD211,074 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) 2.45 (g) 100.52 (h) 65.35 (i) 35.18(j)Navajo 2750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA, hotside ESP, wet FGD226,163 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) 2.12 (g) 42.27 (h) 4.58 (i) 37.69(j)Navajo 3750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD219,778 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) 3.05 (g) 104.67 (h) 68.04 (i) 36.63(j)NH3 0.75 ppmvd at 6% O20.00045 lb/MMBtuunit 1 3.99 lb/hrunit 2 0.00 lb/hrunit 3 4.15 lb/hrFilterable PM10Condensable PM10FineMaximum FilterablePM EmissionsDescriptionUnit(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 estimatefor electric utility coal combustion in Table 6 of “Catalogof Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-D-98-046, January 2002.(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 because emissions reflected startup, shutdownor 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.FacilityMaximum SO2 Emissions(c)Maximum NOx Emissions(d)Maximum Heat Input(a)MaximumSulfurContent(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 (based on EPRI). Coal sulfur content is 0.593%and the heating value is 10,496 Btu/lb. H2SO4 control efficiencyis 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: 0.00111 x0.593%/100 x 1/10,496 x 1,000,000 x HeatInput 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.organiccoarsetotal H2SO4total4-17January 2009BART Analysis for Navajo Generating Station05830-012-300Table 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 lb/hr lb/hrNavajo 1750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCRwet FGD154.48 3.99 (k) 0.234 1.575 -1.34 (l) 0.00 131.51 22.97 65.35 64.01 253.73Navajo 2750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA, hotside ESP, wet FGD4.58 0.00 (k) 0.000 0.047 -0.05 (l) 0.00 4.58 0.00 4.58 4.48 174.86Navajo 3750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD160.85 4.15 (k) 0.244 1.640 -1.40 (l) 0.00 136.93 23.92 68.04 66.65 294.87TotalH2SO4before NH3interactionDescriptionUnitFacilityNH3 SlipTotal PM10NH3 H2SO4 Excess NH3 (Slip) H2SO4(NH4)2SO4/NH4HSO4(as H2SO4)TotalEffectiveH2SO4 forModelingTotalEffectiveSO4 forModeling4-18January 2009BART Analysis for Navajo Generating Station05830-012-300Table 4-8 Navajo Generating Station SOFA/LNB/SCR Emission Controls (Option 4)fine total fine soil ECMMBtu/day MMBtu/hr % ton/day lb/hr lb/MMBtu % reduction ton/day lb/hr lb/MMBtulb/MMBtu(e)lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hrNavajo 1750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD211,074 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) 2.45 (g) 100.52 (h) 65.35 (i) 35.18(j)Navajo 2750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD226,163 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) 2.12 (g) 107.71 (h) 70.02 (i) 37.69(j)Navajo 3750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD219,778 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) 3.05 (g) 104.67 (h) 68.04 (i) 36.63(j)NH3 0.75 ppmvd at 6% O20.00045 lb/MMBtuunit 1 3.99 lb/hrunit 2 4.27 lb/hrunit 3 4.15 lb/hrFacility Unit DescriptionMaximum 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 coarseFinetotalMaximumSulfurContent(b)Maximum SO2 Emissions(c)Maximum FilterablePM EmissionsFilterable 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 because emissions reflected startup, shutdownor 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 estimatefor electric utility coal combustion in Table 6 of “Catalogof Global Emissions Inventories and Emission Inventory Tools for Black Carbon”, William Battye and Kathy Boyer, EPA Contract No. 68-D-98-046, January 2002.(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 (based on EPRI). Coal sulfur content is 0.593%and the heating value is 10,496 Btu/lb. H2SO4 control efficiencyis 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%/100 x 1/10,496 x 1,000,000 x Heat Input x98.06/32.07 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.Condensable PM10H2SO4 organic4-19January 2009BART Analysis for Navajo Generating Station05830-012-300Table 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 lb/hr lb/hrNavajo 1750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD154.48 3.99 (k) 0.234 1.575 -1.34 (l) 0.00 131.51 22.97 65.35 64.01 253.73Navajo 2750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD165.52 4.27 (k) 0.251 1.688 -1.44 (l) 0.00 140.91 24.61 70.02 68.59 240.30Navajo 3750 MW, PC,bituminous coal, drybottom, tangentialfired, LNB, SOFA,hot side ESP, SCR,wet FGD160.85 4.15 (k) 0.244 1.640 -1.40 (l) 0.00 136.93 23.92 68.04 66.65 294.87Facility Unit DescriptionNH3 SlipTotalEffectiveH2SO4 forModelingExcess NH3 (Slip)(NH4)2SO4/NH4HSO4(as H2SO4)H2SO4 Total PM10TotalEffectiveSO4 forModelingNH3 H2SO4Total H2SO4before NH3interaction5-1 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## 5.0 BART Control Opti ons 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, wh ich are more fully discussed in Section 4, are:

