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Proposed Rule: Source Specific Federal Implementat ion Plan for Implementing Best Available Retrofit Technology for Four Corners Powe r Plant: Navajo Nation

Technical Support Document Docket Number: EPA-R09-OAR-2010-0683

Executive Summary

This document provides the analytical framework and technical justification to support the proposed determination of the Best Available Re trofit Technology (BART) for the Four Corners Power Plant (FCPP) pursuant to the Regional Haze Rule (RHR). This BART determination is limited to emissions of NO x and PM from FCPP.

Pursuant to the Tribal Authority Rule, EPA Region I X (EPA) finds that the BART requirement for NO x and PM of the RHR is necessary or appropriate to a pply at this time to FCPP. In making our BART Determination for these f acilities, we examined the following six factors as prescribed by the RHR:

 Factor 1 assesses the available technology to contr ol emissions and determines the technical feasibility of each technology;

 Factor 2 examines the cost of compliance for the te chnically feasible control technologies;

 Factor 3 addresses the energy and non-air quality i mpacts of the control technologies;

 Factor 4 considers any existing air pollution contr ol technologies at the source;

 Factor 5 considers the remaining useful life of the source; and

 Factor 6 assesses the degree of visibility improvem ent expected to result from the various control technologies.

40 C.F.R. § 51.308(e)(1)(ii)(A). All but the first of these factors are also expressly required to be taken into account by the Clean Air Act. 42 U.S.C. § 7491(g)(2). Although we list six factors, the first factor is not always explicitly stated an d the remaining factors are frequently referred to as the “Five Factor Analysis” for the RHR BART dete rmination.

On behalf of Arizona Public Service (APS), co-owne r and operator of FCPP, Black & Veatch (B&V) submitted a BART Engineering Analysis (dated December 4, 2007) and ENSR Corporation, now AECOM, submitted BART visibility m odeling results (dated January 2008) to EPA. Based on these analyses, APS recommended the i nstallation of low-NO x burners (LNB) on Units 1 and 2 and LNB plus overfire air (LNB + OFA) on Units 3 – 5 to satisfy BART. APS concluded that the installation of selective cataly tic reduction (SCR), which would achieve the greatest NO x reductions, was not cost effective because their a nalyses showed high costs and low average visibility improvement. For PM, FCPP concl uded that BART was already met on all five units because additional PM control would not result in significant visibility improvement.

On August 28, 2009, EPA published an Advanced Noti ce of Proposed Rulemaking (ANPRM) in the Federal Register (74 FR 44313) and r equested comment on the anticipatedPage 2 of 92

visibility improvements at surrounding Class I area s and the cost effectiveness of controls for BART at FCPP and the Navajo Generating Station (NGS ). EPA presented results of visibility modeling and cost effectiveness submitted by APS as well as results of visibility modeling conducted by EPA and cost analyses submitted by the National Park Service (NPS). The publication of the ANPRM provided an opportunity to begin formal consultations with affected Tribes and continued an on-going consultation with the Federal Land Managers (FLMs) as required under the RHR (40 CFR §51.308(h)(4)(i)(2)) . We will continue to consult with the Tribes and the FLMs during the comment period for t his proposal.

EPA received requests for consultation and comments from numerous Tribes, including the Ak-Chin Indian Community, Inter Tribal Council of Arizona, Gila River Indian Community, Hopi Tribe, Navajo Nation, Tohono O’odham Nation, a nd the Salt River Pima Maricopa Indian Community. Additionally, EPA received comments fro m Federal and State agencies, numerous industry, utility, and water groups, environmental and community-based organizations, cities and municipalities, U.S. and State Representatives, and the Governor of Arizona. The majority of all comments received related primarily to issues assoc iated with NGS rather than FCPP. All comments received on the ANPRM are available in the ANPRM docket 1 . Because of the complexity of issues related to NGS, EPA is first p roposing this BART determination only for FCPP. EPA intends to propose a BART determination for NGS subsequently. We have reviewed and considered all comments relevant to FC PP and revised our analyses to address comments as we determined appropriate. We have add ressed specific comments resulting from our consultations with affected states, Tribes, and the FLMs and included a discussion of those comments in this Technical Support Document (TSD), but will not issue a response to comments on the ANPRM.

The first factor of the statutory factor analysis identified SCR as the top option for reducing NO x emissions at FCPP. Our approach for the five-fact or analysis was similar to a topdown analysis for the Best Available Control Techno logy (BACT) requirement of the PSD program. Therefore, we started with the most strin gent technology and evaluated the remaining factors to determine if the highest level of contro l should be rejected. EPA determined that even if modern LNB or LNB + OFA achieved the emission ra te claimed by APS, these controls would not reduce NO x emissions sufficiently that is adequate for BART f or a facility that has consistently been one of the largest NO x emitters in the U.S. and is located on the Colorad o Plateau affecting visibility in sixteen Class I are as. Based on past experience with FCPP and contractor evaluations of the potential for NO x reductions through combustion modifications conducted prior in the years prior to the ANPRM, EP A is concerned that combustion controls may result in operational difficulties. EPA therefo re evaluated SCR without additional combustion controls.

The second factor evaluates the cost of controls. EPA finds that even using the cost analysis submitted by B&V for FCPP, the costs per t on for SCR ($4,300 - $5,400/ton) are within a range that has been determined reasonable for BAR T. EPA used B&V’s cost estimates and made several revisions to assumptions based on guid elines in the EPA Control Cost Manual to generate cost projections that are more reasonable and consistent with the BART guidelines.

1 See Docket #: EPA-R09-OAR-2009-0598 on www.regulat ions.gov.Page 3 of 92

EPA estimated an average cost effectiveness of less than $3,000 per ton to install SCR on all five units at FCPP.

The third factor involves consideration of the ene rgy and non-air quality impacts of controls. Because of the importance of FCPP on the economy of the Navajo Nation, EPA also considered in our determination the potential econo mic impacts of SCR. EPA understands the overall concern of the Navajo Nation is that requir ing SCR as BART for FCPP will cause FCPP to shut down and result in the loss of Navajo jobs at FCPP and the BHP Mine, which supplies coal to FCPP, as well as the loss of royalties and taxes paid by these two entities. Based on an economic analysis of the increase in electricity ge neration costs of SCR compared to the estimated cost to purchase electricity on the whole sale market, FCPP is expected to remain competitive relative to the wholesale market, sugge sting that the cost increase for SCR alone should not force FCPP to shut down. This analysis estimates that the average cost of electricity generation over the 20 year amortization period as a result of SCR implementation will increase by 22%, or $0.00740/kWh.

Retail electricity consumers, however, pay more th an just the generation costs of power. Retail rates include the cost to transmit and distr ibute electricity as well as generate electricity. Additionally, for APS customers, for example, the g eneration cost increase on FCPP due to SCR would flow into a broader retail rate impact calculation based on the entire portfolio of APS generation assets and power purchase contracts, whi ch include coal (of which FCPP is only a portion of APS’s total coal portfolio), natural gas , nuclear, and some renewables. For these reasons, EPA expects the increase to rate payers re sulting from SCR on FCPP to be significantly lower than 22%.

As described in comments on the ANPRM, numerous ot her factors exist that will impact an owner’s decision not to invest in SCR, including upcoming lease negotiations, ownership changes, and upcoming regulations on greenhouse gas and mercury emissions and coal combustion residues. Because of the uncertainty as sociated with upcoming regulations and the complexity in determining the appropriate level of risk for each owner, EPA has determined that our BART determination cannot rely on conjectures o n the future decisions of FCPP owners. Without firm intentions and commitments to shut dow n in the near future resulting from one or more regulatory factors, EPA is only considering th e results of the economic model for SCR in our analysis, which suggests that SCR will not caus e the cost of electricity generation to exceed the wholesale market cost of electricity.

Factor four explores the existing controls at the source. For NO x , the existing controls at FCPP include LNBs installed on Units 2 – 5 in the 1 980-1990’s and for PM control, venturi scrubbers on Units 1 – 3 and baghouses on Units 4 a nd 5. Average NO x emission rates from FCPP range from 0.5 lb/MMBtu (Units 4 and 5) to 0.7 8 lb/MMBtu (Unit 1). The physical limitations of the each boiler and the past operati onal difficulties resulting from LNB retrofit of Unit 2 suggest that LNB and LNB+OFA retrofit will n ot reduce NO x emissions significantly and may cause operational challenges. The venturi scru bbers on Units 1 – 3 are very old control technologies that are no longer installed on any co al-fired power plants and do not satisfy BART for PM. The secondary PM plume from the venturi sc rubber-controlled units often results inPage 4 of 92

pervasive and persistent plumes covering much of th e Four Corners area, particularly in the early mornings during temperature inversions.

The fifth factor considers the remaining useful li fe of the facility. Although commenters have cited the age of FCPP and impending lease and right-of-way negotiations with the Navajo Nation as a rationale to consider a shorter useful life of the facility, EPA has determined that the default 20-year amortization period is most appropr iate to use as the remaining useful life of the facility. Without commitments for an early shut do wn, EPA cannot consider a shorter amortization period in our analysis.

The final factor examines the visibility improveme nt resulting from controls. The anticipated visibility benefits were modeled using CALPUFF. Background ammonia concentrations assumed in the model are an importan t component of the visibility impacts model. Based on results from four different ammonia backgr ound scenarios, EPA determined that although the assumed concentration impacts the abso lute modeled visibility benefits, it does not change the ranking of controls, i.e., the most stri ngent control technology, SCR, results in the highest modeled visibility improvement. All ammoni a background scenarios result in perceptible improvements in visibility at the most impacted Class I areas.

EPA’s BART determination for FCPP is presented in T able ES-1: Summary of BART Determination for FCPP.

Table ES-1: Summary of EPA BART Determination for F CPP
Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

NO x (lb/MMBtu) 30-day rolling avg 0.16 0.13 0.12 0.10 0.10

PM (lb/MMBtu) 6-hour average 0.012 10% opacity 0.012

10% opacity 0.012

10% opacity 0.015

10% opacity 0.015

10% opacity

EPA is proposing to require FCPP to meet a plant-wi de heat input-weighted average emission limit of 0.11 lb/MMBtu. This BART determi nation can be met by achieving 80% control on Units 1 – 5 by the application of SCR. For PM, our BART determination is to reduce the PM emission limit on Units 1 – 3 to 0.012 lb/MM Btu and to set the PM limit for Units 4 and 5 at 0.015 lb/MMBtu. Additionally, we are proposin g to include a 10% opacity limit for all 5 units. The new PM limit on Units 1 – 3 would requi re the installation of any of the four technically feasible add-on PM controls discussed b y APS. As an alternative for Units 1 – 3, EPA is requesting comment on whether APS can satisf y BART on Units 1 – 3 by operating the existing venturi scrubbers to meet an emission limi t of 0.03 lb/MMBtu with a 20% opacity limit. The PM limit on Units 4 and 5 should be achievable with proper operation of the existing baghouses.

In weighing the six factors, we believe that our de terminations for NO x and PM represent the most appropriate BART determination for FCPP, t he largest NO x emission source in the United States.Page 5 of 92 Table of Contents

Description Page

List of Tables and Figures 7 List of Commonly Used Acronyms 9 1. Introduction A. Brief History and Description of Four Corners P ower Plant 10 B. Regional Haze Rule 11 C. Pollutants Addressed in our BART Determination 11 D. Advanced Notice of Proposed Rulemaking and EPA Approach to

Consultation with Affected States, Tribes, and FLMs 12

2. Technology Available A. FCPP Approach to this Factor 14 B. Discussion of Factor in ANPRM 17 C. Affected State, Tribe, and FLM Consultation 19 D. EPA Conclusions Regarding this Factor 19 3. Costs of Compliance A. FCPP Approach to this Factor 20 B. Discussion of Factor in ANPRM 24 C. Affected State, Tribe, and FLM Consultation 28 D. EPA Conclusions Regarding this Factor 29 4. Energy and Non-Air Quality Environmental Impacts of Compliance A. FCPP Approach to this Factor 33 B. Discussion of Factor in ANPRM 34 C. Affected State, Tribe, and FLM Consultation 34 D. EPA Conclusions regarding this Factor 35 5. Any Existing Pollution Control Technology at the Source A. FCPP Approach to this Factor 39 B. Discussion of Factor in ANPRM 40 C. Affected State, Tribe, and FLM Consultation 40 D. EPA Conclusions regarding this Factor 41 6. Remaining Useful Life of the Source A. FCPP Approach to this Factor 42 B. Discussion of Factor in ANPRM 42 C. Affected State, Tribe, and FLM Consultation 42 D. EPA Conclusions regarding this Factor 42 7. Degree of Improvement in Visibility Which May Re asonably Anticipated to Result From the Use of Such Technology A. BART Guidelines and Modeling Protocols 42 B. Ammonia 50 C. Sulfuric Acid 50 D. FCPP Approach to this Factor 51 E. Discussion of Factor in ANPRM 54 F. Affected State, Tribe, and FLM Consultation 62 G. EPA Conclusions regarding this Factor 67Page 6 of 92

8. Overall BART Determination A. FCPP Approach to this Factor 81 B. Affected State, Tribe, and FLM Consultation 82 C. EPA Conclusions regarding this Factor 83 9. Appendices A. Mobile Source Risk Estimates for Four Corners P ower Plant B. Economic Analysis of SCR on FCPP C. Impact of Ammonia in Fly Ash on its Beneficial UsePage 7 of 92

List of Tables and Figures

Number Title Page

Table 1 FCPP Operational Characteristics 10 Table 2 Facility-wide NO x Emissions from FCPP from 2001 – 2009 11 Table 3 Analysis of Available NO x Control Options for FCPP Presented by B&V

for APS 15

Table 4 Analysis of Available PM Control Options fo r FCPP Units 1 – 3

Presented by B&V for APS 17

Table 5 Projected Costs (dated August 2008) for NO x Controls Estimated by B&V 21 Table 6 NO x Emission Rates and Percent Reductions Estimated by B&V 22 Table 7 NO x Reductions and Cost Effectiveness of Controls Esti mated by B&V 23 Table 8 Cost Estimates and Emissions Reductions for PM Estimated by B&V 24 Table 9 SCR Cost Estimates from ANPRM based on APS, EPA, and NPS 25 Table 10 Cost Estimates for PM Control Presented in ANPRM from APS and EPA

Revisions 26

Table 11 Comparison of Total Capital Investment (TC I) and Total Annual Costs

(TAC) from Other Western Facilities 27

Table 12 NPS’s Estimated Costs of Combustion Contro ls + SCR based on EPA

Control Cost Manual Reported in their Comments on ANPRM 29

Table 13 Summary of EPA Revisions to B&V Cost Input s for SCR on Unit 4 30 Table 14 Comparison of APS Cost Estimates Submitted in 2009 and 2010 31 Table 15 EPA Revised Cost Estimates for SCR on Unit s 1 – 5 (2008 dollars) 32 Table 16 Cost Effectiveness of SCR Retrofits estima ted for Several Western Power

Plants 32

Table 17 Increase in Electricity Generation Costs ( $/kWh) from NO x and PM

Controls at FCPP Presented in ANPRM 34

Table 18 Summary of Cost Comparisons for NO x Control versus Market Trends

under Straight Line Depreciation (2011 – 2035) 37

Table 19 Summary of Cost Comparisons for NO x Control versus Market Trends

under Accelerated Depreciation (2011 – 2035) 38

Table 20 Flue Gas Flow Sequence and Air Pollution C ontrol Equipment at FCPP 41 Table 21 Measured Visibility Impairment at Class I areas (2007 – 2008 average) 44 Table 22 Class I Areas in CALPUFF Modeling for FCPP 49 Table 23 Selected CALMET settings for FCPP 50 Table 24 Natural Background Concentrations 51 Table 25 AECOM Modeling Inputs (lb/hr) 53 Table 26 Assumptions Used by AECOM for H 2 SO 4 Emission Estimates 54 Table 27 Ammonia Background Concentration in ppb 54 Table 28 Impacts of FCPP on Visibility (98 th Percentile of daily maximum dv) at

Sixteen Class I Areas as Modeled by AECOM 55

Table 29 Assumptions used in Sulfuric Acid (H 2 SO 4 ) Emissions Calculations 59 Table 30 Ammonia Background Concentrations in ppb D etermined by EPA used in

ANPRM 61

Table 31 NPS Modeling Results – Average 8 th High Baseline and Delta dv 67Page 8 of 92 Improvement from 2001 – 2003 Table 32 Class I Area Grouping for Ammonia Backgrou nd used in this proposal 69 Table 33 Ammonia Background Concentrations in ppb m odeled by EPA used in

this proposal 70

Table 34 EPA Modeling Inputs (lb/hr) 74 Table 35 EPA Modeling Results – 8 th High Delta dv Baseline from 2001 – 2003 for

the Different Ammonia Background Scenarios 76

Table 36 EPA Modeling Results – 8 th High Delta dv Improvement and Percent

Change in Delta dv Impact Compared to Baseline Impa cts from 2001 – 2003 using Am1 Ammonia Background Scenario 78

Table 37 EPA Modeling Results – 8 th High Delta dv Improvement and Percent

Change in Delta dv Impact Compared to Baseline Impa cts from 2001 – 2003 using Am2 Ammonia Background Scenario 79

Table 38 EPA Modeling Results – 8 th High Delta dv Improvement and Percent

Change in Delta dv Impact Compared to Baseline Impa cts from 2001 – 2003 using Am3 Ammonia Background Scenario 80

Table 39 EPA Modeling Results – 8 th High Delta dv Improvement and Percent

Change in Delta dv Impact Compared to Baseline Impa cts from 2001 – 2003 using Am5 Ammonia Background Scenario 81

Table 40 Summary of BART Determination for FCPP 87

Figure 1 Map of Class I Areas near FCPP 44Page 9 of 92 List of Commonly Used Acronyms and Abbreviations

AECOM AECOM Environmental ANPRM Advanced Notice of Proposed Rule Making APS Arizona Public Service BART Best Available Retrofit Technology B&V Black and Veatch CAA Clean Air Act CFR Code of Federal Regulations DV (dv) Deciview ENSR ENSR Corporation EPA U.S. Environmental Protection Agency ESP Electrostatic Precipitator FGD Flue Gas Desulfurization FIP Federal Implementation Plan FLM Federal Land Manager FR Federal Register FS U.S. Forest Service FWS U.S. Fish and Wildlife Service H 2 SO 4 Sulfuric Acid LNB Low NO x Burners NAAQS National Ambient Air Quality Standards NH 3 Ammonia NO x Oxides of Nitrogen NPS National Park Service NSPS New Source Performance Standard NSR New Source Review OFA Over Fire Air PJFF Pulse Jet Fabric Filter PM Particulate Matter PSD Prevention of Significant Deterioration RGFF Reverse Gas Fabric Filter SCR Selective Catalytic Reduction SNCR Selective Non-Catalytic Reduction SO 2 Sulfur Dioxide SOFA Separated Over Fire Air FCPP Four Corners Power Plant TPY (tpy) Tons Per Year TSD Technical Support DocumentPage 10 of 92



### 1. Introduction

A. Brief History and Description of Four Corners Power Plant

The Four Corners Power Plant (FCPP) is a mine mouth coal-fired power plant located on the Navajo Nation Indian Reservation, ne ar Farmington, New Mexico and consists of five coal-fired electric utility steam generating units with a total net capacity of 2060 MW (See Table 1). FCPP was built prior to the original Clean Air Act (CAA) of 1970. These types of facilities are often referred to as “grandfathered” because they predate many of the regulatory programs required by the CAA such as New Source Review (NSR), Prevention of Significant Deteriorati on (PSD), and New Source Performance Standards (NSPS).