Options 1 and 1 Alternative : Advanced combustion controls (LNB/S OFA) 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 Un its 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 Resu lts for Control Options

The results of the BART control options modeling are pr esented in Tables 5-1 and 5-2 and graphically plotted in Figure 5-1. Table 5-1 is an overall summary, av eraged 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 com pares 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 visi bility by about 0.37 delta-deciview (relative to the baseline case) with the inst allation of LNB/SOFA controls. These controls result in a NO x 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 regi onal haze changes will im prove 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 NO x emission rate that is well below the pr esumptive limit, thus complying with the requirements of the BART Guidelines fo r 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 re lative to the results of Option 1a at any of the Class I areas. This lack of visibility improvement/degradation occurs because NO x emissions are exactly the same as those for BART Option 1a, with the complication that th e installation of SNCR woul d create new emissions of excess ammonia in an area with low levels of ambi ent ammonia. As discussed in Appendix B, the higher5-2 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 concentra tions of ammonia nitrate particulate s, and result in more visibility degradation. Therefore, NO x emission controls involving SNCR are inef fective 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 NO x controls will improve visibility by about 0.57 delta-deciview over the baseline case. However, the average vi sibility improvement over BART Option 1a is only 0.10 delta-deciview. It is noteworthy that the installation of SCR w ould create new emissions of primary sulfates (H 2 SO 4 and ammonium bisulfate), and would lead to increased gr oss generation to run the SCR equipment, which has not even been factored into the modeling analysis. The incr eased 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 NO x 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, NO x emission controls involving SCR are relatively ineffective for improving visi bility 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 ar eas show that addition of SCR on all three units in addition to the Option 1 controls wi ll improve visibility by about 0.70 delta-deciview over the baseline case. The average visibility improvement over BART Option 1a is about 0.22 del ta-deciview, which is less than onethird of this overall improvement. This incremental improvement in visibility over Option 1a is imperceptible in spite of the NO x emission reductions, for the same reasons stat ed above for BART Option 3.. Therefore, as noted above, NO x 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 effect iveness 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 met eorological year, while Table D-1 presents annualized cost data and information on dollars-per-NO x -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 w ould 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 e ffects 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 SO 2 emissions, which are the same for all NO x BART control options, are relatively low for short distances. In c ontrast, 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 (i f any) from adoption of any of the additional control options considered. As noted above, the installation of SNCR is not a ben eficial option. BART options 3 and 4 controls are5-3 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 NO x limit -- Options 2, 3, and 4 would all require use of post-combustion controls th at EPA specifically determined w ould not be used as the basis for presumptive NO x limits for coal-fired utility boilers (other t han 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 de lta-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 ve ry steep increase in the slopes of the plotted lines relative to the slope for Option 1a. Th is 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 al l units). In this case, the visibility benefits for this BART option are, on average, 0.70 delta-deciviews re lative to the baseline case, but less than a third of this amount, 0.22 delta-deciviews, occurs with the inst allation of the SCR equipment. While the annualized cost to obtain the first 0.47 delta-deciview of the aver age visibility improvement is about $5 million per year, the cost to obtain the remaining 0.22 delta-deciview im provement 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 th e slopes of the plotted lines relative to the slope for Option 1a. Similar to BART Option 3, this analysis clea rly 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 ar eas 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 NO x emissions is only effective during the period of low tourist visitation . While there are modest vi sibility benefits of SCR controls relative to LNB/SOFA contro ls on an annual basis, benefits during the high visitation months of April through October are either reduced s ubstantially or become nonexistent and are replaced by a degradation of visibility in some cases. More in formation in this regard is presented in Appendix G. This supplemental information lends additional justification for the rejection of post-combustion NO x controls as BART.5-4January 2009BART Analysis for Navajo Generating Station05830-012-300Table 5-1 Regional Haze Benefit of BART Controls2001 2002 2003 2001-2003AveBenefit ofControlsfrom Option1/ 1a,delta-dvClassI AreaOption BART Controls8thHighest delta deciviewBaseline None 1.79 1.76 1.69 1.75n/aOption 1 SOFA/LNB on Units 1-3 (0.24lb NOx/MMBtu)1.42 1.41 1.29 1.38n/aOption 1-altSOFA/LNB on Units 1-3 (0.20lb NOx/MMBtu)1.31 1.32 1.19 1.270.10Option 2 SOFA/LNB/SNCR on Units1-31.39 1.43 1.26 1.36-0.08Option 3 SOFA/LNB/SCR on Units1&3 and SOFA/LNB on Unit21.19 1.22 1.10 1.170.10

Average of 11 Class I AreasOption 4 SOFA/LNB/SCR on Units 1-3 1.04 1.10 1.01 1.050.225-5January 2009BART Analysis for Navajo Generating Station05830-012-300Figure 5-1 8thHighest Regional Haze Total Effects Averaged Over3 Years for Baseline and BART Control Case Emissions0.00.51.01.52.02.53.0GrandCanyonCapitol Reef BryceCanyonZion Canyonlands SycamoreCanyonPetrifiedForestArches Mesa Verde Mazatzal PineMountainClass I Area

8th Highest delta-deciviewBaselineOption 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 1-35-6 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table 5-2 Regional Haze Results of BART Cont rols for Each Year and Class I Areas5-7 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table 5-2 Regional Haze Results of BART Controls for Each Year and Cl ass I Areas, continued5-8 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average5-9 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table 5-3 Annual Costs vs. Visibility Improvements, 3-Year Average, continued5-10 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 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

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 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 46-1 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) increm ental improvement in visibility over that resulting from use of LNB/SOFA; increased emi ssions of ammonia, ammonia salts, and sulfuric acid aerosols, which negatively affect local visibility; th e high capital and O&M compliance costs for these technologies; increased generation requirements; and other considerations asso ciated with the shipping, storage, and injection of anhydrous or aqueous ammonia. A summary of the recomm ended 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 NO x Burners / Separated Overfire Air

Estimated NO x Emission Rate 0.24 lbs/MMBtu, with possible reduction to 0.20 lb/MMBtu with experience and optimization of operations

NO x Emission Limit Reduction from Baseline At least 48% at 0.24 lb/MMBtu

Estimated NO x 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 CO 2 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 05830-012-300 ENSR conducted CALPUFF modeling of the baseline emissions and four NO x control emission scenarios, all involving NO x emission reductions and any as sociated increased emissions of H 2 SO 4 and ammonia. The BART control options that were analyzed inclu de the retrofit of adv anced post-combustion NO x controls, i.e., SNCR and SCR, even though EPA determin ed that these kinds of controls are more stringent than those that are ordinarily needed to meet t he 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 98 th percentile prediction results indicate that the installation of the post-combustion NO x controls in addition to LNB/SOFA would have a detri mental, or at best only a modest benefici al 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 Opti on 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 im provements 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 98 th percentile results, is in all cases less than the 0.5-dec iview 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 cont rols is extremely high for those areas for which any improvement in visibility is projec ted. Therefore, post-combustion NO x emission controls are not cost-effective. Consequently, none of the post-combus tion-control options are recomm ended 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 NO x 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.6-3January 2009BART Analysis for Navajo Generating Station05830-012-300Table 6-2 Summary of BART Analysis for NOxStep 1Step 2Step 3Step 4aStep 4bStep 5IdentifyControlTechnologiesFeasibleControlTechnology?Evaluate ControlEffectiveness forTechnicallyFeasible ControlTechnologiesCalculate CostEffectivenessfor ControlTechnologies(relative tobaseline)DetermineNon-Air QualityEnvironmental andEnergy ImpactsEvaluate VisibilityChanges ofControls vs.baselineIdentify BARTControl ResultsControlOption 1Low NOxburners,separatedoverfire airYes48% NOxreductionfrom baselineAnnualized cost= $4.9 MMIncrease in fuelconsumption, LOI of flyash, corrosion,increase in COaverage visibilityimprovement = 0.37delta-dvAchieves betterthan presumptiveNOxlimit withmodest visibilitybenefitAlternativeto ControlOption 1Low NOxburners,separatedoverfire airYes57% NOxreductionfrom coal-firedbaseline (9%reduction relative toOption 1)Annualized cost= $4.9 MMIncrease in fuelconsumption, LOI of flyash, corrosion,increase in COaverage visibilityimprovement = 0.47delta-dv (0.10reduction relative toOption 1)Achieves betterthan presumptiveNOxlimit withadditional visibilitybenefitControlOption 2Low NOxburners,separatedoverfire air, andSNCRYes57% NOxreductionfrom coal-firedbaseline (noadditional reductionfrom Option 1a)Annualized cost= $26.4 MMExcess NH3emissions;1% plant energyconsumption; NH3riskto workers and public,air emissions of NH3transportaverage visibilityimprovement = 0.39delta-dv(degradation fromOption 1a)No additionalvisibility benefit athigh costControlOption 3Low NOxburners,separatedoverfire air, andSCR (Units 1,3)Yes71% NOxreductionfrom coal-firedbaseline (14%reduction relative toOption 1a)Annualized cost= $59.5 MMExcess sulfateemissions; 1% plantenergy consumption;NH3risk to workers andpublic, air emissions ofNH3transportaverage visibilityimprovement = 0.57delta-dv (0.10reduction relative toOption 1a)Marginal additionalvisibility benefit atvery high costControlOption 4Low NOxburners,separatedoverfire air, andSCR (all units)Yes83% NOxreductionfrom coal-firedbaseline (26%reduction relative toOption 1a)Annualized cost= $94.8 MMExcess sulfateemissions; 1% plantenergy consumption;NH3risk to workers andpublic, air emissions ofNH3transportaverage visibilityimprovement = 0.70delta-dv (0.22reduction relative toOption 1a)Marginal additionalvisibility benefit atvery high cost7-1 January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## 7.0 References