Units 1, 2, and 3 are nearly 50 years old and owned by Arizona Public Service (APS), which serves as the facility operator. Unit s 4 and 5 are about 40 years old and coowned by six entities: Southern California Edison ( 48%), APS (15%), Public Service Company of New Mexico (13%), Salt River Project (10 %), El Paso Electric Company (7%), and Tucson Electric Power (7%). These owners serve electricity customers in California, New Mexico, Arizona, and Texas.

Table 1: FCPP Operational Characteristics Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 Year Operation Began 1963 1963 1964 1969 1970

Capacity (MW) 170 170 220 750 750 Heat input (gross) (MMBtu/hr) 1863 1863 2400 7806 7806

Boiler Type Riley Stoker,

front wall-fired, tangent tube furnace Riley Stoker,

front wall-fired, tangent tube furnace Foster Wheeler,

front wall-fired, membrane wall furnace B&W, front and

rear wall-fired, cell burner boiler B&W, front and

rear wall-fired, cell burner boiler
NO x Baseline emission rate 2 (lb/MMBtu) 0.78 0.64 0.59 0.51 0.48

PM Baseline emission rate 3 (lb/MMBtu) 0.025 0.029 0.029 0.014 0.010

Based on data from the Clean Air Markets Division, from 2001 – 2009, FCPP has consistently ranked among the top ten highest NO x emitters (in terms of tons of NO x emitted per year) in the United States (see Table 2 ). Additionally, FCPP is the largest

2 Based on annual averages reported by APS from 2002 – 2006. See Excel Spreadsheet titled “FCPP_BART_Scenarios_Emissions_EPA_proposal.xls”.
3 Based on annual averages reported by APS from 2002 – 2006. See Excel Spreadsheet titled “FCPP_BART_Scenarios_Emissions_EPA_proposal.xls”.Page 11 of 92

source of NO x on the Navajo Nation and in the Western United Sta tes. From 2004 – 2006 and in 2009, FCPP was the largest source of NO x in the United States.

Table 2: Facility-wide NO x Emissions from FCPP from 2001 – 2009 NO x Ranking Year NO x emissions (tons) Heat Input (MMBtu) NO x (lb/MMBtu)
3 2001 47,300 168,016,168 0.56
8 2002 41,577 145,626,994 0.57
3 2003 45,197 158,875,366 0.57
1 2004 40,742 147,315,117 0.55
1 2005 41,743 156,326,135 0.53
1 2006 44,649 159,833,285 0.56
2 2007 41,083 147,085,512 0.56
2 2008 40,311 146,354,068 0.55
1 2009 42,510 156,774,393 0.54

B. Regional Haze Rule

The Regional Haze Rule (RHR) requirements in the 1 990 CAA amendments were designed to address the large grandfathered sources that have an adverse impact on visibility in National Parks and Wilderness Areas. EPA Region IX has determined pursuant to the Tribal Authority Rule (40 CFR §49.1 1(a)) as part of our Federal Implementation Plan (FIP) proposal that the BART re quirement of the RHR is necessary or appropriate to apply at this time to FCPP. The R HR provides the following six factors that should be taken into consideration when undert aking a BART determination:

 Factor 1 assesses the available technology to contr ol emissions and determines the technical feasibility of each technology;

 Factor 2 examines the cost of compliance for the te chnically feasible control technologies;

 Factor 3 addresses the energy and non-air quality i mpacts of the control technologies;

 Factor 4 considers any existing air pollution contr ol technologies at the source;

 Factor 5 considers the remaining useful life of the source; and

 Factor 6 assesses the degree of visibility improvem ent expected to result from the various control technologies.

40 C.F.R. § 51.308(e)(1)(ii)(A). All but the first of these factors are also expressly required to be taken into account by the Clean Air Act. 42 U.S.C. § 7491(g)(2). Although we list six factors, the first factor is not always explicitly stated an d the remaining factors are frequently referred to as the “Five Factor Analysis” for the RHR BART dete rmination.

C. Pollutants Addressed in our BART Determination

The RHR requires an assessment of all visibility-i mpairing pollutants at a source that are emitted in excess of the Prevention of Sig nificant Deterioration (PSD) significance levels (40 CFR §52.21). The BART Guid elines (40 CFR Part 51 AppendixPage 12 of 92

Y) list sulfur dioxide (SO 2 ), oxides of nitrogen (NO x ), and particulate matter (PM) as visibility impairing pollutants. The significance thresholds for SO 2 and NO x are each 40 tpy, the significance thresholds for PM, PM 10 , and PM 2.5 are 25, 15, and 10 tpy, respectively. Emissions of SO 2 , NO x , PM, PM 10 , and PM 2.5 from FCPP exceed those significance thresholds. EPA has determined that i t is necessary or appropriate to address emissions of NO x and particulate matter, but not SO 2 , in this BART determination.

On May 7, 2007, EPA published in the Federal Regis ter the final rule for a source-specific Federal Implementation Plan (FIP) f or FCPP (72 FR 25698). The purpose of the 2007 FIP was to make federally enfor ceable significant emissions reductions of SO 2 , from 72% to 88% control, and to federalize emissi ons limitations which FCPP has historically followed for NO x , PM, opacity, and control measures for dust. Thus, the 2007 FIP did not require emissions reductions in the context of BART for NO x and PM. NO x emission limits in the FIP were 0.85 lb/MMBtu (Uni ts 1 and 2) and 0.65 lb/MMBtu (Units 3 – 5). The FIP included PM e mission limits of 0.05 lb/MMBtu from all units and a 20% opacity limit from Units 4 and 5, and dust emissions from any crusher, grinding mill, screening operation, belt c onveyor, or truck unloading or loading operation were limited to 20% opacity. For the inc rease in SO 2 control federalized in the FIP, EPA determined that the 88% SO 2 control was “close to or equivalent” to BART. This would decrease SO 2 emissions 57% from historical levels, resulting in a reduction of approximately 22,000 tons per year. These SO 2 reductions began in 2004 and the early implementation of the reductions factored into EPA’ s determination. Under the Tribal Authority Rule, EPA promulgates provisions as are n ecessary or appropriate to protect air quality. Because SO 2 has been reduced by 88%, and the reductions were m ade federally enforceable in 2007, EPA has determined SO 2 control to be “close to or equivalent” to BART.

D. Advanced Notice of Proposed Rulemaking and EPA A pproach to Consultation with Affected States, Tribes, and FLMs

On August 28, 2009, EPA published in the Federal Re gister an Advanced Notice of Proposed Rulemaking (ANPRM) that put forth our a nalyses regarding the anticipated visibility improvements at surrounding Class I area s and the cost effectiveness of controls for BART at FCPP and Navajo Generating Station (NGS ) and requested comment on our analyses as well as the analyses completed by APS f or FCPP and SRP for NGS. The publication of the ANPRM provided an opportunity to begin formal consultations with affected Tribes and continued an on-going consultat ion with the Federal Land Managers (FLMs) as required under the RHR (40 CFR §51.308(h) (4)(i)(2)). We will continue to consult with the Tribes and the FLMs during the com ment period for this proposal.

EPA received over 6,000 comments on the ANPRM, most of which were generalized electronic mail messages in support of reducing emissions. All substantive comments and examples of the generalized electronic mail messages have been posted to our docket for the ANPRM. Comment letters generall y focused either on both FCPP and NGS, or solely on NGS. Any comments received perta ining to NGS will not bePage 13 of 92

addressed in this proposal and will be discussed in our separate, subsequent BART proposal for NGS.

We received comments from six tribes located in Ari zona and the Inter Tribal Council of Arizona, Inc. Generally, comments from the tribes highlighted EPA’s trust responsibility to protect the economic interests of Indian Tribes and to assure that tribal concerns and interests are considered 4 and EPA’s responsibility to engage in meaningful consultation with tribal officials. EPA responded to all tribal requests for consultation as well as opportunities for on-going consultation, an d provided an extension to tribes to submit comments on the ANPRM by March 1, 2010. The relationship between the Arizona Tribes and water rights, as well as the rel ationship between the Kayenta Coal Mine and the Hopi Tribe apply only to NGS and will not be addressed here. The Navajo Nation and the Salt River Pima Maricopa Indian Comm unity submitted comments on the potential impacts of BART at FCPP and NGS on their economies. The concerns specific to FCPP raised by the Navajo Nation and the Salt Ri ver Pima Maricopa Indian Community are discussed in Section 4.D of this Tech nical Support Document.

In addition to tribes, we received numerous substan tive comments from State environmental agencies and the Federal Land Manager s for the impacted Class I areas. Several owners of FCPP: APS, Tucson Electric Power Company, and Public Service Company of New Mexico, as well as other industry an d utility groups, including Electric Power Research Institute (EPRI) and Utility Air Reg ulatory Group (UARG) submitted comments that included concerns regarding modeling inputs, visibility metrics, cost estimates, and economic impacts on the Four Corners area and Tribes. Additionally, we received comments specifically focused on the impac ts of SCR at NGS on water cost to Arizona cities and tribes from the Central Arizona Project, the U.S. Bureau of Reclamation, and the U.S. Bureau of Indian Affairs. Comments related to water rights in Arizona do not pertain directly to this proposed BA RT determination for FCPP and will not be discussed further in this Technical Support Document (TSD).

A consortium of environmental and Navajo community organizations 5 (Consortium) submitted comments on the estimates of cost and cost effectiveness at both facilities, visibility modeling, and additional ben efits of stringent controls on reducing ozone and nitrogen deposition. The remainder of th e comments we received on the ANPRM came from local community-based organizations , city governments, municipalities, and State and U.S. Representatives in Arizona concerned about impacts of SCR on NGS to water cost, and private citizens writ ing on their own or in association with “Take Action” campaigns by the Sierra Club or the National Parks Conservation Association. The majority of citizen comments were general “Take Action” comment letters supportive of stringent controls at both fa cilities, but we also received numerous citizen comments against stringent controls. Most of the comments we received against

4 EPA Policy for the Administration of Environmental Programs on Indian Reservations (November 8, 1984)
5 Center for Biological Diversity, Dine CARE, Dooda (NO) Desert Rock, Environmental Defense Fund, Grand Canyon Trust, Clean Air Counsel – National Parks Co nservation Association, Natural Resources Defense C ouncil, San Juan Citizens Alliance, Sierra Club, and Wester n Resource Advocates.Page 14 of 92

stringent controls were concerned about costs to co nsumers and generally did not provide comments specific to the five-factor analysis.

We have carefully considered all comments, but will not be issuing a Response to Comments on the comments received on the ANPRM. We have included responses in this technical support document only to comments we relied on to revise or justify our analyses and on substantive comments resulting from our consultation with Tribes, State Air Pollution Control Agencies, and the Federal Lan d Managers of the affected Class I

areas.

In our final determination, EPA will respond to com ments submitted on this proposal, but will not respond to comments submitte d on the ANPRM. Those who submitted comments on the ANPRM will need to resubm it comments on the proposal in order for EPA to consider those comments in finaliz ing this FIP.



### 2. Technology Available

A. FCPP Approach to This Factor

APS provided results of a BART engineering and cos t analysis for the FCPP conducted by Black and Veatch (B&V). Sixteen option s were identified as available retrofit technologies to control NO x . Generally, NO x control techniques utilize 1) combustion control to reduce the production of NO x from fuel-bound nitrogen and high temperature combustion, 2) post-combustion add-on c ontrol to reduce the amount of NO x emitted in flue gas by converting NO x to N 2 , or 3) a combination of combustion and postcombustion controls. APS identified six of these c ontrol options as technically feasible for all five units at FCPP. B&V presented the NO x Control Options, Description, and Technical Feasibility recommendations generally in a bottom-up approach and did not provide control efficiency information for technolo gies they excluded as technically infeasible. EPA revised the format of the informat ion presented (see Table 3 for NO x and Table 4 for PM) to be organized in top-down format and to provide estimate control efficiencies of all technologies listed, if the inf ormation was available. The control efficiency estimates were provided here to confirm that B&V did not exclude top-ranked technologies as infeasible. EPA was unable to dete rmine control efficiencies or additional information for several technologies lis ted, e.g., biotechnological denitrification. Although one PM control technolog y, GE-MAX-9 is claimed to have a higher control efficiency than the three technologi es not determined by B&V to be technically infeasible, GE-MAX-9 has only been demo nstrated in a pilot demonstration.Page 15 of 92

Table 3: Analysis of Available NO x Control Options for FCPP Presented by B&V for APS NO x Control Option Description B&V Technical Feasibility Recommendation Possible % Control Selective Catalytic Reduction (SCR) Ammonia or urea injection in the presence of a cata lyst to reduce NO x to N 2 . Yes 90 – 95% 6

LoTO x Oxidation of NO x with ozone to form nitrogen pentoxide

(N 2 O 5 ), which is scrubbed by the wet flue gas desulfurization (FGD) unit. No, no large operation units with this technology. 70 – 95% 7

THERMALONO x Process Elemental phosphorus is injected into the flue gas to react

with oxygen to form ozone. Similar to LoTO x , the ozone oxidizes NO x to N 2 O 5 which is removed in the wet FGD. No, not currently in similar type or size facilities. Up to 90% 8

SNCR/SCR Hybrid SNCR system with high ammonia slip followed by smal l catalyst that provides further reductions of NO x and

ammonia slip. No, technology has not been demonstrated on large units (Units 4-5), and no available room for ductwork expansion at economizer outlet (Units 1-3). 50 – 75% 9

High Energy Reagent Technology (HERT) OFA coupled with reagent injection. The reagent bre aks

down to ammonia to reduce NO x but functions in a different temperature window compared to SNCR. Yes 50 - up to 65% 10

Natural Gas Reburn Three combustion zones are used to reduce NO x emissions.

A reburn zone, fired with natural gas burners, redu ces NO x to N 2 by stripping oxygen from NO x to convert CO to CO 2 . No, not currently in similar type or size facilities. 65% when combined with LNB 11 Oxygen Enhanced Combustion Pure oxygen is used to stage combustion with higher local flame temperatures and higher local oxygen inlet concentrations to reduce NO x and unburned carbon. No, not currently in similar type or size facilities. Up to 60% 12

Induced Flue Gas Recirculation Recirculation of flue gas into the combustion zone to

reduce peak flame temperatures to reduce thermal NO x

production. No, technology not applicable to coal-fired plants, especially pulverized coal boilers. ~ 60% 13

Rotating Opposed Firing Air (ROFA) and ROTAMIX ROFA modifies OFA by adding rotation to improve

mixing with the flue gas. The ROTAMIX system adds u rea to the flue gas by injection with boosted air. In t he appropriate temperature range, urea reduces NO x to N 2 . Yes – Units 1-3, No – Units 4-5 because ROTAMIX has not been demonstrated on large

units. 40 – 60%

Selective Noncatalytic Reduction (SNCR) Ammonia or urea injection without use of a catalyst to reduce NO x to N 2 . Yes 30 – 50% 14

Low NO x Burners and Overfire Air Systems (OFA) LNB plus staged combustion such that excess air in the

burner zone is reduced and additional air is added above the burner zone to complete combustion. Yes 35 – 63% 15

Low NO x Burners Burner modification to stage combustion by controll ing air Yes 35 – 63% 16

6 Multipollutant Emission Control Technology Options for Coal-Fired Power Plants, EPA-600/R-05/034, EPA Contract No. 68-C-99-201, Work Assignment 6-13, Mar ch 2005.
7 Multipollutant Emission Control Technology Options for Coal-Fired Power Plants, EPA-600/R-05/034, EPA Contract No. 68-C-99-201, Work Assignment 6-13, Mar ch 2005.
8 Multipollutant Emission Control Technology Options for Coal-Fired Power Plants, EPA-600/R-05/034, EPA Contract No. 68-C-99-201, Work Assignment 6-13, Mar ch 2005.
9 Pfaff, Dale and Abrams, Rich, 2006. Hybrid SNCR/I n-Duct SCR System. Presentation to the Environmenta l Controls Conference, Pittsburgh, PA.
10 http://www.advancedcombustion.net/hert.html
11 Evaluation of Gas Reburning and Low-NOx Burners on a Wall-Fired Boiler A DOE Assessment. DOE/NETL2001/1143, February 2001.
12 Bool, LE., and Bradley J. NOx Reduction From a 44 MW Wall-Fired Boiler Utilizing Oxygen Enhanced Combustion. 2003 Mega Symposium.
13 http://www.epa.gov/appcdwww/aptb/nox.htm
14 EPA Air Pollution Control Fact Sheet EPA-452/F03-0 31
15 Srivastava et al., 2005. Journal of the Air and Wa ste Management Association.Page 16 of 92 (LNB) and fuel flow to create fuel-rich/O 2 -poor conditions in the

burner and high temperature zones. Reduces the form ation

of fuel NO x . Combustion Optimization System (COS) Computer hardware and software technology using rea ltime operational data to reduce emissions while imp roving plant performance by adapting to changes in plant

operation. Yes 15%

NO x Star and NO x Star Plus NO x Star is a trademark name for the injection of ammon ia

and a hydrocarbon (i.e., natural gas) in the flue g as. The ammonia reduces NOx to N 2 , and the hydrocarbon reduces

ammonia slip. No, not currently marketed, but would be expected to achieve similar results as SNCR with lower NH3 slip. Not known 17

ECOTUBE Hybrid of Separated OFA (SOFA) and ammonia or urea

injection, where ammonia or urea injected through retractable lances into the gas flow to improve mix ing and

combustion characteristics. No, no existing installations exist on similar type or sized facilities, but would be expected to achieve similar results as SNCR with lower NH3 slip. Not known

Biotechnological Denitrification (BioDeNO x ) An iron chelate is added to the wet FGD to react wi th NO

to form a nitrogen compound that dissolves in the F GD liquid. A catalyst is used to convert the dissolved nitrogen

compound to N 2 . No, not currently in similar type or size facilities. Not known

B&V identified seven options as available retrofit technologies to control particulate matter (PM) (See Table 4). Typically, PM controls r ely on post-combustion capture of PM.