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

Battye, W. and K. Boyer. 2002. Catalog of Global Emi ssions 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 Protecti on Agency. EPA Contract #68-02-4400, January 31, 1991.

Electric Power Research Institute. 2007. Estimating Tota l 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) De terminations (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 Im pacts, EPA-454/R-98-019, page 14, December 1998.
EPA. 1995. AP 42, Fifth Edition, Compilation of Air Pollut ant Emission Factors, Volu me 1: Stationary Point and Area Sources, January 1995
Hardman, R., R. Stacy and E. Dismukes. 1998. Estimating Total Sulfuric Acid Emi ssions 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 Wil derness Areas, National Research Council, National Academy Press, Washington, D.C., October 1990.
Paise, J.W. 2006a. Regional Haze Regulations and Guide lines for Best Available Retrofit Technology (BART) Determinations. Memorandum to Kay Prince, Branch Ch ief 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 Ci rcuit Court document UARG vs. EPA, No. 06-1056.
Personal correspondence between John Notar of the N PS and Bob Paine of ENSR, November 28, 2005.

Regional Haze Regulations and Guidelines for Best Avail able Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 70, No. 128 published July 6, 2005).
Regional Haze Regulations; Revisions to Provisions Gove rning Alternative to Source-Specific Best Available Retrofit Technology (BART) Determinations; Final Rule (FR Vol. 71, NO. 198 published October 13, 2006).
Sargent & Lundy, 2008. Salt River Project Navajo Gener ating 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 We stern United States. August 15, 2006.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix A

CALMET/CALPUFF Processing RefinementsJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 

### 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 prot ocol. As part of ENSR’s internal quality assurance procedure, we displayed and examined the 4-km Arizona WR AP 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 heigh t. Circular areas in thes e figures with common winds and abrupt transitions at the edge of the circles indicate a radius of influence of surf ace 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 establis hed out to 50 km and then it abruptly ends beyond that distance. Setting R1 and R1MAX to such high val ues 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 m odeling in the WRAP region from John Notar of the National Park Service (personal correspondence between J ohn Notar of the NPS and Bob Paine of ENSR). A large R1 value results in wind fields surrounding surface st ations that overwrite the MM5 wind fields, which do have terrain influences incorporated into them. In ma ny instances, the extended ex trapolation of the surface station data with an abrupt transition at 50 km produces opposing wind directions in adj acent 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 observ ations much better, creating a more uniform wind field throughout the domain. Therefore, ENSR used the smalle r R1 and R1MAX values to be more consistent with FLM guidance and due to the better performance in the wind field depiction associated with the smaller values.

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

.
In accordance with recent CALPUFF modeling guidance from the EPA Region IX and National Park Service (see Appendix F), ENSR used the tec hnical options listed below.

• Included upper air soundings in a Step 2 analys is; 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 observ ations to the upper layers using similarity theory, and ignore layer 1 from the upper air soundings.

• Set ITPROG = 1, to use surface station temp erature and the MM5 for upper air temperature interpolation.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure A-1 CALMET Windfields with WRAP SettingsJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure A-2 CALMET Windfields with ENSR SettingsJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure A-3 Location of Surface and Upper Air Stations used for Arizona CALMET DomainJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 

### 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 Versio n 6.211 that was used by WRAP, available at http://www.src.com/calpuff/do wnload/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 gener ally acknowledged to be t he 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) unc overed a number of issues that were of concern to EPA. These issues were discussed in a presentation byMr. Dennis Atkinson of EPA’s Office of Air Quality Planning and Standards at the 2007 annual modelers workshop (see http://www.cleanairinfo.com/regional statelocalmodelingworkshop/agenda.htm ; “CALPUFF_status_update.pdf”). The basic issues of concern with the VISTAS version (and equivale nt Version 6) are as follows:

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

• Incomplete model documentation has been a problem wi th the last model users guides now 7 years old.

• The VISTAS code changes went beyond just fixing c oding errors in Version 5.711a, contrary to what TRC, the model developer, asserted.

• EPA’s annotated in-code documentation identifi ed 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 optio nal technical enhancements, e.g., for mixing height, were implemented in CALMET

The new approved Version 5.8 disables some of the VIST AS “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 techni cal options specified in the newly a pproved 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 20January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

### Ambient Background Ammonia Values

The POSTUTIL utility program was used to repartition HNO 3 and NO 3 using appropriate ammonia background values that were approved by the Federal Land manager s 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/monitori ng/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 concentra tion 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 ba ckground 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 CM AQ modeled values provided in Appendix A of www.vistas-sesarm.org/BART/ CMAQ2002_evaluation_Dec31_2005.pdf

.
Ammonia slip sensitivity analys is 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 0.2January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix B

Factors Influencing NO x 

## Emissions Effects on Visibility and Ammonia Slip Sensitivity Analysis

-January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Secondary pollutants such as nitrates and sulfates are signifi cant contributors to the visibility extinction in Class I areas. The CALPUFF model was used to determine the ef fect of these pollutants on Class I areas, associated with BART control options. CALPUFF uses the EPA-a pproved MESOPUFF II chemical reaction mechanism to convert SO 2 and NO x emissions to secondary sulfates and nitrat es. 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 SO 2 to ammonium sulfate (NH 4 ) 2 SO 4 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). Ho mogeneous gas phase reaction is the dominant SO 2 oxidation pathway during clear, dry conditions (Calvert et al., 1978). CALPUFF assumes that the sulfate reacts preferentially with ammonia (NH 3 ) to form ammonium sulfate and that any remaining ammonia is available to form ammonium nitrate (NH 4 NO 3 ).

Figure B-1 MESOPUFF II SO 2 Oxidation

Formation of Nitrates

The oxidation of NOx to nitric acid (HNO 3 ) 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 NO x Oxidation

In CALPUFF, total nitrate (TNO 3 =HNO 3 + NO 3 ) is partitioned into each species according to the equilibrium relationship between gaseous HNO 3 and NO 3 aerosol. This equilibrium is a f unction of ambient temperature and relative humidity. Moreover, the formation of nitrate strongly depends on availability of NH 3 to form ammoniumJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 nitrate, as shown in Figure B-3 (from CALPUFF courses gi ven 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 partic ulate form. Figure B-3 also shows that colder temperatures and higher relative humidity significant ly favor nitrate formation and vice versa. A summary of the conditions affecting nitrate formation are listed below:

• Colder temperature and higher relative humidity cr eate favorable conditions to form nitrate particulate matter, and therefore more a mmonium nitrate is formed;

• Warm temperatures and lower relative humidity create less favorable conditions to form nitrate particulate matter, and therefore less amm onium nitrate is formed;

• Sulfate preferentially scavenges ammonia over nitrat es. 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 temperatur e 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 emi ssions are quite low, the at mosphere is likely to be in an ammonia-limited regime relati ve 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 NO 3 /HNO 3 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, t he 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 unalter ed ambient ammonia background values. This range covers the extremes of the analysis requested by EPA Region 9.