16 Srivastava et al., 2005. Journal of the Air and Wa ste Management Association.
17 For those labeled “Not known”, EPA was unable to f ind information on control efficiencies from this t echnology.Page 17 of 92

Table 4: Analysis of Available PM and Control Optio ns for FCPP Units 1 – 3 Presented by B&V for APS PM Control Option Description B&V Technical Feasibility Recommendation Possible % Control Dry Electrostatic Precipitator (ESP) ESPs use electrical fields to negatively charge PM for

collection onto grounded plates by electrical attra ction. The collection plates are periodically cleaned by mechanical rappers and PM are collected and removed by

the ash handling system. Yes 99 – 99.9%

Wet ESP Operates on same theory as dry ESP, but collection plates are flushed with water to remove the PM. Yes 99 – 99.9%

Pulse Jet Fabric Filter (PJFF) PM is collected onto fabric filter bags. PM are cle aned

from the bags by a pulse of air and removed by the ash

handling system. Yes 99 – 99.9%

GE-MAX-9 Hybrid This technology involves an ESP using fabric filter bags instead of collection plates. PM are cleaned from t he bags by a pulse of air and removed by the ash handling s ystem. No, not demonstrated on large size boiler units. 99.999% 18

Compact Hybrid Particulate Collector (COHPAC) COHPAC involves a fabric filter with a high air to cloth ratio, and thus a smaller footprint. No, ineffective for use with venturi scrubbers. 99+% in a dry gas stream

Multiple Cyclone Multiple cyclones use several cyclones operated in parallel

that remove PM from the gas stream by centrifugal f orce and the inertia of PM. No, the addition of multiple cyclones to existing venturi scrubbers is not expected to provide additional PM control. 70 – 90%

PM Agglomeration Upstream of Dry ESP Upstream of a dry ESP, a bipolar charger alternatel y

charges PM with a positive or negative charge. Oppo sitely charged PM will be attracted and agglomerate to for m larger PM that are more effectively captured by the ESP. No, not demonstrated effective upstream of venturi scrubbers. Not known

B. Discussion of Factor in ANPRM

In our ANPRM, we focused on cost effectiveness and visibility improvement from two NO x control options: SCR, the most stringent level of control, and LNB, a midlevel control option. Additionally, we discussed f our PM control options (three types of ESPs and one type of baghouse) that are all project ed to achieve the same controlled emission rate. We did not provide detailed informa tion in our ANPRM on all of the technologies discussed by B&V and their technologic al feasibility determinations for NO x and PM, but the APS/B&V report was included in the ANPRM docket.

However, in the ANRPM, we questioned the capabilit y of obtaining significant NO x reductions from LNB retrofits at FCPP. In associa tion with our discussion of Factor 5: Existing Air Pollution Control at the Source, we stated that FCPP has had limited success in retrofitting their boilers with LNB tech nology. When Unit 2 was retrofit in the 1990s, FCPP encountered significant operational pro blems with the boiler. This led FCPP to decide against retrofit of Unit 1, which wa s identical to Unit 2, because of the operational difficulties with Unit 2. For Units 4 and 5 that were originally equipped with cell burners, the inherent design of these boilers makes it difficult to achieve any significant reduction in NO x through burner retrofit technology. Based on the inherent

18 http://www.gepower.com/prod_serv/products/particul ate_matter/en/max9/index.htmPage 18 of 92

design of Units 1 – 5, we stated in our ANPRM that LNB retrofit of these units would provide only limited NO x control, and we requested comment on this determin ation.

APS submitted two different reports concerning the potential for NO x reductions at FCPP. The first report written by Andover Techn ology Partners entitled: “Assessment of Potential for Further NO x Reduction by Combustion-Based Control at the Four Corners Steam Electric Station”, dated April 5, 200 4 (Andover Report), was submitted by APS by letter dated August 7, 2009, per EPA request prior to the publication of the ANPRM. The Andover Report outlined the challenges associated with LNB and OFA retrofits on each unit, including boiler design and size, and FCPP coal characteristics. Although four different technology suppliers claime d they could achieve NO x reductions with burner retrofits, the Andover Report concluded that LNB retrofits were not likely to be beneficial for the boilers at FCPP because the r isk of adverse operational side effects outweighed the potentially modest improvement in em issions performance. Even for Units 4 and 5, where retrofit with LNB+OFA might re sult in some improvement in NO x performance (approaching 0.40 lb/MMBtu), the Andove r Report did not recommend burner retrofits because potential operational prob lems on the two largest units at FCPP was not worth the small incremental reduction in NO x emissions.

A subsequent report prepared by APS and submitted to EPA as Attachment J of their October 28, 2009 comment letter on the ANPRM, indicated that Units 1 and 2 could achieve 0.40 lb/MMBtu, Unit 3 could achieve 0.32 lb /MMBtu with LNB retrofit, and Units 4 and 5 could achieve 0.35 lb/MMBtu with a co mbination of LNB + OFA retrofit. APS cited examples of several boilers with LNB or L NB+OFA retrofits that achieve emission rates of 0.4 lb/MMBtu or below.

EPA Clean Air Markets Division (CAMD) evaluated th e examples from Attachment J of boilers APS stated are achieving 0. 4 lb/MMBtu or better, to assess the emissions reductions that have been achieved with m odern combustion modification retrofits on those boilers. CAMD concluded that tho se boilers have achieved NO x emissions of approximately 0.4 lb/MMBtu, but could not determine if these boilers were indeed representative of Units 1 – 3 at FCPP. APS did not provide enough information in Attachment J to assess the level of similarity.

Based on the operational difficulties experienced by Unit 2 subsequent to its 1999 retrofit, the information provided in the Andover R eport regarding operational risks associated with LNB/OFA retrofits, and the uncertai n comparability of the boilers at FCPP with boilers that have achieved 0.4 lb/MMBtu f ollowing LNB/OFA retrofit, EPA has determined that LNB and LNB+OFA is not capable of achieving the level of NO x control needed for BART for one of the nation’s lar gest NO x sources, located on the Colorado Plateau and affecting visibility at sixtee n Class I areas.

C. Affected State, Tribe, and FLM ConsultationPage 19 of 92

We did not receive comments from affected States o r Tribes on additional NO x or PM control options to consider. NPS commented that APS should have evaluated tailend SCR configuration (SCR downstream of all pollut ion control equipment). The downstream air pollution control equipment, particu larly the baghouses and wet FGDs, provide significant control of the additional H 2 SO 4 formed from SO 2 to SO 3 conversion on the SCR catalyst. For example baghouses are exp ected to provide 90% control of H 2 SO 4 and the wet FGD is expected to provide 53% control of H 2 SO 4 (see Section 7 of this technical support document). If the SCR were placed downstream of all other control equipment, the loss of the mitigating affec ts of sulfuric acid control in the venturi scrubbers, air preheaters, wet FGDs, or baghouses w ould result in greater emissions of sulfuric acid from the stack. Sulfuric acid also i mpacts visibility because it contributes to ammonium sulfate formation. This would offset the visibility improvement from the NO x reductions gained from applying SCR. EPA conclude s that tail-end SCR would result in significantly higher sulfuric acid emissi ons which would reduce the visibility improvement resulting from SCR and could potentiall y increase visibility impairment. Therefore, EPA did not evaluate tail-end SCR for th is proposal.

D. EPA Conclusions regarding This Factor

For the control of NO x emissions, EPA has determined that B&V has identif ied the available NO x control technologies. See Table 3. In conducting our BART analysis, EPA used the analogous top-down approach of Best Av ailable Control Technology (BACT) analyses for Prevention of Significant Deter ioration (PSD) permits, which starts with the evaluation with the top-ranked technology, in this case, SCR. B&V eliminated technologies that they determined were technically infeasible prior to reporting the control efficiencies and costs of those technologie s. Therefore, in order to confirm the technologies eliminated by B&V do not provide more NO x control than SCR, EPA used available estimates of NO x control efficiencies (see footnotes to Table 3) to produce an initial ranking for all the technologies in Table 3 . We relied on our estimates of control efficiencies only to rank the technologies and rely on B&V’s control efficiency determinations for estimating cost effectiveness of controls. Based on the available information EPA determined that SCR is the most str ingent NO x control option and B&V did not eliminate as technically infeasible any opt ions that are more stringent than SCR. Generally, LNB and LNB+OFA can be applied in additi on to SCR, such that the combination of combustion controls and post-combust ion controls can be expected to result in the most stringent level of control.

Based on our evaluation of the information provide d in the Andover Report and the lack of support in Attachment J provided by APS that Units 1 – 3 are similar to other boilers that have been successfully retrofit with L NBs, EPA determined that combustion controls are not effective control technologies at FCPP due to the inherent limitations of the existing boilers on all units. Therefore, EPA determined that LNB and LNB+OFA are not capable of achieving the level of NO x control needed for BART for one of the nation’s largest NO x sources and we start our five-factor evaluation wi th SCR (without combustion controls). However, although EPA has det ermined that LNB and LNB+OFAPage 20 of 92

will not achieve the reductions claimed by APS, we include the costs and visibility benefits from LNB/LNB+OFA in this technical support document to contrast the anticipated costs and visibility benefits of the mo st stringent control technology with the controls APS recommended as BART for FCPP. Because we started our analysis with the top-ranked control, we are not providing furthe r evaluation of the technical feasibility recommendations made by B&V.

For the control of PM emissions from the boilers, EPA has determined that B&V properly identified the following options as techni cally feasible for FCPP: Dry and Wet Electrostatic Precipitators (ESP) and Fabric Filter s (baghouses). See Table 4. For Units 4 and 5, EPA has determined that APS does not need to install new controls in addition to the baghouses currently in place but would be requi red to operate the baghouse to meet an emissions limit of 0.015 lb/MMBtu. We are also requesting comment on continuing to allow FCPP to use venturi scrubbers on Units 1 – 3 to meet a lower emission limit of 0.03 lb/MMBtu and 20% opacity.



### 3. Costs of Compliance

In assessing the cost of compliance, the analyses by B&V examined the total and annual costs of the control technologies, as well a s the cost effectiveness of controls, in terms of 2008 dollars per ton of pollutant removed ($/ton ) and cost of the visibility improvement, in terms of dollars per average deciview improvement ( $/dv). The cost effectiveness of controls should be calculated using emissions based on an an nual average emission rate, whereas the degree of visibility improvement should be calculat ed using emissions based on the highest 24-hour emission rate (Appendix Y to 40 CFR Part 51 , “Guidelines for BART Determinations Under the Regional Haze Rule” IV.D.4 .b. and IV.D.5.; “Regional Haze Regulations and Guidelines for Best Available Retro fit Technology (BART) Determinations; Final Rule”, 70 FR 39170, July 6, 2005). In this s ection, we will discuss the estimates of total and annual cost of control and the cost effec tiveness of control. The degree of visibility improvement will be discussed in Section 7.

A. FCPP Approach to This Factor

B&V conducted the cost of compliance analysis usin g the EPA Coal Utility Environmental Cost (CUECost) program 19 , information supplied by equipment vendors, estimates from previous projects, and projected cos ts from FCPP. The CUECost model is not equivalent to the EPA Control Cost Manual , and is not the recommended model in the BART guidelines. CUECost estimates costs for i nstallation and operation of various pollutant control technologies, and relies upon use r-inputs for variables that determine cost. APS submitted cost estimates in January 2008 and submitted revised cost estimates on March 16, 2009 to reflect higher costs of constr uction services and materials 20 (See

19 http://www.epa.gov/ttn/catc/products.html
20 APS-FCPP did not include revised cost estimates fo r ROTAMIX, ROTAMIX + LNB, ROFA, and ROTAMIX + ROFA in their March 16, 2009 revised estimates.Page 21 of 92

Table 5). The March 16, 2009 submittal from APS is based on B&V cost revisions dated August 19, 2008. Table 6 lists the 2008 costs prov ided by B&V, but reformatted by EPA to be listed in top-down order, with several footno tes listing previous cost estimates where the increase in cost was particularly large. Although we are focusing on the topranked control (SCR without combustion controls) an d comparing that with APS’s BART recommendation, we included cost and percent c ontrol information for the other control technologies, for informational purposes. T he NO x emission rates and % NO x reductions are shown in Table 6 and the total estim ated NO x reductions (in tons per year) and cost effectiveness are shown in Table 7.

Table 5: Projected Costs (dated August 2008) for NO x Control Estimated by B&V
NO x Control Total Capital and Annual Costs 21 Unit 1 Unit 2 Unit 3 Units 4, 5 (each)

SCR Total Capital Investment 22 $110,664,000 $119,010,000 $113,084,000 $265,406,000

Total Annual Cost ($/yr) 23 $22,297,000 $23,634,000 $23,173,000 $55,755,000
LNB + OFA + HERT Total Capital Investment $10,762,000 $10,762,000 $10,076,000

Total Annual Cost ($/yr) $2,816,000 $2,816,000 $2,961,000
ROTAMIX + ROFA Total Capital Investment $13,672,000 $13,532,000 $13,689,000

Total Annual Cost ($/yr) $4,223,000 $4,191,000 $4,858,000
SNCR + LNB + OFA Total Capital Investment $15,070,000 $15,360,000 $15,626,000 $39,084,000

Total Annual Cost ($/yr) $3,785,000 $3,851,000 $4,210,000 $11,221,000
ROFA Total Capital Investment $9,657,000 $9,657,000 $10,705,000

Total Annual Cost ($/yr) $2,956,000 $2,956,000 $3,406,000
ROTAMIX + LNB Total Capital Investment $11,105,000 $11,105,000 $11,215,000 Total Annual Cost ($/yr) $3,508,000 $3,508,000 $3,536,000
SNCR + LNB Total Capital Investment $13,796,000 $14,104,000 $15,409,000 $34,088,000 Total Annual Cost ($/yr) $3,849,000 $3,918,000 $4,520,000 $11,503,000
LNB + OFA Total Capital Investment $5,752,000 $5,752,000 $4,701,000 $15,260,000 Total Annual Cost ($/yr) $1,293,000 $1,293,000 $1,055,000 $3,447,000
LNB Total Capital Investment $4,109,000 $4,109,000 $3,999,000 $8,828,000

Total Annual Cost ($/yr) $922,000 $922,000 $897,000 $1,991,000
ROTAMIX Total Capital Investment $7,282,000 $7,282,000 $7,436,000 Total Annual Cost ($/yr) $4,277,000 $4,277,000 $4,311,000
SNCR Total Capital Investment $10,866,000 $10,742,000 $12,137,000 $25,890,000

Total Annual Cost ($/yr) $4,314,000 $3,941,000 $4,536,000 $10,668,000
COS Total Capital Investment $1,429,000 $1,429,000 $1,429,000 $1,577,000

Total Annual Cost ($/yr) $314,000 $314,000 $314,000 $348,000

21 These estimates of Total Annual Cost by B&V do not include the 1.45129 Levelization Factor used by B& V.
22 From 2007 B&V Cost estimates submitted by APS to E PA January 2008: Total Capital Investment for SCR: Unit 1 = $88,235,000, Unit 2 = $94,216,000, Unit 3 = $96 ,690,000, Unit 4 or 5 = $242,090,000.
23 From 2007 B&V Cost estimates submitted by APS to E PA January 2008: Total Annual Cost for SCR: Unit 1 = $18,056,000, Unit 2 = $18,966,000, Unit 3 = $19,957 ,000, Unit 4 or 5 = $51,487,000.Page 22 of 92

Table 6: NO x Emission Rates and Percent Reductions Estimated by B&V
NO x Control (#) Emission Rates and % Reductions 24 Unit 1 Unit 2 Unit 3 Units 4, 5 (each)

Baseline Emission (lb/MMBtu) 0.78 0.64 0.59 0.49
SCR Expected Emission rate (lb/MMBtu) 0.08 0.06 0.06 0.06

% NO x reduction from baseline 89.7% 90.6% 89.8% 87.8%
ROTAMIX + ROFA Expected Emission rate (lb/MMBtu) 0.19 0.19 0.19

% NO x reduction from baseline 75.6% 70.3% 67.8%
LNB + OFA + HERT Expected Emission rate (lb/MMBtu) 0.20 0.20 0.20

% NO x reduction from baseline 74.3% 68.8% 66.1%
SNCR + LNB + OFA Expected Emission rate (lb/MMBtu) 0.26 0.26 0.26 0.26

% NO x reduction from baseline 66.7% 59.4% 55.9% 46.9%
ROFA Expected Emission rate (lb/MMBtu) 0.28 0.28 0.28

% NO x reduction from baseline 64.1% 56.3% 52.5%
ROTAMIX + LNB Expected Emission rate (lb/MMBtu) 0.30 0.30 0.30
% NO x reduction from baseline 61.5% 53.1% 49.2%
SNCR + LNB Expected Emission rate (lb/MMBtu) 0.32 0.32 0.32 0.32

% NO x reduction from baseline 59.0% 50% 25 45.8% 26 34.7%
LNB + OFA Expected Emission rate (lb/MMBtu) 0.33 0.33 0.33 0.35

% NO x reduction from baseline 57.7% 48.4% 44.1% 28.6%
LNB Expected Emission rate (lb/MMBtu) 0.43 0.43 0.43 0.45

% NO x reduction from baseline 44.9% 32.8% 27.1% 8.2%
ROTAMIX Expected Emission rate (lb/MMBtu) 0.56 0.45 0.45