The modeling analysis was limite d 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 NO x control) was assumed to combine with H 2 SO 4 to result in additional primary sulfate emissions. Therefore, ammonia sensitivity modeling was not required for the SCR cases.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Excess ammonia emissions associated with SNCR operations were modeled in CALPUFF to determine the 8 th 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 8 th highest ammonia concentrations were first produced in μ g/m 3 and then were converted to ppb. The results show that the predicted excess ammonia concentrations av eraged over 2001-2003 are the highest at Grand Canyon NP (0.09 ppb with 100% of ammonia emi ssions) 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 differ ence 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 th e 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 am monia 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 amm onia emissions and by about 0.48 delta-deciview with 100% of expected ammonia emissions.

At Capitol Reef NP, regional haze changes would involv e 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 Concen trations due to SNCR Operation

2001-2003 Average 8th highest 24-hr

Predicted Ammonia Concentration (ppb) Class I Area

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 0.017January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table B-2 Background Ammonia Concentrations used for Sensitivity Modeling

Ambient Ammonia Background Concentration at Grand Canyon NP and Capitol Reef NP (ppb) Ambient NH 3 Background Concentration Plus Predicted Excess NH 3 at Grand Canyon NP (ppb) Ambient NH 3 Background Concentration Plus Predicted Excess NH 3 at Capitol Reef NP (ppb) Ambient NH 3 Background Concentration Plus Predicted Excess NH 3 at Grand Canyon NP (ppb) Ambient NH 3 Background Concentration Plus Predicted Excess NH 3 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 Ave Class I

Area Case NH3 Emissions 8 th 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 2.44Grand 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 2.43Capitol 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.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix C

Review of Data from the IMPROVE Monitoring NetworkJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 The Visibility Information Exchange W eb System (VIEWS) is an online databas e 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 visibili ty in national parks and wilderness areas (http://vista.cira.colo state.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 av erage 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 show n in Figure C-1. Bar and pie charts for the modeled eleven Class I areas for year 2002 are presented in this appendix. Year 200 2 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 forJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 peak effects) contributed about 40% and coarse particu late matter (due to wind-blown dust) contributed about 22% on the worst 20% days to the vi sibility 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 ni trate contributions were virtually nonexi stent during the warm period of AprilOctober (during the period of the heavie st park visitation), while sulfate contributions were generally present throughout the entire year. In fact, very few of the wo rst 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 asso ciated 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 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-3 Plot of Measured Visibility-Degradi ng Pollutants in Capitol Reef NP, Year 2002

The pie chart for Capitol Reef NP was not available on the VIEWS web site.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-4 Plot of Measured Visibility-Degrading Pollutants in Grand Canyon NP, Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-5 Plot of Measured Visibility-Degrading Pollutants in Mazatzal W and Pine Mountain W, Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-6 Plot of Measured Visibility-Degrading Pollutants in Mesa Verde NP, Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-7 Plot of Measured Visibility-Degrading Pollutants in Petrified Forest NP, Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure C-8 Plot of Measured Visibility-Degrading Pollutants in Sycamore Canyon W, Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 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.January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix D

CALPUFF Modeling and Cost Effectiveness Results for Each Year from Potential Plant Contributions to Visibility ChangesJanuary 2009BART Analysis for Navajo Generating Station05830-012-300Table D-1 Annual Costs and Costs per NOxTon RemovedControlOptionControl TechnologyTotal CapitalCost ($)Fixed CapitalCost ($/yr)Annual O&MCost ($/yr)Total AnnualCost ($/yr)NOx (TPY)Removed @ 85%Utilization$/ton NOxRemovedRelative toBaseline orOption 1a1a LNB/SOFA (Units 1-3)$42,000,000 $4,866,000 $0 $4,866,000 26753 $1822LNB/SOFA & SNCR (Units1-3)$78,000,000 $9,037,000 $17,391,000$26,428,000 26753 not effective3LNB/SOFA (Unit 2) &LNB/SOFA & SCR (Units 1and 3)$438,000,000 $50,747,000 $8,778,000 $59,525,000 34769 $6,8194LNB/SOFA & SCR (Units1-3)$705,000,000 $81,681,000 $13,167,000 $94,848,000 38980 $7,360January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-2 Annual Costs vs. Visibility Improvements for Year 2001January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-2 Annual Costs vs. Visibility Improvements for Year 2001, continuedJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-3 Annual Costs vs. Visibility Improvements for Year 2002January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-3 Annual Costs vs. Visibility Improvements for Year 2002, continuedJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-4 Annual Costs vs. Visibility Improvements for Year 2003January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table D-4 Annual Costs vs. Visibility Improvements for Year 2003, continuedJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix E

CALPUFF Modeling Results Using Background plus Potential PlantCaused Visibility Impairment for Each YearJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 TableE-1 Regional Haze Changes from Natura l Conditions Due to Baseline EmissionsJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure E-1 8 th 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 8.0Grand Canyon NPCapitol Reef NPBryce Canyon NPZion NPCanyonlands NPSycamore Canyon WPetrified Forest NPArches NPMesa Verde NPMazatzal WPine Mountain W

Class I Area8th Highest deciview Met Year 2001 Met Year 2002 Met Year 2003

Table E-2 Regional Haze Benefit of BART ControlsJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Figure E-2 8th Highest Regional Haze Total Result s 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 Area8th 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 1-3January 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table E-3 Regional Haze Results of BART C ontrols for Each Y ear and Class I AreasJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table E-4 Annual Costs vs. Visibility Improvements/Degradation, 3-Year AverageJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 Table E-4 Annual Costs vs. Visibility Improvements/Degradation, 3-Year Average, continuedJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 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

4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 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 4January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix F

EPA Region 9 Letter to Salt River Project (July 1, 2008)January 2009 BART Analysis for Navajo Generating Station 05830-012-300January 2009 BART Analysis for Navajo Generating Station 05830-012-300January 2009 BART Analysis for Navajo Generating Station 05830-012-300January 2009 BART Analysis for Navajo Generating Station 05830-012-300 

## Appendix G

98th Percentile Regional Haze Results During Entire Year and April – October PeriodJanuary 2009 BART Analysis for Navajo Generating Station 05830-012-300 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 Area98th 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 Area98th 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 1-3A Trusted Global Environmental, Health and Safety Partner 

## U.S. Locations

AK, Anchorage (907) 561-5700
AL, Birmingham (205) 980-0054

AL, Florence (256) 767-1210
CA, Alameda (510) 748-6700
CA, Camarillo (805) 388-3775
CA, Orange (714) 973-9740
CA, Sacramento (916) 362-7100
CO, Ft. Collins (970) 493-8878
CO, Ft. Collins Tox Lab. (970) 416-0916
CT, Stamford (203) 323-6620
CT, Willington (860) 429-5323
FL, St. Petersburg (727) 577-5430

FL, Tallahassee (850) 385-5006
GA, Norcross (770) 381-1836
IL, Chicago (630) 836-1700
IL, Collinsville (618) 344-1545
LA, Baton Rouge (225) 751-3012

MA, Harvard Air Lab. (978) 772-2345
MA, Sagamore Beach (508) 888-3900 MA, Westford (978) 589-3000

MA, Woods Hole (508) 457-7900
MD, Columbia (410) 884-9280

ME, Portland (207) 773-9501

MI, Detroit (269) 385-4245
MN, Minneapolis (952) 924-0117
NC, Charlotte (704) 529-1755
NC, Raleigh (919) 872-6600

NH, Belmont (603) 524-8866
NJ, Piscataway (732) 981-0200
NY, Albany (518) 453-6444

NY, Rochester (585) 381-2210
NY, Syracuse (315) 432-0506
NY, Syracuse Air Lab. (315) 432-0506
OH, Cincinnati (513) 772-7800
PA, Langhorne (215) 757-4900
PA, Pittsburgh (412) 261-2910

RI, Providence (401) 274-5685
SC, Columbia (803) 216-0003 TX, Dallas (972) 509-2250

TX, Houston (713) 520-9900
TX, San Antonio (210) 296-2125
VA, Chesapeake (757) 312-0063
VA, Glen Allen (804) 290-7920

WA, Redmond (425) 881-7700

WI, Milwaukee (262) 523-2040

Headquarters MA, Westford (978) 589-3000

Worldwide Locations

Azerbaijan Belgium Bolivia Brazil China England France Germany Ireland Italy Japan Malaysia Netherlands Philippines Scotland