% NO x reduction from baseline 28.2% 29.7% 23.7%
SNCR Expected Emission rate (lb/MMBtu) 0.56 0.46 0.46 0.38

% NO x reduction from baseline 28.2% 28.1% 22% 22.4%
COS Expected Emission rate (lb/MMBtu) 0.72 0.6 0.56 0.47

% NO x reduction from baseline 7.7% 6.3% 5.8% 4.1%

24 Percent reductions were calculated from the expect ed change in emission rate (lb/MMBtu) compared to b aseline.
25 Table 6-3 of the 2007 B&V BART Analysis for FCPP s ubmitted by APS in January 2008 presents cost and emission estimates twice for New LNBs, OFA, and SNC R. We assume the higher emission rate of the two ac tually corresponds to New LNBs and SNCR.
26 Table 6-4 of the 2007 B&V BART Analysis for FCPP s ubmitted by APS in January 2008 presents cost and emission estimates twice for New LNBs, OFA, and SNC R. We assume the higher emission rate of the two ac tually corresponds to New LNBs and SNCR.Page 23 of 92

Table 7: NO x Reductions and Cost Effectiveness of Controls Esti mated by B&V
NO x Control Unit 1 Unit 2 Unit 3 Unit 4, 5 (each)

TPY NO x reduced Cost

($/ton) TPY NO x

reduced Cost

($/ton) TPY NO x

reduced Cost

($/ton) TPY NO x

reduced Cost

($/ton)
SCR 5,134 27 4,343 4,310 5,484 5,057 4,582 11,445 4,872
ROTAMIX + ROFA 4,318 978 3,368 1,244 3,809 1,275

LNB + OFA + HERT 4,245 663 3,293 855 3,713 797

SNCR + LNB + OFA 3,808 994 2,844 1,354 3,137 1,342 6,171 1,818

ROFA 3,662 807 2,695 1,097 2,945 1,157
ROTAMIX + LNB 3,517 997 2,545 1,378 2,753 1,284

SNCR + LNB 3,371 1,142 2,396 1,635 2,561 1,765 4,589 2,507

LNB + OFA 3,298 392 3,298 392 2,465 428 3,798 908
LNB 2,569 359 2,569 359 1,505 596 1,160 1,716
ROTAMIX 1,622 2,637 1,425 3,001 1,313 3,283
SNCR 28 1,622 2,660 1,349 2,921 1,217 3,727 3,138 3,400
COS 456 689 302 1,040 257 1,222 633 550

In their analysis, B&V state that Units 1 and 2 at FCPP have relatively small furnace volumes compared to other wall-fired furnac es, which make the use of staged combustion for LNBs and OFA more challenging. Addit ionally, B&V state that SCR retrofits of Units 1 – 3 are costly and difficult b ecause the existing air heater arrangements for Units 1 – 3 would require new air heaters, and new forced draft (FD) and induced draft (ID) fans. For the retrofit of Un its 4 and 5 with SCR, B&V states that the arrangement and corresponding ductwork of the p rimary and secondary air heaters makes the retrofit costly and complicated.

B&V examined the emissions reductions and cost eff ectiveness for four PM control scenarios for Units 1 – 3 (See Table 8). Be cause Units 4 and 5 have existing reverse gas fabric filters for PM control, B&V dete rmined that these units already meet the most stringent emissions control.

27 SCR cost effectiveness based on original (January 2008) cost estimates: Unit 1 = $3,517/ton, Unit 2 = $4,401/ton, Unit 3 = $3,947/ton, and Units 4 or 5 = $4,499/ton.
28 SNCR cost effectiveness based on original (January 2008) cost estimates: Unit 1 = $1,925/ton, Unit 2 = $2,029/ton, Unit 3 = $2,549/ton, and Units 4 or 5 = $2,336/ton.Page 24 of 92

Table 8: Cost Estimates and Emissions Reductions fo r PM Estimated by B&V ESP Upstream of add-on controls PJFF Upstream of

add-on controls Metal ESP

Downstream of Venturi Scrubber Membrane ESP

Downstream of Venturi Scrubber

Unit 1

Baseline = 0.025 lb/MMBtu Total Capital Investment ($) $37,236,000 $50,515,000 $32,136,000 $23,360,000

Total Annual Cost ($/yr) $10,169,000 $13,950,000 $8,781,000 $5,652,000 Estimated PM (lb/MMBtu) 0.012 0.012 0.012 0.012 % PM Reduction from Baseline 52% 52% 52% 52%
Additional TPY PM Reduced 94 94 94 94 Cost Effectiveness ($/ton) $108,370 $148,659 $93,571 $60,231

Unit 2

Baseline = 0.029 lb/MMBtu Total Capital Investment ($) $45,702,000 $60,992,000 $32,879,000 $23,901,000

Total Annual Cost ($/yr) $11,011,000 $14,481,000 $8,972,000 $6,658,000 Estimated PM (lb/MMBtu) 0.012 0.012 0.012 0.012 % PM Reduction from Baseline 58.6% 58.6% 58.6% 58.6%
Additional TPY PM Reduced 129 129 129 129 Cost Effectiveness ($/ton) $85,092 $111,908 $69,335 $51,453
Unit 3

Baseline = 0.029 lb/MMBtu Total Capital Investment ($) $40,135,000 $59,594,000 $59,594,000 $26,988,000

Total Annual Cost ($/yr) $10,925,000 $16,559,000 $10,309,000 $7,557,000 Estimated PM (lb/MMBtu) 0.012 0.012 0.012 0.012 % PM Reduction from Baseline 58.6% 58.6% 58.6% 58.6%
Additional TPY PM Reduced 168 168 168 168 Cost Effectiveness ($/ton) $65,164 $98,770 $61,490 $45,075

B&V state that the four PM control scenarios are e xpected to control PM emissions from Units 1 – 3 down to 0.012 lb/MMBtu, which is equivalent to the current level of PM control on Units 4 and 5, which use rev erse gas fabric filters.

B. Discussion of Factor in ANPRM

In our ANPRM, we presented three sets of cost estim ates for SCR – costs estimated by B&V for APS, costs estimated by EPA ba sed on a revision to APS’s cost estimates to be more representative, and costs esti mated by the National Park Service (NPS) using the EPA Control Cost Manual (Table 9). For PM, EPA presented APS estimates for capital and annual costs and cost eff ectiveness, as well as EPA’s revision to the annual costs and cost effectiveness (Table 10). In the ANPRM, EPA only revised the total annual cost estimates for SCR and PM controls , not the total capital investment costs, presented by B&V. EPA determined that the a ssumptions, particularly the 15% pre-tax interest rate, used by B&V for calculating annualized costs were too high, resulting in ratios of total annual costs to total capital cost for NO x controls of approximately 0.20. Lower interest rates used by o ther facilities, for example, other coalfired power plants in Arizona, New Mexico, and Oreg on, resulted in annual to capital cost ratios of approximately 0.12 – 0.15 (See Table 11). Therefore, in the ANPRM, to provide a more representative estimate for annualiz ed costs and cost effectiveness, EPA applied an annual to capital cost ratio of 0.15. F inally, in the ANPRM, EPA also estimated the increase in electricity generation co sts from NO x and PM controls at FCPP in terms of dollar per kilowatt-hour ($/kWh). In t his TSD, we discuss increasedPage 25 of 92

electricity generation costs under Factor 3 – Energ y and Non-Air Quality Impacts (See Section 4).

Table 9: SCR Cost Estimates from ANPRM based on APS , EPA, and NPS Total Capital Costs B&V for APS EPA NPS

Unit 1 $110,664,000 EPA did not revise B&V Total Capital Cost estimates in the ANPRM $18,508,764
Unit 2 $119,010,000 $18,508,764
Unit 3 $113,084,000 $22,187,577
Unit 4 $265,406,000 $52,788,968
Unit 5 $265,406,000 $52,788,968
Total Annual Costs

Unit 1 $22,297,000 $16,599,600 $2,983,004
Unit 2 $23,634,000 $17,851,500 $3,052,010
Unit 3 $23,173,000 $16,962,600 $3,497,117
Unit 4 $55,755,000 $39,810,900 $9,838,997
Unit 5 $55,755,000 $39,810,900 $9,838,997 Cost Effectiveness ($/ton)

Unit 1 $4,343 $3,758 $1,558
Unit 2 $5,484 $4,803 $1,469
Unit 3 $4,582 $3,646 $1,684
Unit 4 $4,872 $4,341 $1,185
Unit 5 $4,872 $4,330 $1,357Page 26 of 92

Table 10: Cost Estimates for PM Control Presented i n ANPRM from APS and EPA Revisions Upstream ESP Upstream Baghouse Wet Metal ESP Wet Membrane ESP Total Capital Costs – B&V (EPA did not revise B&V’s cost estimates for PM in ANPRM)
Unit 1 $37,236,000 $50,515,000 $32,136,000 $23,360,000
Unit 2 $45,702,000 $60,992,000 $32,879,000 $23,901,000
Unit 3 $40,135,000 $59,594,000 $59,594,000 29 $26,988,000
Total Annual Costs – B&V Unit 1 $10,169,000 $13,950,000 $8,781,000 $5,652,000
Unit 2 $11,011,000 $14,481,000 $8,972,000 $6,658,000
Unit 3 $10,925,000 $16,559,000 $10,309,000 $7,557,000
Total Annual Costs – EPA
Unit 1 $5,585,400 $7,577,250 $4,820,400 $3,504,000
Unit 2 $6,855,300 $9,148,800 $4,931,850 $3,585,150
Unit 3 $6,020,250 $8,939,100 $8,939,100 $4,048,200
Cost Effectiveness – B&V
Unit 1 $106,571/ton $146,195/ton $92,024/ton $59,233/ton
Unit 2 $86,485/ton $113,739/ton $70,470/ton $52,294/ton
Unit 3 $67,785/ton $102,741/ton $63,963/ton $46,888/ton
Cost Effectiveness – EPA Unit 1 $60,691/ton $82,334/ton $52,378/ton $38,074/ton
Unit 2 $55,556/ton $74,143/ton $39,968/ton $29,054/ton
Unit 3 $16,074/ton $23,867/ton $23,867/ton $10,808/ton

29 This estimate was reported by APS in their Decembe r 2007 analysis. EPA believes this value was report ed by APS in error because it is unlikely a wet ESP would equal the cost of a baghouse for Unit 3, but not U nits 1 and 2.Page 27 of 92

Table 11: Comparison of Total Capital Investment (T CI) and Total Annual Costs (TAC) from Other Western Facilities

Facility Total Capital Investment ($) Total Annual

Cost ($) TAC/TCI

(%) Description

Four Corners Power Plant (Unit 1) 30 $110,664,000 $22,297,000 20% SCR Four Corners Power Plant (Unit 2) $119,010,000 $23,634,000 20% SCR Four Corners Power Plant (Unit 2) $113,084,000 $23,173,000 20% SCR Four Corners Power Plant (Unit 4-5) $265,406,000 $55,755,000 21% SCR Coronado Generating Station $145,000,000 $17,086,550 11.8% Combustion Controls + SCR San Juan Generating Station (Unit 1) 31 $156,805,000 $20,525,000 13.1% SCR San Juan Generating Station (Unit 2) $169,251,000 $21,891,000 12.9% SCR San Juan Generating Station (Unit 3) $215,568,000 $28,359,000 13.2% SCR San Juan Generating Station (Unit 4) $199,558,000 $26,592,000 13.3% SCR PGE Boardman 32 $269,500,000 $39,400,000 14.6% Phase 1: LNB (+ SNCR contingency)

PGE Boardman $154,300,000 $19,600,000 12.7% Phase 2: Additional SCR

The BART guidelines state that “[i]n order to impro ve consistency, cost estimates should be based on the OAQPS Control Cost Manual , where possible.” The OAQPS Control Cost Manual is now called the EPA Air Pollution Control Cost Manual . The EPA Air Pollution Control Cost Manual (Sixth Edition, January 2002) 33 provides guidance and methodologies for estimating the cost and economic feasibility of a project, with a nominal accuracy of ± 30%. The costs that ar e incorporated into estimates of capital and annual costs by the Control Cost Manual (CCM) are outlined in Section 1, Chapter 2 34 , which states that total capital costs may include equipment costs, freight, sales tax, and installation costs. For existing fac ilities, retrofit costs should also be considered, and may include auxiliary equipment, ha ndling and erection, piping, insulation, painting, site preparation, off-site fa cilities, engineering, and lost production revenue. Finally, annual costs are estimated from c osts of raw materials, maintenance labor and materials, utilities, waste treatment and disposal, replacement materials, overhead, property taxes, insurance, and administra tive charges.

In the cost analysis for FCPP, B&V provided line-i tem estimates for the direct and indirect capital costs, as well as direct and i ndirect annual costs. B&V included several costs that were not specifically described in the EPA Cost Control Manual

, including costs of unintended consequences and “own er’s costs”. The “owner’s costs” were described by B&V to include financing, project management, and construction support costs, as well as legal assistance, permits and offsets, and public relations costs.

30 Cost estimates based on 2008 dollars.
31 Based on 2007 dollars.
32 Based on 2007 dollars.
33 http://epa.gov/ttn/catc/products.html#cccinfo
34 Mussatti, D.C., and Vatavuk, W.M.. Section 1: Int roduction, Chapter 2: Cost Estimation: Concepts and Methodology. EPA/452/B-02-001, January 2002.Page 28 of 92

C. Affected State, Tribe and FLM Consultation

The Arizona Department of Environmental Quality (AD EQ) 35 commented that it is inappropriate to include projected costs of cont rols to consumers in our BART analysis without a description of the unusual circumstances that justify consideration of these costs. Additionally, ADEQ commented that we should justify our revision of APS’s cost according to the ratio of annual costs to the total capital investment of other facilities. New Mexico Environment Department (NMED) 36 , however, supported our revision of APS’s costs. NMED commented that we underestimated emissions reductions possible from SCR on Units 1 – 5, and further stated that Ap pendix Y takes into account the most stringent emission control level that the technolog y is capable of achieving, therefore we should not rely on a negotiated settlement of 75% c ontrol. NMED also encouraged review of additional PM control on Units 4 and 5, w hich can include improvement of existing controls, not just complete replacement.

The Navajo Nation 37 recommended that we accept the cost estimates prov ided by APS because the costs appeared to fall within the s cope of the BART guidelines. The Navajo Nation further recommended that EPA include an incremental cost analysis because of the potential importance the high increm ental costs of SCR may have on the final BART determination.

NPS 38 commented that based on data from the EPA Clean Ai r Markets Division, SCR retrofits result in controlled emissions of 0.0 5 lb/MMBtu. Therefore, NPS recommended setting NO x limits of 0.07 lb/MMBtu on a 24-hour basis, 0.06 l b/MMBtu on a 30-day rolling basis, and 0.05 lb/MMBtu on an annual average basis. NPS recommended using 0.05 lb/MMBtu for estimating annu al costs and determining cost effectiveness. Additionally, NPS commented that co st estimates for SCR provided by APS were not adequately justified and should have r elied on the EPA Control Cost Manual , rather than the CUECost Model and other proprieta ry databases. NPS used the EPA Control Cost Manual to estimate the cost of combustion controls plus S CR on all 5 units and provided revised cost estimates in their comments on the ANPRM.

35 Letter dated October 28, 2009 from Benjamin Grumbl es, ADEQ to EPA Docket Center.
36 Letter dated October 27, 2009 from Mary Uhl, NMED to Anita Lee, EPA.
37 Letter dated March 1, 2010 from President Joe Shir ley, Jr., Navajo Nation, to Anita Lee, EPA.
38 Letter dated November 11, 2009 from Michael Snyder , National Park Service, to Anita Lee, EPA.Page 29 of 92

Table 12: NPS’s Estimated Costs of Combustion Contr ols + SCR based on EPA Control Cost Manual reported in their comments on ANPRM 39

Unit 1 2 3 4 5 Total Rating (MW gross) 185 185 235 790 790 2185 Emissions Reductions 5,446 4,307 5,417 12,684 11,508 39,361

Capital Cost $52,793,277 $60,676,814 $54,026,747 $113,485,159 $113,945,854 $394,927,651 Capital Cost ($/kW) $285 $328 $230 $144 $144 $181
O&M Cost $1,896,917 $2,035,967 $2,270,190 $5,897,139 $5,804,109 $17,904,321
Total Annual Cost $7,221,813 $8,104,955 $7,528,210 $18,435,022 $18,385,478 $59,675,476
Cost Effectiveness ($/ton) $1,326 $1,882 $1,390 $1,453 $1,598 $1,516

D. EPA Conclusions Regarding This Factor

EPA contracted with EC/R Incorporated to conduct a detailed comparison of the capital and annual cost estimates presented by B&V against the EPA Control Cost Manual . The spreadsheets are included in the docket for this technical support document 40 . In general, as recommended by the Navajo Nation, EPA relied on APS’s own cost estimates, with the exception of any line item costs that are not explicitly included in the EPA Control Cost Manual or where EPA determined alternate costs were more appropriate, e.g., cost of catalysts, or inter est rates. See Table 13 for the list of revisions EPA made to the cost estimates from APS. The cost estimate spreadsheets are available in electronic format in the docket for th is proposal.

39 Based on 1998 Control Cost model with costs adjust ed for inflation from 1998 and 2007. See NPS Cost Estimate Spreadsheets submitted as comments to EPA on docket for ANPRM (Comment and Appendices #208 in ANPRM docket).
40 See Excel Spreadsheet titled “Four Corners SCR Cos t Analysis 8-26-10.xls”.Page 30 of 92

Table 13: Summary of EPA Revisions to B&V Cost Inpu ts for SCR on Unit 4 41

B&V/ APS EPA Revision EPA Rationale for Revision Initial Catalyst $7,941,000 $5,093,000 EPA used a low-oxidation catalyst cost of $5,500/m 3 based on quote from Hitachi Power

Systems. Variable Frequency Drive on ID or FD Fans Included Not Included Generally, a VFD is not required for operation of SCR and was excluded. Miscellaneous Equipment Included Not Included It was unclear what miscellaneous equipment represented and was excluded. Taxes (Direct Cost) 10% 6% CCM uses 6% as default tax rate. Tuning (Indirect Cost) Included Not Included CCM does not include this cost. Side Effect Mitigation (Other Capital Cost) Included Not Included Low oxidation catalysts were assumed, therefore side effect mitigation not needed.
Lost Revenue Included Not Included EPA assumes construction would occur during scheduled major outages.
Maintenance Labor & Materials 3% 1.5% CCM uses 1.5%.

Catalyst Replacement $3,154,000 $574,000 We recalculated catalyst replacement cost according to CCM recommendations. Catalyst Disposal Included Not Included Disposal costs are typically included in catalyst
costs. Side Effect Mitigation (Unintended Consequences) Included Not Included Low oxidation catalysts were assumed, therefore side effect mitigation not needed.
Interest Rate 15% 7% CCM uses 7% interest rate. This interest rate and the amortization period are then used to calculate a cost recovery factor.

APS submitted to EPA various revisions to their co st estimates. Initial cost estimates were provided to EPA in January 2008, wit h costs dated July 6, 2007. In a letter dated March 16, 2009, APS submitted revised cost estimates for SCR dated August 2008 that were higher than the previous submission to account for increased cost of materials. APS provided a third set of revised cos t estimates to EPA, via electronic mail on April 22, 2010, in a report written by Black and Veatch dated February 10, 2010. In the 2010 submission, costs estimate for Unit 1 – 3 are dated May 2008, whereas revised cost estimates were provided for Units 4 and 5 date d February 2010. The entire B&V report was claimed by APS as confidential. On Sept ember 9, 2010, APS confirmed to EPA that the report and the cost estimates are not confidential information. Therefore, EPA included this report in the docket 42 . The report provides updated cost estimates for Units 4 and 5 in 2010 dollars and cost estimate for Units 1 – 3 in 2008 dollars that differ from the August 2008 costs. EPA relied on the Augu st 2008 cost estimates, which are the highest of the cost estimates submitted to EPA (See Table 14). Thus, EPA’s revised cost information and our additional analyses that r ely on the capital and annual costs are conservatively overestimated.

41 Details for Units 1-3 and 5 are included in the sp readsheet. Unit 4 is used here as an example.
42 Four Corners Steam Electric Station Units 1 throug h 5 NO x Compliance Report, Revision D. Black and Veatch Corporation, Project Number 166861, February, 2010.Page 31 of 92

Table 14: Comparison of APS Cost Estimates Submitte d in 2009 and 2010 Total Capital Cost Total Annual Cost From March 2009 letter – costs dated August 2008 From February 2010

submission – costs dated May 2008 or February 2010 From March 2009 letter – costs dated August 2008 From February 2010

submission – costs dated May 2008 or February 2010
Unit 1 $110,664,000 $94,934,000 $22,297,000 $19,334,000
Unit 2 $119,010,000 $105,279,000 $23,634,000 $20,978,000
Unit 3 $113,084,000 $96,423,000 $23,173,000 $19,962,000
Unit 4 $265,406,000 $223,782,000 43 $56,967,000 $43,587,221
Unit 5 $265,406,000 $201,268,000 $56,967,000 $39,925,221

EPA generated revised cost estimates based on EC/R ’s comparison of the August 2008 B&V cost estimates against the EPA Control Cost Manual . Our revisions are listed in Table 13, and the results are shown in Table 15. Cost effectiveness of SCR is based on an assumed 80% reduction in NO x by SCR. The 80% reduction is the minimum reduction expected from SCR, estimated by Hitachi P ower Systems America 44 and therefore provides a margin of compliance with the emission limit. These costs are lower than costs estimated by B&V and higher than costs e stimated by NPS.

Several commenters, including NMED and NPS, sugges ted that the calculations of cost effectiveness should be based on the most s tringent level of control possible. NPS stated that data from many existing facilities with SCR controls show annual average emission rates of 0.05 lb/MMBtu. To be conservativ e in estimating costs and cost effectiveness, EPA assumed 80% control efficiency f or SCR without additional combustion controls, based on the minimum level of control estimated by Hitachi. Additionally, as described above, EPA relied mostly on APS cost estimates, which can be expected to represent a conservatively high estimat e of costs, except where EPA determined the line-item costs to be inappropriate or excluded from the EPA Control Cost Manual . Because our revised cost estimates no longer rel y on a comparison with other facilities of the ratio of annual to capital costs, the comment from ADEQ to justify this method is moot. ADEQ additionally suggested t hat it was inappropriate to include the anticipated increase in electricity costs to co nsumers in our ANPRM without explanation of the unusual circumstances justifying its consideration. The BART guidelines state that under the Energy and Non-Air Quality Impacts factor, the reviewing authority may consider whether a given alternative would result in significant economic disruption or unemployment. EPA determined that an increase in electricity generation costs warranted review as a potential economic impa ct and we include this discussion in Section 4 of this technical support document.

43 The costs for Unit 4 include systems in common wit h Unit 5.
44 April 23, 2010 email from Anthony Favale, Hitachi Power Systems America to Anita Lee, EPA.Page 32 of 92

Table 15: EPA Revised Cost Estimates for SCR on Uni ts 1 – 5 (2008 dollars)

Total Capital Investment Total Annual Cost Cost Effectiveness ($/ton) $/KW

Unit 1 $90,337,340 $11,475,000 $2,515 $488
Unit 2 $97,663,260 $12,114,000 $3,163 $528
Unit 3 $94,180,720 $12,068,000 $2,678 $401
Unit 4 $217,727,260 $28,740,000 $2,622 $276
Unit 5 $217,727,260 $28,740,000 $2,908 $276 Total Facility $717,635,840 $93,137,000

The APS cost estimate represents the upper-range o f submitted costs for SCR, whereas the estimate from NPS, using the EPA Control Cost Manual , represents the lower range of submitted costs for SCR. The EPA Of fice of Air Quality Planning and Standards (OAQPS) Air Benefit and Cost Group review ed the cost estimates NPS submitted to EPA during the ANPRM comment period. OAQPS determined that in general, NPS used the appropriate assumptions for e stimating costs of SCR, however, several assumptions warrant additional explanation. These include why different indirect and direct retrofit factors were used in the capita l cost calculation and whether actual vendor information is available regarding the press ure drops across duct and catalyst layers rather than relying on assumed pressure drop s from the Control Cost Manual

.

Table 16: Cost Effectiveness of SCR Retrofits estim ated for Several Western Power Plants

Facility Year of Cost Basis Size Cost Effectiveness ($/ton)

Centralia Power Plant (Units 1 – 2) 2008 702.5 MW $9,091 San Juan Generating Station (Units 1 – 4) 2007 350 – 544 MW $5,498 – $6,932 M.R. Young (Units 1 – 2) 2009 257 – 477 MW $3,950 – $4,250 Naughton (Units 1 – 3) 2006 160 – 330 MW $2,751 – $2,848 Jim Bridger (Units 1 – 4) 2006 530 MW $2,256 – $4,274

Based on the cost data presented by APS, as well a s EPA’s revisions to APS’s cost estimates, EPA has determined that SCR is cost effective, particularly in comparison to the cost effectiveness of SCR retrofits estimate d for other Western coal-fired power plants (See Table 16). Therefore, EPA will continu e evaluating SCR in the BART fivefactor analysis.

For this technical support document, EPA has not r evised the cost estimates for PM control provided by APS. However, we note that the annual cost of PM controls likely uses similar interest rates and assumptions relied upon in APS’s cost estimates for SCR, for example a high 15% interest rate, therefor e, we anticipate the annual costs of PM controls presented by APS to be overestimated. To be conservative, EPA relied on the PM cost estimates provided by APS. Additionall y, we note that the cost effectiveness of controls estimated by APS actually represent an incremental cost effectiveness of the upstream PM controls because the calculation counts PM reductions on top of reductions from the venturi scrubbers.Page 33 of 92 The wet-membrane ESP is the lowest cost approach to meeting to meet an emission limit of 0.012 lb/MMBtu, but it has a very high dollar per ton of PM removed because it is an incremental cost for removing the remainder of the PM not already controlled by the venturi scrubber. An alternativ e technology that may be used by FCPP to meet a PM emission limit of 0.012 lb/MMBtu is to install baghouses upstream of the venturi scrubbers. Installing baghouses would make the baghouses the primary PM control device on these units. Using AP-42 emissio n factors and the 25% ash content of FCPP coal, baghouses would be reducing 99+% of the 340,000 tons of fly ash. The cost effectiveness for Unit 1 would then be about $110/t on, Unit 2 would be about $118/ton, and Unit 3 would be about $91/ton 45 . With these upstream controls, APS could optimize the venturi scrubber for SO 2 control and potentially reduce the pressure drop o n the venturi scrubber. The baghouses would be the most likely choice for APS for PM control if they want to achieve significant Hg reduction fr om these units.

Baghouses have already been installed on the four o ther coal fired EGUs in Region 9 that had historically used venturi scrubbe rs for PM control, including the only other venturi scrubber owned and operated by APS at their Cholla Unit 1. NV Energy Reid Gardner offered to install baghouses at Units 1, 2, and 3 as extra injunctive relief in a settlement agreement. EPA believes these baghous es were installed, despite the very high incremental dollars per ton of PM removed, to allow the companies to continue to operate the units in continuous compliance with the ir PM and opacity limits and to prepare for the upcoming utility MACT regulation of Hg.

In conclusion, EPA considers installation of either the wet membrane ESP or the baghouse as reasonable cost technology capable of a chieving the proposed BART emission limit of 0.012 lb/MMBtu for Units 1 – 3. This cost effectiveness determination relies heavily on the fact that the other venturi P M control devices in Region 9 have already installed retrofit baghouses and found that to be an economically and environmentally sound approach. Therefore, EPA con tinues to evaluate the four most stringent PM control options for Units 1 – 3 in the BART five-factor analysis. In addition, EPA is requesting comment on whether APS can satisfy BART on Units 1 – 3 by operating the existing venturi scrubbers to meet an emission limit of 0.03 lb/MMBtu with a 20% opacity limit.



### 4. Energy and Non-Air Quality Environmental Impacts of Compliance

A. FCPP Approach to This Factor

The potential non-air quality impacts identified b y B&V for FCPP were the disposal requirements for byproduct and waste gener ated from each control technology and lost generation due to extended outages for ins tallation. Impacts to water quality were not considered by FCPP because the facility has not been identified as a zero water

45 See Excel Spreadsheet titled “FCPP PM Cost Effecti veness baghouse ap-42.xls”.Page 34 of 92

pollutant discharge site. The costs for direct ener gy impacts, i.e., power consumption from the control equipment and additional draft sys tem fans, from each control technology were included in the cost analyses. The indirect energy impacts, such as the energy to produce raw materials, were not considere d, consistent with the BART guidelines.

B. Discussion of this Factor in ANPRM

In the ANPRM, EPA outlined several energy and non-a ir quality environmental impacts of the control technologies, including incr eased unburned carbon in the fly ash (loss of ignition or LOI) resulting from LNBs, incr eased emissions of sulfuric acid that may trigger permitting requirements under the Preve ntion of Significant Deterioration (PSD) program from the use of traditional SCR catal ysts, particularly those that are vanadium-based, and the parasitic load resulting fr om the operation of SCR. Although not presented under this factor in the ANPRM, EPA a lso projected the increase in electricity generation costs resulting from LNB/LNB +OFA and SCR from NO x controls and from the ESP and baghouse options for PM contro l. See Table 17.

Table 17: Increase in Electricity Generation Costs ($/kWh) from NO x and PM Controls at FCPP Presented in ANPRM

LNB and LNB+OFA SCR Upstream ESP Upstream

Baghouse Wet Metal

ESP Wet

Membrane ESP Unit 1 $0.001 $0.015 $0.005 $0.007 $0.004 $0.003
Unit 2 $0.001 $0.016 $0.006 $0.008 $0.004 $0.003
Unit 3 $0.001 $0.011 $0.004 $0.006 $0.006 $0.003
Unit 4 $0.001 $0.009
Unit 5 $0.001 $0.009

C. Affected State, Tribe, and FLM Consultation

The Arizona Department of Environmental Quality (AD EQ) submitted comments that the non-air quality impacts of SCR, such as tr ucking of ammonia and challenges associated with ammonia storage and handling, as we ll as the energy efficiency losses resulting from the installation of SCR, be assessed . Because FCPP is a significant source of mercury (Hg), and Four Corners region experience s high levels of Hg deposition, the Colorado Department of Public Health and Environmen tal (CDPHE) 46 commented that EPA should assess the effectiveness of new fabric f ilter baghouses in providing additional PM reductions and co-benefits of mercury emissions reductions. Additionally, CDPHE cited additional environmental and health ben efits of reducing NO x emissions on ambient ozone concentrations, and NPS cited additio nal benefits of reduced nitrogen deposition resulting from more stringent NO x controls.

46 Letter dated September 25, 2009 from James B. Mart in, CDPHE to Laura Yoshii and Anita Lee, EPA.Page 35 of 92 The Navajo Nation (the Nation) submitted comments o n the potential that requiring SCR as BART for FCPP would cause the faci lity to shut down, resulting in great economic harm to the Navajo directly and indi rectly, through lost employment at FCPP, at the BHP Navajo Mine that supplies coal to FCPP, as well as the revenue to the Nation in the form of royalties and taxes. The Sal t River Pima-Maricopa Indian Community (Salt River) expressed concern regarding the potential adverse impact of SCR on its Phoenix Cement Company and the fly ash b usiness unit at FCPP, which is a significant source of revenue for Salt River 47

.

D. EPA Conclusions regarding This Factor

In their cost analysis, APS included the cost of au xiliary power for the SCR system; therefore EPA did not further consider the energy efficiency losses, as suggested by ADEQ.

Emissions increases in H 2 SO 4 at existing major stationary sources as a result o f the application of SCR for NO x control will trigger PSD permitting requirements, including the application of BACT, if they exceed t he H 2 SO 4 significance threshold of 7 tpy. However, the existing and expected control te chnology for PM emissions can be effective in reducing these emissions. Specificall y, the baghouses in use on Units 4 and 5 are likely to result in good reductions of H 2 SO 4 . The coal that is used at FCPP has very high percentage of ash, approaching 25%. This high percentage of ash may prevent a significant increase in H 2 SO 4 after installation of SCR on these units.

For Units 1 – 3, EPA is proposing the addition of w et membrane ESPs as BART for PM. When the exhaust from Units 1 – 3 reaches these tail gas control devices, which APS will most likely install after the existing ven turi scrubbers, SO 3 emissions will have already formed H 2 SO 4 droplets. The wet membrane ESPs can have very goo d collection efficiency for any H 2 SO 4 droplets that penetrate the venturi scrubber. H 2 SO 4 can also be minimized with the use of a low SO 2 to SO 3 conversion SCR catalyst or additional control technologies such as adsorbent injection to collect the SO 3 / H 2 SO 4 and then remove it from the gas stream in the primary PM con trol devices.

APS estimated costs of SCR based on the use of urea for SCR reagent rather than anhydrous ammonia, therefore EPA does not expect th e potential risks associated with the transportation and storage of anhydrous ammonia , a hazardous substance, to be an issue for FCPP. However, because FCPP is not locat ed next to a major rail line, EPA does anticipate urea deliveries to increase heavy-d uty truck traffic between FCPP and Gallup, New Mexico, the nearest rail station. Alth ough this factor deals specifically with energy and non-air quality environmental impacts, E PA determined that the potential adverse health impacts of increased diesel truck tr affic to and from FCPP warranted further review.

47 Letter dated March 1, 2010 from President Diane En os, Salt River Pima Maricopa Indian Community to Ja red Blumenfeld, EPA.Page 36 of 92 EC/R Incorporated estimated that fifteen additional truck deliveries per week would be needed to transport ammonia in the form of urea from the Gallup to FCPP, an approximate one-way distance of 100 miles. The risk estimates conducted by EC/R associated with additional tanker truck deliveries to FCPP are presented in Appendix A: Mobile Source Risk Estimates for Four Corners Power Plant. EC/R estimated emissions from the additional truck trips using conservative emission factors from the South Coast Air Quality Management District. The modeled conce ntrations of criteria pollutants were compared against the National Ambient Air Quality S tandard (NAAQS), and modeled concentrations of hazardous air pollutants were use d to estimate cancer risks and a noncancer hazard quotient for comparison against backg round. Of the criteria pollutants, emissions of NO x were highest but totaled less than 3 tons per year , which was modeled to be less than 1% of the NAAQS at the most impacte d census block, located in San Juan County, New Mexico. The modeled impact of the sum of all hazardous air pollutants in the highest impacted census block, with a populatio n of 36 individuals, was estimated to result in a cancer risk of 0.5 excess cancer cases over a lifetime exposure per one million people exposed (5 x 10 -7 risk), and a non-hazard quotient of 0.2, where a q uotient of one or below indicates exposure is not likely to result in adverse health effects. The background cancer risk is 1.5 excess cancer cases o ver a lifetime exposure per one million people exposed. For the other impacted cen sus blocks, the risks are estimated to be as low as 1 x 10 -10 and the hazard quotients are estimated to be as lo w as 0.00001. Based on the information that the increase in risks associated with transportation emissions in the most impacted census block are wel l below background, EPA has determined that the increase in daily tanker truck traffic to transport urea to and from FCPP for SCR will not result in a significant healt h risk.

EPA agrees with CDPHE and NPS that NO x reductions from FCPP will have cobenefits for tropospheric ozone and nitrogen deposi tion. We also note that ambient ozone concentrations in the Four Corners region are close to the National Ambient Air Quality Standard (NAAQS) for ozone and the area may be recl assified as non-attainment for the standard. We have determined that a qualitative ac knowledgement of the co-benefit for ozone and nitrogen deposition is sufficient conside ration for this factor. The BART guidelines generally focus on adverse environmental impacts of control technologies, such as solid or hazardous waste generation or disc harges of polluted water, however, the guidelines further state that “any important relati ve environmental impacts (both positive and negative) of alternatives can be compared with each other”. As the most stringent NO x control option, SCR is expected to result in the h ighest level of co-benefit for reducing ozone and nitrogen deposition. EPA furthe r agrees with CDPHE that potential co-benefits for Hg reductions are possible if bagho uses are required for PM control on Units 1 – 3. Currently, APS has measured Hg reduct ions of approximately 90% from Units 4 and 5 with their baghouse controls, while U nits 1 – 3 have had about 25% control across the venturi scrubbers 48 . Again, EPA has determined that a qualitative consideration of this co-benefit is sufficient for this factor.

The BART guidelines state that under the energy imp acts analysis, the reviewing authority may consider whether a given alternative would result in significant economic

48 See letter from Richard Grimes, APS, to Steve Frey , EPA, dated February 18, 2010.Page 37 of 92

disruption or unemployment. EPA contracted with EC /R Incorporated to explore the concerns raised by the Navajo Nation regarding the economic impacts of SCR. EPA requested EC/R conduct an economic analysis to esti mate the increase in cost to produce electricity if SCR were required for BART, to asses s the factors that impact a decision to shut down FCPP, and to assess the potential impacts on the Salt River fly ash business using FCPP ash. EC/R contracted with Energy Strate gies, a subcontractor, to conduct the economic analysis.

Energy Strategies (ES) created an economic model to estimate the cost of electricity generation if LNB/OFA or SCR (without c ombustion controls) were installed on all 5 units at FCPP compared with the cost to pu rchase electricity on the wholesale market. The final report from ES is Appendix B: Ec onomic Analysis of SCR on Four Corners Power Plant of this TSD and the economic mo del is available in the online docket for this proposal 49 . The economic model is a 25-year discounted cash flow model that estimates the net present value (NPV) cost of electricity for two cases: (1) assuming straight line depreciation, and (2) assuming accele rated depreciation per the Rapid Tax Amortization program (See 26 CFR §1.169 and 40 CFR Part 20), which can apply to facilities in service on or before December 31, 197 5 that install air pollution control devices. ES estimated the current Business As Usua l (BAU) cost to produce electricity and modeled the cost to add LNB/LNB+OFA or SCR to a ll five units. ES forecasted the market price to purchase energy on the wholesale ma rket using the Palo Verde price index, which is determined by the most costly sourc e of electricity, in this case, natural gas. Additionally, ES estimated the non-discounted cost of electricity per MWh, which we report here in kWh for consistency with our ANPR M. The model uses LNB/LNB+OFA cost data provided by APS, and uses EPA ’s revisions to APS’s capital expense and operating expense estimates for SCR. T he economic model uses an amortization rate of 15%, which includes the intere st rate and the tax rate on the debt and equity of the project. Thus, the economic model di ffers from the EPA Control Cost Manual in that the Cost Manual determines the amortizatio n rate on a pre-tax basis, using only the interest rate and amortization period. Th e results of the model are shown in Tables 18 and 19.

Table 18: Summary of Cost Comparisons for NO x Controls versus Market Trends under Straight Line Depreciation (2011 – 2035)

BAU LNB/OFA SCR Market Low Market Mid Market High Cost per kilowatt-hour (non-discounted cost / 25 ye ar kWh)
Cost/kWh $0.03395 $0.03451 $0.04135 $0.04451 $0.04809 $0.05192
Increase compared to BAU $0.00056 $0.00740 $0.01056 $0.01414 $0.01797

Net Present Value (Discounted) 25 Year Cost ($Milli on)
Cost $5,688 $5,776 $6,892 $7,008 $7,356 $7,746
% Increase compared to BAU 2% 21% 23% 29% 36%

49 Economic Analysis of Proposed EPA BART Determinati on on FCPP_r0-9_18_10 RATES.xls”.Page 38 of 92

Table 19: Summary of Cost Comparisons for NO x Controls versus Market Trends under Accelerated Depreciation (2011 – 2035)

BAU LNB/OFA SCR Market Low Market Mid Market High Cost per kilowatt-hour (non-discounted cost / 25 ye ar kWh)
Cost/kWh $0.03395 $0.03451 $0.04021 $0.04451 $0.04809 $0.05192
Increase compared to BAU $0.00049 $0.00626 $0.01056 $0.01414 $0.01797

Net Present Value (Discounted) 25 Year Cost ($Milli on)
Cost $5,688 $5,764 $6,704 $7,008 $7,356 $7,746
% increase compared to BAU 1% 18% 23% 29% 36%

The results from the economic model suggest that th e retrofit of all five units at FCPP with SCR would increase the non-discounted cos t of electricity generation by an average of $0.00740/kWh over the 20 year amortizati on period, resulting in a cost of $0.04135/kWh, which is lower than the low, mid, and high trends for the wholesale market price of electricity. Additionally, the 25 year cost to produce electricity (discounted NPV) if all five units were retrofit wi th SCR represented a 21% increase over the BAU case, but was also lower than the low, mid, and high market trends, suggesting that SCR would not result in a cost to produce elec tricity for FCPP that exceeded the cost to purchase electricity on the open market. Assumi ng FCPP qualifies for the rapid tax amortization program, under ES’s interpretation of the regulations, ES modeled an 18% increase in the average cost to produce electricity over the 20 year amortization period if SCR is required, compared to BAU, or $0.00626/kWh i ncrease on a non-discounted basis. EPA has determined that SCR will increase t he cost of electricity generation, but is not likely to force FCPP to shut down.

Retail consumers of power pay more than just the ge neration costs of power (i.e., transmission and distribution costs), however, for APS customers, for example, the cost increase from FCPP would flow into a broader rate impact calculation based o n the entire portfolio of APS generation assets and power purcha se contracts, which include coal, natural gas, nuclear, and some renewables. Therefo re, a 22% increase in generation costs at only one of APS’s sources of power does not resu lt in a commensurate 22% increase to rate payers. As discussed in Appendix B to this TS D, in public meetings as part of its integrated resource planning process, APS discussed their sensitivity analysis regarding the effects of carbon pricing on its customers. AP S estimated a carbon cost range of $20 - $50/MT, which is equivalent to an increase of $20 - $50/MWh or $0.02 – 0.05/kWh for a coal fired power plant. Based on APS’s entire po rtfolio of power generation assets and power purchase agreements, APS estimated carbon pri ces of $0.02 – 0.05/kWh would result in an increase to rate payers of 10 – 25%. Based on APS’s estimates of how carbon pricing may impact rate payers but without k nowing the assumptions that wentPage 39 of 92

into APS’s rate payer calculation, because the cost of electricity generation from SCR is estimated to increase by an average of $0.0074/kWh, which is 63% lower than the low range of carbon costs, EPA infers that the increase to APS rate payers as a result of SCR alone is likely to be less than 5%.

EPA used another approach to estimate affects of SC R on APS rate payers that also employed public information from APS (See “Eco nomic Analysis of Proposed EPA BART Determination on FCPP_r0-9_18_10 RATES.xls”, R ate Impact Estimates worksheet in docket for this proposal). This anal ysis was based on FERC F1 filings and uses the 2009 total retail sales (in kWh) and 2009 total retail revenues ($) to get an average retail rate over 2009. This methodology in volves numerous conservative simplifying assumptions to estimate the affect of S CR on retail rates. Revenues, in nominal dollars, and sales (in kWh) from 2009 were estimated for 2015 (the expected completion date for SCR installation on all 5 units ) by applying a 1.5% escalation factor each year from 2009 – 2015. This escalation factor is uncertain, but 1.5% is conservative and within the range of historical increases. This estimate also assumes that 100% of the increase in cost from SCR is passed onto retail cus tomers, and does not include changes in ownership, or life-extending capital investment, or other environmental regulations.

The increase in generation costs resulting from SCR , using the 2015 increase in generation costs of $0.1195/kWh, is multiplied by t he utility's share of FCPP's electricity generation (in kWh) to calculate the APS’s share of the increase in cost resulting from SCR. This cost is added to the 2009 retail revenue s (escalated to 2015 by 1.5% annually) and then divided by estimated retail sales (kWh) ba sed on 2009 sales (escalated to 2015 by 1.5% annually). This results in the estimated r etail rate with installation and operation of SCR. The increase in the retail rate is then es timated by subtracting the estimated retail rate without SCR from the estimated rate wit h SCR. Using this methodology, EPA estimates that the increase in retail rates to APS rate payers may be $0.00235/kWh, a 2.2% increase in the average 2009 estimated retail rate.

As the Navajo Nation and other commenters discussed in their comment letters on the ANPRM, other factors affect whether the plant w ould shut down, including lease negotiations, future regulations targeting greenhou se gas emissions, mercury and HCl emissions (Utility MACT), and ash handling (coal co mbustion residues). ES explored these issues in more detail in their report to EPA. There is considerable uncertainty related to greenhouse gas regulations and the effec t on the other owners of Southern California Edison’s divestiture of their ownership interest in FCPP when its contractual obligations expire in mid-2016 50 . ES describes three types of risk, regulatory, eco nomic, and market, that each owner must consider when dete rmining whether investment in SCR meets the needs of their stakeholders (rate payers, regulators, and owner boards) and shareholders. Because of the uncertainty associate d with these upcoming regulations and the complexity in determining the appropriate level of risk for each owner, EPA has determined that our BART determination cannot rely on conjectures on the future decisions of FCPP owners. Without firm intentions and commitments to shut down in the near future resulting from one or more regulato ry factors, EPA is only considering the

50 http://newamericamedia.org/2010/04/socal-edison-ba ils-out-of-coal-plant.phpPage 40 of 92

results of the economic model for SCR in our analys is, which suggests that SCR will not cause the cost of electricity generation to exceed the wholesale market cost of electricity.

In addition to the potential impacts on the Navajo Nation, the Salt River Pima Maricopa Indian Community (SRPMIC) submitted commen ts expressing concern over the economic impact of SCR on their Phoenix Cement Company’s fly ash business unit at FCPP. SRPMIC did not specify in their comment lett er how SCR would affect their fly ash business, therefore, EPA assumed potential impa cts of requiring SCR include the possible shutdown of FCPP, and the impact of ammoni a in the FCPP fly ash. As discussed above, EPA has determined, based on the e conomic modeling, that installing SCR is not likely to cause FCPP to shut down. EPA contracted with EC/R to explore the impact of ammonia on the usability of fly ash. Thi s report from EC/R is Appendix C of this TSD: Impact of Ammonia in Fly Ash on its Benef icial Use. Ammonia adsorption to fly ash is generally less desirable due to odor but does not impact the integrity of the use of fly ash in concrete. However, EC/R notes that o ther NO x control technologies, including LNB, have undesirable impacts on fly ash. LNBs increase the amount of unburned carbon in the fly ash, also known as Loss of Ignition (LOI), which does affect the integrity of the concrete. However, commercial -scale technologies exist to remove ammonia and LOI from fly ash. Therefore, EPA has d etermined that the impact of SCR on the fly ash at FCPP is smaller than the impact o f LNB on the fly ash, and in both cases, the impact can be mitigated.

EPA concludes that energy and non-air quality impac ts of SCR do not warrant elimination of SCR as the top control option for NO x , and EPA is not aware of any significant energy or non-air quality impacts of th e PM controls that would warrant their elimination.



### 5. Any Existing Pollution Control Technology at the Source

A. FCPP Approach to This Factor

Table 20: Flue Gas Flow Sequence and Air Pollution Control Equipment at FCPP lists the existing air pollution control equipment in order of flow through the physical flue gas configuration. Burner modifications were made i n 1977 to Unit 1 to reduce NO x emissions, and LNBs were installed on Units 2 (1988 ), 3 (1990), 4 (1989), and 5 (1991). In their analysis, FCPP does not claim that the exi sting level of NO x control already meets BART.

Units 1 – 3 currently use venturi scrubbers to con trol PM and SO 2 emissions, with a PM control efficiency of 98%, with less control o f PM 10 and PM 2.5 , and an SO 2 control efficiency of 90%. Units 4 and 5 at FCPP each use r everse gas fabric filters (RGFF) and tray tower flue gas desulfurization (FGD), also cal led wet scrubbers, to control PM and SO 2 , respectively. Expected control efficiency for the baghouses is 99.9+% and the SO 2 control efficiency is about 87.5% because approxima tely 8% of the exhaust gas is bypassed around the scrubber to be used for reheat in the stack. The FCPP stack lining isPage 41 of 92

not capable of withstanding wet droplet conditions. Reduction of the bypass allowing a wet stack would require new stacks or new stack lin ers. B&V concluded that the most stringent controls have already been applied to Uni ts 4 and 5, and thus meet BART for PM.

Table 20: Flue Gas Flow Sequence and Air Pollution Control Equipment 51 at FCPP Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

Boiler Boiler – LNB (NO x ) Boiler – LNB (NO x ) Boiler – LNB (NO x ) Boiler – LNB (NO x )
Economizer Economizer Economizer Economizer Economizer
Air Preheater Air Preheater Air Preheater Air Preheater Air Preheater
Venturi Scrubber (PM, SO 2 ) Venturi Scrubber –

Lime (PM, SO 2 ) Venturi Scrubber –

Lime (PM, SO 2 ) Reverse Gas Fabric Filter (PM) Reverse Gas Fabric

Filter (PM)
Stack Stack Stack Tray Tower Lime Flue Gas Desulfurization (SO 2 ) Tray Tower Lime

Flue Gas Desulfurization (SO 2 ) Stack Stack

B. Discussion of this Factor in the ANPRM

FCPP has had limited success in retrofitting their boilers with LoNO x technology. When Unit 2 was retrofit in the 1990s, FCPP encount ered significant operational problems with the boiler. This led FCPP to decide against retrofit of Unit 1, which was identical to Unit 2, because of the operational dif ficulties with Unit 2. For Units 4 and 5 that were originally equipped with cell burners, th e inherent design of these boilers makes it difficult to achieve any significant reduction i n NO x through burner retrofit technology. Based on the inherent design of Units 1 – 5, we sta ted in our ANPRM that LNB retrofit of these units would provide only limited NO x control, and we requested comment on this determination. We discussed the LNB retrofit in mo re detail in Section 2 above.

C. Affected State, Tribe, and FLM Consultation

We did not receive comments on the existing air po llution controls for NO x at FCPP. Because our ANPRM focused on PM controls on Units 1 – 3, NPS and NMED commented that the existing baghouses on Units 4 an d 5 should be reviewed to determine if further PM control can be achieved.

D. EPA Conclusions regarding This Factor

For NO x control, EPA believes that LNB technology will be ineffective in reducing NO x emissions from the boiler units at FCPP because of past difficulties in the

51 Air Pollution Control Equipment listed in regular text and the pollutant controlled is listed in pare ntheses.Page 42 of 92

LNB retrofit of Unit 2, and due to the inherent des ign and size limitations of all the furnaces at FCPP (See Section 2).

EPA also concludes that existing PM controls for U nits 1 – 3 at FCPP, the venturi scrubbers do not meet BART and are the least effect ive PM control devices on large coalfired EGUs, especially at a pressure drop below 8 i nches of water, as is typical of the FCPP scrubbers. PM emissions from Units 4 and 5 are currently controlled by baghouses with emission limits in their Part 71 Operating Per mit of 0.05 lb/MMBtu for each unit. In their modeling inputs, APS reported that average PM 10 emission rates from 2002 – 2006 from Unit 4 is 0.014 lb/MMBtu and from Unit 5 is 0. 010 lb/MMBtu, suggesting that operation of Unit 4 may be improved to achieve emis sion rates comparable to Unit 5, and that PM emissions from Units 4 and 5 are significan tly lower than their permitted emission limit.

Boiler standards for coal fired units were revised for units built after 1978 and the PM limit was lowered to 0.03 lb/MMbtu. See 40 CFR P art 60 Subpart Da. Most current coal fired boilers now use baghouses that are capab le of meeting PM limits of about 0.01 to 0.012 lb /MMBtu.

As mentioned in Section 3 of this TSD, baghouses ha ve already been installed on the four other coal fired EGUs in Region 9 that had historically used venturi scrubbers for PM control, including APS’s Cholla Unit 1. EPA believes these baghouses were installed, despite the very high incremental dollar s per ton of PM removed, to allow the companies to continue to operate the units in conti nuous compliance with their PM and opacity limits. EPA notes that these four units op erated with a re-heat of the scrubber exhaust. This allowed the use of Continuous Opacit y Monitors (COMs) in their stacks and provided an ongoing measurement of the opacity compliance. FCPP Units 1, 2, and 3 originally had, and EPA believes operated with, a re-heat system, but FCPP discontinued its use. EPA Region 9 unaware when u se of the re-heat system was discontinued and did not give permission for remova l of the re-heat system. The three venturi-equipped units also do not have an opacity limit, which is required on all other EGUs in Region 9 and likely across the U.S. When E PA promulgated the 2007 gap filling FIP, APS refused to accept an opacity limit for these units and told EPA that there is no limit that these units could continuously mee t. Thus, the regulatory agencies and the public lack this opacity tool to help assess contin uing compliance for PM at these units. Over the past several years the PM test for Units 1 and 2 showed compliance with the PM emission limit of the FIP, however source tests on Unit 3 have exceeded the limit and, after subsequent improvements, only managed to test at 0.049 lb/MMBtu with a limit of 0.05 lb/MMBtu.



### 6. Remaining Useful Life of the Source

A. FCPP Approach to This FactorPage 43 of 92 In their analysis, FCPP stated that the remaining u seful life of Units 1 – 5 were each at least 20 years. As such, the remaining usef ul life does not impact the cost effectiveness of controls because the remaining lif e is longer than the economic study period of all control technologies (see page 6-2 of the B&V BART Analysis).

B. Discussion of Factor in ANPRM

In the ANPRM, we stated that the remaining useful l ife is often expressed in terms of the amortization period used to annualize the cost of controls. APS used an amortization period of 20 years, which is consisten t with the EPA Control Cost Manual

. We requested comment on the use of 20 years to repr esent the remaining useful life of FCPP.

C. Affected State, Tribe, and FLM Consultation

The Navajo Nation recommended that we adopt a phase d approach to BART, in part to provide a reasonable timeframe in which to resolve the outstanding lease and right-of-way issues that affect the productive life of FCPP. EPA understands these issues involve upcoming negotiations between APS and Navaj o Nation on renewals of APS’s coal, land, and right-of-way leases and agreements.

D. EPA Conclusions regarding This Factor

EPA has determined that the remaining useful life d etermination of at least 20 years is appropriate for FCPP. The outcome of the lease and right-of-way negotiations could conceivably impact FCPP’s ability to operate into the future; however, without a commitment to shut down, EPA has determined it is m ost appropriate to rely on a 20 year useful life as the default for amortization purpose s.



### 7. Degree of Improvement in Visibility which May Re asonably be Anticipated to Result from the Use of Such Technology

A. BART Guidelines and Modeling Protocols

The final factor to consider under EPA's BART Guid elines is the degree of visibility improvement from the BART control option s. 59 FR 39104, 39170 (July 6, 2005). The BART guidelines recommend use of the CA LPUFF air quality dispersion model to estimate the visibility improvements at ea ch Class I area, typically within a 300 km (186 mile) radius of the source, of alternative control technologies, and to compare these to each other and to the impact of the baseli ne, or current, source configuration. ENSR Corporation (now AECOM) conducted the modeling for FCPP and included sixteen Class I Areas in their modeling analysis; f ifteen are within 300 km of FCPP and one Class I area, Grand Canyon National Park, is ju st beyond 300 km from FCPP. These are listed in Table 21 and 22 and shown in Figure 1 . The measured visibility impairmentPage 44 of 92

(in deciviews) at each Class I area is presented in Table 21as a range of the 10 th and 90 th percentiles, averaged for 2007 and 2008.

Table 21: Measured Visibility Impairment at Class I areas (2007 – 2008 average), from IMPROVE monitoring network (Regional Haze Rule Summ ary data, Original IMPROVE Algorithm, http://vista.cira.colostate.edu/improve/ Data/IMPROVE/summary_data.htm)

Class I Area 10 th Percentile Deciview Impairment 90 th Percentile Deciview Impairment Arches NP 3.9 11.8
Bandelier WA 5.1 12.6 Black Canyon of the Gunnison WA 3.2 11.0 Canyonlands NP 3.9 11.8 Capitol Reef NP 3.8 12.0 Grand Canyon NP 3.1 11.7
Great Sand Dunes NM 4.5 11.8 La Garita WA 3.2 11.0
Maroon Bells Snowmass WA 2.2 10.3
Mesa Verde NP 4.1 11.6
Pecos WA 2.8 11.3
Petrified Forest NP 5.4 13.0 San Pedro Parks WA 2.8 11.3
West Elk WA 2.2 10.3 Weminuche WA 3.2 11.0
Wheeler Peak WA 2.8 11.3Page 45 of 92

Figure 1: Map of Class I Areas 300 km from FCPPPage 46 of 92

Under the BART guidelines, the measure of the vis ibility improvement to be used in comparisons between various control scenarios is the 98 th percentile of impacts are expressed as 24-hour averages of delta deciviews r elative to natural background, as estimated using the CALPUFF air quality modeling sy stem. The meaning of this is described next, followed by particulars of the appl ication of CALPUFF to the FCPP BART determination.

Under the RHR, visibility is measured in deciviews . Visibility is traditionally described in terms of visual range in kilometers or miles. However, the visual range scale does not correspond to how people perceive vi sibility: a given increase in visual range is perceived differently depending on how goo d the original visibility was (that is, it is not on a linear scale). The deciview scale i s designed to address this problem. It is linear with respect to perceived visual changes ove r its entire range, analogous to the decibel scale for sound: a given change in deciview s will be perceived as the same amount of visibility change, whatever the original visibility was. The defining equation is: deciviews = 10*ln(b ext / 10), where ln is the natural logarithm, and exti nction b ext is the fraction of light scattered out of a viewing path. Extinction increases with the amount of pollution (b ext is in units of 1/Mm, “inverse megameters”). Lower deciview values represent better visibility, more pristine atmosphe res, and greater visual range, while increasing deciview values represent increasingly p oor visibility. An increase of 1 deciview corresponds to about a 10% increase in ext inction. (Deciviews are related to the more traditional visual range according to dv = 10*ln(391 / visual range)). An eligible BART source with a predicted impact of 0.5 dv or mo re of impairment in a Class I area “contributes” to visibility impairment and is subje ct to BART. 70 FR 39104, 39121 (July 6, 2005).

Under the BART guidelines, deciviews are estimated using the CALPUFF air quality model. CALPUFF predicts 24-hour average po llutant concentrations based on source emissions and how they disperse in the atmos phere. The CALPUFF modeling includes source emissions of the following visibili ty-impairing pollutants: SO 2 , SO 4 , NO x , secondary organic aerosol (SOA), fine particulate matter (PMF), coarse particulate matter (PMC), and elemental carbon (EC). CALPUFF i ncorporates a semi-empirical chemical module that simulates the conversion of SO 2 to particulate sulfate and NO x to particulate nitrate, at a rate dependent on meteoro logical conditions and background ozone concentration. These concentrations are conv erted to deciviews by the CALPOST post-processor in two steps. First, the IMPROVE 52 equation is used to estimate extinction b ext from the predicted concentrations of various pollu tants:

b ext = 3 * f(RH) * [ sulfate ] + 3 * f(RH) * [ nitrate ] + 4 * [ organic mass ] + 10 * [ elemental carbon ] + 1 * [ fine soil ] + 0.6 * [ coarse mass ] + 10

The 10 is for Rayleigh scattering, which is due to the interaction of light with molecules of air itself with no pollutants. The f(RH) is a water growth factor for sulfate and nitrate;

52 Interagency Monitoring of Protected Visual Environ ments (IMPROVE) is a network of monitors in variou s Class I Areas, established to assess visibility impairme nt and its causes. The IMPROVE equation is used t o converted monitored concentrations into extinction, a measure of visibility. See: http://vista.cira.colostate. edu/improve/Page 47 of 92

its value depends on relative humidity (RH), rangin g from 1 at low humidity to 18 at 98% humidity. In the second CALPOST step this extinction is conve rted to deciviews, using the above defining equation for deciviews.

Finally, the delta deciviews ( ∆ dv) represents the impact on visibility in deciview s of the source being evaluated, and is also provided by CALPUFF. It is the change, or “delta”, between deciviews with and without the sou rce. Under the BART guidelines, delta deciviews is the difference between deciviews including the impact of the source and natural background, and deciviews of the natura l background alone. Each modeled day and location in the Class I area will have an a ssociated delta deciview. For each day, the model finds the maximum visibility impact of al l locations (receptors) in the Class I area. From among these daily values, the BART guid elines recommend use of the 98th percentile, roughly equivalent to the 8 th highest day, for comparing the base case and the effects of various controls. The 98th percentile i s recommended rather than the maximum value to avoid undue influence from unusual meteorological conditions (BART guidelines p. 39121).

AECOM conducted modeling for FCPP according to mod eling protocols submitted to EPA 53 . The modeling analysis generally followed the BAR T protocol developed by the Western Regional Air Partnership ( WRAP), except as noted below 54

. The WRAP protocol received extensive scrutiny duri ng 2005-2006 by various States, EPA Regions, and Federal Land Managers (FLM s). Some key features of the protocol are listed here. Meteorological fields we re derived from the MM5 prognostic meteorological model, using a 36 km grid resolution , for the years 2001, 2002, and 2003 and with the continental United States as the model ing domain. Subdomains were extracted for use by individual states, such as Ari zona and New Mexico. The MM5 fields were then processed using CALMET (meteorolog ical pre-processor, part of the CALPUFF modeling system) as preparation for use in the CALPUFF air quality model, using a 4 km grid resolution. After much discussio n, WRAP elected to blend meteorological station observations into the MM5 fi elds, instead of relying on the CALMET “no observations” (“no obs”) mode.

For visibility calculations, the pollution concent ration predictions of CALPUFF are used in two post-processing steps. First, POST UTIL considers ammonia background concentrations, temperature, and humidity to determ ine how much nitrate ends up as particulate ammonium nitrate; this is to reflect th e competition between sulfate and nitrate for available ammonia. Ammonia background is discussed further below. Second, CALPOST uses the adjusted concentrations to calculate visibility using the IMPROVE equation, as described above. For the part icular way of applying it, the

53 See BART Visibility Modeling Protocol for the Ariz ona Public Service Four Corners Power Plant”, ENSR Corporation, January 2008, Doc. No.: 00494-021-300
54 “CALMET/CALPUFF Protocol for BART Exemption Screen ing Analysis for Class I Areas in the Western Unite d States”, Western Regional Air Partnership (WRAP); G ail Tonnesen, Zion Wang; Ralph Morris, Abby Hoats a nd Yiqin Jia, August 15, 2006. Available on UCR Regio nal Modeling Center web site, BART CALPUFF Modeling

, http://pah.cert.ucr.edu/aqm/308/bart.shtmlPage 48 of 92

WRAP protocol specified visibility calculation “Met hod 6” in CALPOST, the EPArecommended approach that uses monthly average humi dity.

The AECOM modeling protocol mainly followed the WR AP protocols. CALMET and CALPUFF settings were almost all the sam e; the WRAP-defined Arizona and New Mexico subdomains were used; all Class I Ar eas within 300 km of FCPP were included, as well as Grand Canyon National Park. H owever, the AECOM protocol differed in several important respects. First, AEC OM used the CALMET and CALPUFF versions now recommended by EPA, since they do not have the problems identified in the versions used by WRAP. Second, when blending i n meteorological station wind observations, AECOM used a lower radius of influenc e for stations (R1, R2, RMAX1). As shown in the wind field illustrations provided b y AECOM, this resulted in smoother wind fields than those used for WRAP, which had som e abrupt changes as one leaves the zone of influence of a given meteorological station . After initial input from the Federal Land Managers, EPA requested that certain other CAL MET option settings be changed. These changes resulted in a more refined approach t hat is more consistent with approaches used in PSD permit application modeling. The revised modeling has more extensive use of meteorological station observation s (e.g. IEXTR=-4 to extrapolate surface observations up to higher layers), and thus is responsive to the FLM concerns regarding the “no observations” mode mentioned abov e. Various relevant CALMET option settings are listed in Table 23: Selected CA LMET settings for FCPP. For meteorological input to CALPUFF, EPA used the AECOM CALMET results, which used the settings in the “Revised modeling” column of Table 23.Page 49 of 92

Table 22: Class I Areas in CALPUFF Modeling for FCP P

Class I Area Abbreviation State Agency IMPROVE monitor 55 Distance to

FCPP (km) 56

Arches arch UT NPS CANY1 245
Bandelier Wilderness band NM NPS BAND1 216 Black Canyon of the Gunnison Wilderness blca CO NPS WEMI1 217

Canyonlands cany UT NPS CANY1 214 Capitol Reef care UT NPS CAPI1 283 Grand Canyon grca AZ NPS GRCA2 345 Great Sand Dunes National Monument grsa CO NPS GRSA1 279

La Garita Wilderness laga CO USFS WEMI1 202 Maroon Bells Snowmass Wilderness mabe CO USFS WHRI1 294

Mesa Verde meve CO NPS MEVE1 62 Pecos Wilderness peco NM NPS WHPE1 258
Petrified Forest pefo AZ NPS PEFO1 224 San Pedro Parks Wilderness sape NM USFS SAPE1 160
Weminuche Wilderness wemi CO USFS WEMI1 137
West Elk Wilderness weel CO USFS WHRI1 245 Wheeler Peak Wilderness whpe NM USFS WHPE1 265

55 For a Class I area without an IMPROVE monitor of i ts own, the nearest monitor in another area is used

. 56 Distance is calculated between Unit 1 of each faci lity and the centroid of the Class I area.Page 50 of 92

Table 23: Selected CALMET settings for FCPP Option Description EPA default WRAP Original modeling 57 Revised

modeling 58 Comments

version CALMET version 5.8, level 070623 6.211, level

060414 5.8, level

070623 5.8, level

070623
NOOBS No Observation

Mode 0 0 or 1 implied 1 0 Change per FLM recommendation: use both surface and upper air observations
ICLOUD gridded cloud fields 0 0 0
IWFCOD diagnostic winds 1 1 1
IFRADJ Froude wind adj. 1 1 1
IKINE kinematic effects 0 0 0
IOBR O'Brien vertical wind

adj. 0 0 0

ISLOPE slope flows 1 1 1
IEXTRP extrapolate wind to

upper air -4 1 1 -4 Change per FLM recommendation: to extrapolate up from surface
ICALM extrapolate calm to

upper air 0 0 0

BIAS layer biases sfc vs.

UA NZ*0 NZ*0 NZ*0

IPROG gridded initial

prognostic 0 14 14 Use prognostic inputs from MM5

RMAX1 max surface radius of

influence NA 50 30 Gives smoother wind fields, per AECOM
RMAX2 max aloft radius of

influence NA 100 100

RMAX3 max over-water

radius of influence. NA 100 100

RMIN min wind radius of

influence. 0.1 0.1 0.1

RMIN2 min dist sfc winds

extrap 4 4 4

TERRAD terrain radius of in

influence NA 10 10

R1 weight surface Step 1

vs. obs NA 100 18 Gives smoother wind fields, per AECOM
R2 weight aloft Step 1

vs. obs NA 200 20 Gives smoother wind fields, per AECOM
ITPROG 3D T from obs or

prognostic 0 1 or 2 implied 2 1 Change per FLM recommendation: use surface station temperatures
TRADKM radius of influ. for T

interp. 500 500 500

IAVET spatial T averaging 1 0 1 Smoothing turned on (WRAP thought MM5 already smooth

enough)
JWAT1 starting land use for

T interp. over water 999 51 51 This area has very little "water" land use; may set to 999 to disable overwater feature, and avoid a CALMET bug
JWAT2 ending land use for T

interp. over water 999 55 55

57 January 29, 2008
58 December 16, 2009 (ENSR/AECOM report dated Novem ber 2008)Page 51 of 92

As mentioned above, the BART guidelines recommend that impacts of sources be estimated in deciviews relative to natural backgrou nd. EPA used background concentrations from Table 2-1 of “Guidance for Esti mating Natural Visibility Conditions Under the Regional Haze Rule” 59 . Although the concentration for each pollutant is a single value for the year, this method allows for m onthly variation in its visibility impact, which changes with relative humidity. The resultin g backgrounds in deciviews differ by roughly 1% from those resulting from the method ori ginally used by AECOM. 60

Table 24: Natural Background Concentrations CALPOST parameter Pollutant Concentration (μg/m 3 )
BKSO4 ammonium sulfate 0.12
BKNO3 ammonium nitrate 0.10
BKPMC coarse particulates 3.00
BKOC organic carbon 0.47
BKSOIL soil 0.50
BKEC elemental carbon 0.02

In addition to the general modeling procedures, we must address two additional pollutants when estimating the impact of various co ntrol technologies on visibility improvement: ammonia (NH 3 ) and sulfuric acid (H 2 SO 4 ).

B. Ammonia

Ammonia is important because it is a precursor to p articulate ammonium sulfate and ammonium nitrate, both of which degrade visibil ity. It is present in the atmosphere from both natural and anthropogenic sources. The l atter may include livestock operations, fertilizer application associated with farming, and ammonia slip (or unreacted ammonia) from its use in SCR or SNCR to con trol NO x emissions.

In the CALPUFF modeling inputs, EPA and AECOM both assumed that the remaining ammonia in the flue gas following SCR rea cts with sulfuric acid to form ammonium sulfate or ammonium bisulfate before exiti ng the stack. This particulate ammonium is represented in the modeling as sulfate (SO 4 ) emissions. Thus, EPA and AECOM both accounted for ammonia slip through addit ional sulfate emissions, rather than by incorporating ammonia slip into the ambient background ammonia concentrations.

C. Sulfuric Acid

59 U.S. Environmental Protection Agency, EPA-454/B-03 -005, September 2003, on web page http://www.epa.gov/ttn/oarpg/t1pgm.html, with direc t link http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcur hr_gd.pdf
60 AECOM’s modeling of FCPP used the annual average d eciviews from the guidance document, and calculated the background soil concentrations that would yield tho se deciviews; the soil concentrations were used by AECOM in the CALPOST visibility, a single value for the enti re year irrespective of relative humidity.Page 52 of 92 Sulfuric acid (H 2 SO 4 ) is formed from coal-fired power plants from the o xidation of sulfur dioxide (SO 2 ) to sulfur trioxide (SO 3 ) and the subsequent reaction of SO 3 with water vapor (SO 3 + H 2 O = H 2 SO 4 ). Sulfuric acid (also known as sulfuric acid mist ) can combine with ammonia to form particulate ammonium s ulfate, which is an important contributor to visibility impairment. CALPUFF mode ls emissions of H 2 SO 4 as inorganic particulate sulfate.

Sulfuric acid emissions from power plants must be r eported to the Toxic Release Inventory (TRI) and are typically calculated for th e TRI by estimating the amount of H 2 SO 4 produced and the amount of H 2 SO 4 removed by control equipment using information from the Electric Power Research Instit ute (EPRI) 61 . These calculations rely on assumed values for the amount of fuel sulfur con verted to SO 2 , the amount of SO 2 oxidized to SO 3 , and the amount of H 2 SO 4 lost to (or mitigated by) the air preheater and applicable control equipment, such as venturi scrub bers, baghouses, and FGDs. The assumed values are based on averages from a limited number of measurements, or in some cases, single measurement points, and are not specific to the Navajo Mine coal or FCPP. Even if stack test data of H 2 SO 4 emissions from FCPP were available, it is not possible to know the individual production and loss terms for H 2 SO 4 in the system unless a detailed measurement program of H 2 SO 4 up and downstream of the various ductwork components were conducted as well. Therefore, base line and post-SCR estimates of H 2 SO 4 from FCPP are based on the best current informatio n available from EPRI 62 and other sources.

D. FCPP Approach to This Factor

1. AECOM Modeling Inputs

In our ANPRM, we summarized the emission inputs an d modeling results AECOM submitted for FCPP. Although AECOM included SNCR in addition to LNB and SCR in their modeling, we focused on the LN B and SCR control scenarios. The inputs for the baseline case (FC0), and for the PM (FC1), LNB (FC2), and SCR (FC3) control scenarios are reproduced here in Tabl es 25. The spreadsheets where these modeling inputs were calculated are available electronically in the docket for this proposal. The modeling scenarios presented her e are:

FC0a = Baseline Visibility Impacts modeled by AECOM

, FC0e = Baseline Visibility Impacts modeled by EPA, FC1a = Visibility Impacts from PM control on Units 1 – 3 modeled by AECOM, FC1e = Visibility Impacts from PM control on Units 1 – 3 modeled by EPA,

61 Sulfuric acid emissions can also be measured using source tests, but source tests are typically not r equired unless the facility has a sulfuric acid emissions limit. FCPP does not have a sulfuric acid emission limit, therefore we do not have source test data for sulfuric acid and mus t rely on the calculation methodology to estimate s ulfuric acid emissions from FCPP.
62 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stati onary Power Plants

, 1016384, Technical Update, March 2008.Page 53 of 92 FC2a = Visibility Impacts from LNB+OFA for NO x control on Units 1 – 5 modeled by AECOM, FC2e = Visibility Impacts from LNB on Units 1 – 2 a nd LNB+OFA on Units 3 – 5 for NO x control modeled by EPA, FC3a = Visibility Impacts from SCR on Units 1 – 5 m odeled by AECOM, FC3e = Visibility Impacts from SCR on Units 1 – 5 m odeled by EPA.

Table 25: AECOM Modeling Inputs (lb/hr) Scenario FC0a - Baseline Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 464.17 615.12 995.26 2,026.10 2,130.76
SO 4 3.35 3.78 4.65 1.03 1.03
NO x 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04
SOA 8.35 9.41 11.58 32.00 32.00 PM fine 30.74 47.87 52.90 100.93 48.00
PM coarse 12.52 19.49 21.54 77.12 36.67
EC 1.18 1.84 2.03 3.88 1.84 Scenario FC1a – PM control on Units 1 - 3 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 464.17 615.12 995.26 2,026.10 2,130.76
SO 4 0.34 0.38 0.47 1.03 1.03
NO x 1,841.37 1,567.66 1,926.23 5,015.98 4,444.04
SOA 8.35 9.41 11.58 32.00 32.00
PM fine 15.34 20.39 22.54 100.93 48.00
PM coarse 11.72 15.58 17.22 77.12 36.67
EC 0.59 0.78 0.87 3.88 1.84 Scenario FC2a – LNB + OFA on Units 1 – 5 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 464.17 615.12 995.26 2,026.10 2,130.76
SO 4 3.35 3.78 4.65 1.03 1.03
NO x 1,010.91 1,051.90 1,078.69 3,561.35 3,155.27
SOA 8.35 9.41 11.58 32.00 32.00
PM fine 30.74 47.87 52.90 100.93 48.00
PM coarse 12.52 19.49 21.54 77.12 36.67
EC 1.18 1.84 2.03 3.88 1.84 Scenario FC3a – SCR on Units 1 – 5 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 464.17 615.12 995.26 2,026.10 2,130.76
SO 4 30.71 34.61 42.61 9.53 9.58
NO x 147.31 141.09 192.62 601.92 533.29
SOA 8.35 9.41 11.58 32.00 32.00
PM fine 30.74 47.87 52.90 100.93 48.00
PM coarse 12.52 19.49 21.54 77.12 36.67
EC 1.18 1.84 2.03 3.88 1.84Page 54 of 92 Note that although the control technology scenarios may be the same (e.g., SCR on Units 1 – 5), the assumptions and % control levels may differ between the modeling conducted by AECOM and EPA. For example, AECOM and EPA made different assumptions in calculating emissions of H 2 SO 4 , which resulted in different SO 4 emission rate inputs for the modeling. Table 26 ou tlines the assumptions used by AECOM for the sulfuric acid calculation.

Table 26: Assumptions Used by AECOM for H 2 SO 4 Emission Estimates Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

24-hour Maximum Uncontrolled SO 2

emissions (lb/hr) 3,629 63 4,092 5,039 13,920 14,002

Controlled SO 2 emissions (lb/hr) 464 615 995 2,026 2,131 Conversion of SO 2 to H 2 SO 4 via SO 3 due to combustion (%) 0.11% 0.11% 0.11% 0.11% 0.11%

Conversion of SO 2 to SO 3 due to SCR

(%) 1% 1% 1% 1% 1%

H 2 SO 4 penetration 64 through air

preheater 0.9 0.9 0.9 0.9 0.9

H 2 SO 4 penetration through venturi

scrubber 0.65 0.65 0.65 -- --

H 2 SO 4 penetration through baghouse -- -- -- 0.10 0.10

H 2 SO 4 removal by wet spray tower -- -- -- 0.47 0.47

As discussed above, in addition to emissions from t he facility, the background ammonia concentrations must be specified for the mo del. The IWAQM default value for ammonia background is 1 ppb year-round (discuss ed below). AECOM used background ammonia concentrations based on concentr ations used for the PSD ambient air quality impacts analysis for the Desert Rock Energy Center. Table 27 compares the IWAQM default values with the ammonia values used by AECOM.

Table 27: Ammonia background concentration in ppb
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec IWAQM default 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
AECOM values 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2

2. Results of AECOM CALPUFF modeling

AECOM presented various control scenarios’ visibili ty improvements in terms of the 98th percentile (8th highest) of the d aily maximum delta deciviews from CALPUFF for each Class I area, averaged over 2001 – 2003. As outlined in the 1999 Regional Haze rule (64 FR 35725, July 1, 1999), a o ne deciview change in visibility

63 Based on uncontrolled SO 2 = 1.7 lb/MMBtu
64 Sulfuric Acid removal efficiency = (1 - Penetratio n ) x 100%Page 55 of 92 impairment is a small but perceptible change under most circumstances when viewing scenes in a Class I area. Table 28 presents the im pact of FCPP on visibility at each Class I area, based on the 98th percentile of daily maxima from 2001 – 2003, as modeled by AECOM. APS assessed visibility impacts individually for each Class I area, however, in our ANPRM, we summed the impacts at all Class I areas as part of the assessment of the overall impact of FCPP on vis ibility.

Table 28: Impacts of FCPP on Visibility (98 th Percentile of daily maximum dv) at Sixteen Class I Areas as Modeled by AECOM Visibility Impact (dv) after applying: Baseline (FC0a) Wet ESP (FC1a) LNB (FC2a) SCR (FC3a)
Arches 1.98 1.96 1.74 1.23
Bandelier 1.71 1.70 1.57 1.12 Black Canyon 1.44 1.43 1.21 0.75 Canyonlands 2.25 2.23 2.06 1.67 Capitol Reef 1.74 1.73 1.53 1.15 Grand Canyon 1.07 1.07 0.95 0.66
Great Sand Dunes 1.02 1.02 1.02 0.62 La Garita 1.36 1.36 1.08 0.58
Maroon Bells 1 0.81 0.66 0.35 Mesa Verde 3.17 3.14 3.01 2.73
Pecos 1.55 1.54 1.31 0.88 Petrified Forest 1.21 1.20 1.05 0.68
San Pedro 2.21 2.18 2.04 1.51
West Elk 1.22 1.21 1.03 0.56 Weminuche 1.90 1.68 1.66 0.94
Wheeler Peak 1.20 1.19 0.97 0.64 Sum of Class I areas 26.03 25.45 22.89 16.07

E. Discussion of Factor in EPA ANPRM

1. Sulfuric Acid Emission Estimates

In our ANPR, we disagreed with certain assumptions used by AECOM for FCPP to calculate the sulfuric acid emissions, in p articular, the rate of SO 2 to SO 3 oxidation from the SCR catalyst and the amount of s ulfuric acid that penetrates through (or is lost to) the air preheater. APS sub mitted comments regarding our assumptions in the ANPRM. The following discussion provides a brief summary of each assumption used in the sulfuric acid emissi ons calculation, and a more detailed rationale for the two cases where EPA disa greed with the assumption used by AECOM, i.e., SO 2 to SO 3 oxidation from the SCR catalyst and loss in the air preheater.Page 56 of 92 The amount of fuel sulfur that is oxidized to SO 2 is estimated for three different coal types. Hardman et al. (1998) 65 report sulfur conversion to SO 2 (based on AP-42) to be 0.95 for bituminous coal, 0. 875 for subbituminous coal, and 0.55 – 0.85 for lignite coal, based on sodium ( Na) content. AP-42 explains that the alkaline nature of sub-bituminous coal ash results in some of the sulfur to form sulfate salts, reducing the amount of SO 2 in the flue gas. EPA agrees with APS that the ash generated at FCPP has very low ava ilable alkalinity 66 , therefore AECOM and EPA both rely on the value of 0.95 for es timating SO 2 production from fuel sulfur.

For coal-fired power plants without SCR, SO 3 is only formed during the combustion process. The amount of SO 2 that is oxidized to SO 3 during combustion depends on coal type and the type of boi ler. Measurements of SO 3 production show a wide range (0.00111 – 0.016) but many of the values reported in the EPRI 2008 document are based on single measu rements. EPRI 2008 and Harrison 2005 67 both report the SO 3 production factor from Western bituminous coal from dry bottom boilers to be 0.00111, or 0.11 1% of SO 2 production, and AECOM and EPA both used this value.

For coal-fired power plants with SCR, SO 3 is also formed as a result of oxidation of SO 2 to SO 3 on the SCR catalyst. As discussed in Section 3 of this document, AECOM assumed a 1% conversion of SO 2 to SO 3 across the SCR catalyst layers, whereas EPA used 0.5% conversion e fficiency in our ANPRM because low conversion catalysts are commercially a vailable to specifically reduce H 2 SO 4 formation following the application of SCR. In the ir comments on the ANPRM, APS stated that conversion levels are ge nerally 0.25% - 0.5% per layer of catalyst and cited a May 15, 2006 article in POWER Magazine entitled “Curbing the Blue Plume: SO 3 Formation and Mitigation”, attached as Exhibit H to APS’s comments. However, in a paper presented i n the Proceedings of the 2006 Environmental Controls Conference, written by Hitachi Power Systems America, American Electric Power, and Babcock-Hitac hi (submitted as Exhibit 41 of the CBD Consortium letter), the authors state that conversion rates as low as 0.1% have been achieved. In 2010, based on informa tion EPA submitted to Hitachi Power Systems America regarding FCPP, Hitac hi guaranteed that a total 0.5% conversion of SO 2 to SO 3 using 3 layers of CX series catalyst, can be achieved while controlling NO x by 80 – 90% 68 . After an initial 16,000 hours of use, an additional layer of catalyst would be used, adding an additional 0.2% conversion. In our ANPRM, we did not account for th e additional conversion resulting from the 4 th layer of catalyst. Therefore, we now use 0.6% SO 2 to SO 3 conversion in our calculations, which is the averag e conversion from 3 and 4

65 Hardman, R., R. Stacy, E. Dismukes. Estimating Total Sulfuric Acid Emissions from Coal- Fired Power Plants. Southern Company Services, Revised September 1998.
66 APS Comments on ANPRM (See EPA-R09-OAR-2009-0598-0 195).
67 Harrison, K.E., L.S. Monroe, J.E. Cichanowicz, Estimating Total Sulfuric Acid Emissions from Stati onary Power Plants: Revision 3 (2005). Southern Company Services, October 2005.
68 Anthony Favale, Hitachi Power Systems America to A nita Lee, electronic mail, April 21, 2010.Page 57 of 92 layers of catalyst. Although comments submitted by the Environmental Consortium recommend using a 0.1% conversion rate, EPA relied on the vendor guarantee. Although EPA recognizes that the rate a chieved may be lower than the guarantee, to be conservative, EPA has determined t hat a 0.6% conversion rate is most appropriate for our sulfuric acid estimates us ed in the visibility modeling. EPA updated the cost estimates for SCR to reflect t he cost of the Hitachi CX series catalysts (see Section 3, discussion of Fact or 2, Table 13).

At FCPP, H 2 SO 4 removal can occur in the air preheaters (Units 1 – 5), venturi scrubbers (Units 1 – 3), FGDs and baghouses (Units 4 and 5). Removal efficiencies from the air preheaters are not availa ble from EPRI 2008 and other references for non-Powder River Basin (PRB) Western bituminous coal, and only one datum point is available for PRB coal. EPRI 20 08 reports penetration factors of 0.49 (Low Sulfur Eastern Bituminous coal), 0.85 (Med-High Sulfur Eastern Bituminous coal) and 0.56 (PRB coal). Most data is available for low-sulfur Eastern bituminous coal: measurements from eight un its show a range of percent removal from 0 – 69%. Before calculating the avera ge % removal of H 2 SO 4 observed from low-sulfur Eastern bituminous coal, E PRI 2008 and Harrison 2005 excluded the 0% removal value because “the data poi nt showing 0% removal at approximately 600 ppm SO 2 is believed suspect, as an identical companion uni t firing the same coal exhibited sulfuric acid captur e of 38%”. Because data from other coal types was not available, EPRI 2008 and H arrison 2005 suggested that western coals with acidic ash (e.g., bituminous) ma y consider adopting the low sulfur, eastern bituminous value of 0.49 for the H 2 SO 4 penetration (1- removal), which is equivalent to 51% removal. EPA used the 0 .49 value for the air preheater penetration factor for our analysis prese nted in the ANPRM. This is consistent with APS’s statement cited above that th eir ash has low alkalinity.

In their analysis for FCPP, AECOM used an air prehe ater penetration factor of 0.9 (10% removal). The 0.9 penetration f actor is consistent with the value for PRB coal in Harrison 2005 and for Western bituminous and subbituminous coal in Hardman 1998, but inconsisten t with the value for PRB coal from EPRI 2008. The values in EPRI 2008 docum ent are identical to those in Harrison 2005, except for the change from 0.9 to 0.56. AECOM chose to use the earlier PRB value from Harrison 2005 rather tha n EPRI 2008.

APS submitted comments to EPA regarding our use of 0.49, stating that APS considered the use of this factor and determine d that it was not appropriate because (1) lower flue gas SO 2 content results in lower SO 3 content, which results in a lower dew point for H 2 SO 4 , suggesting that less H 2 SO 4 will condense and be removed by the air preheater, (2) high actual H 2 SO 4 removal rates on the order of EPA’s assumed value of 51% would require the air pr eheater to be operated at low temperature and would also result in significan t operational problems for FCPP, and (3) the low alkalinity ash at FCPP sugges ts that less sulfuric acid would be removed 69 . For these reasons, APS concludes that it is more appropriate

69 See page 16 of ANPR comment letter from Ed Fox, AP S, to Anita Lee, EPA, October 28, 2009.Page 58 of 92 to rely on the value of 0.9 for Western bituminous and subbituminous coal in Hardman 1998. However, Harrison 2005 associates th e 0.9 value specifically with PRB coal, not Western bituminous and subbitumi nous coal. Because Harrison 2005 is the updated version of the Hardman 1998 publication from Southern Company Services, EPA concludes that the P RB coal is the appropriate categorization for the 0.9 value. EPA was not able to determine from Hardman 1998 or Harrison 2005 how many measurements the 0.9 value was based on, however, given that no standard deviation was repor ted for this value (but a standard deviation was reported for the six units o n which the Eastern low-sulfur bituminous value was based) in Harrison 2005, EPA c oncludes that the 0.9 value is based on a very limited number of data points.

APS states that “the data presented in the [EPRI] 2 008 document indicates that the percent removal of H 2 SO 4 in the air preheater is generally proportional to the flue gas sulfur dioxide (SO 2 ) content”. APS uses this argument to justify thei r assumption that the air preheaters at FCPP will rem ove 10% of the H 2 SO 4 (0.9 penetration factor from Harrison 2005 for PRB coal) . However, APS’s rationale (low SO 2 = low H 2 SO 4 removal efficiency) is inconsistent with Figure 3- 1 of EPRI 2008, which shows that high sulfur Eastern bit uminous coal, with high flue gas SO 2 content, has very low percent H 2 SO 4 removal, suggesting that flue gas SO 2 content is not the only factor impacting the remov al of H 2 SO 4
. The 2010 EPRI update 70 to their 2008 publication revised the air preheate r penetration factor for PRB coal from 0.49 (2008 ver sion) to 0.36 (2010 version). Given the high alkalinity of PRB ash, we expect rem oval of H 2 SO 4 from PRB coal to provide more than just 10% removal of H 2 SO 4 , and the revised EPRI report is consistent with this expectation. Althou gh FCPP ash may be less alkaline than PRB ash, because the quantity of ash at FCPP is so much greater 71

, we expect FCPP ash to still provide enough bulk alk alinity to provide some removal of H 2 SO 4 . Formation of SO 3 is highly dependent on coal and boiler type and ash characteristics, and PRB coal and FCPP coal are not identical, however, EPA has determined that use of the PRB values repre sent the best available estimates for FCPP coal. Because of the inconsiste ncies between APS’s rationale and the data presented in EPRI 2008 and EPRI 2010, EPA concludes that APS’ generalization is not supported and does not justif y the use of the Hardman 1998 penetration factor of 0.9 for FCPP. We followed th e 2010 version of EPRI report and used a penetration factor of 0.36 in our calcul ation.

Downstream of the air preheater, H 2 SO 4 is additionally lost to PM and SO 2 control equipment. EPA and AECOM used a penetrati on factor through the venturi scrubbers on Units 1 – 3 of 0.65. EPRI rec ommended this value for all coal types through wet venturi towers. Units 4 and 5 are equipped with wet FGDs and baghouses for SO 2 and PM control. EPA and AECOM used the EPRI-

70 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stati onary Power Plants

, Version 2010a, 1020636, Technical Update, April 201 0.
71 Coal used by FCPP is typically > 20% ash, whereas PRB coal is typically < 7% ash.Page 59 of 92 recommended penetration factors of 0.47 through the wet FGD and 0.1 through the baghouses.

Table 29: Assumptions used in Sulfuric acid (H 2 SO 4 ) Emissions Calculations AECOM EPA (ANPRM) EPA (Proposal) Fuel Impact Factor (SO 3 formation from combustion) 0.00111 0.00111 0.00111

Coal sulfur content (%) 0.772 0.772 0.772
Coal S conversion to SO 2 0.95 0.95 0.95 Conversion of SO 2 to SO 3 from SCR catalyst (%) 1 0.5 0.6 Penetration factor 72 through Venturi Scrubber (Units 1 – 3) 0.65 0.65 0.65 Penetration factor through Air Preheater (Unit 1 – 5) 0.9 0.49 0.36 Penetration factor through wet FGD (Units 4 and 5) 0.47 0.47 0.47 Penetration factor through Baghouse (Units 4 and 5) 0.10 0.10 0.10

2. Ammonia Background Concentrations

In our ANPRM, we described the method we used to a estimate ammonia background concentrations that we determined to be appropriate for the CALPUFF modeling to represent the amount of available ammon ia that emissions from FCPP would encounter on the way to a given Class I area. Because very little monitored ammonia data is available, the IWAQM Phase 2 document 73 recommends a default ammonia background value, which is 1 ppb for arid r egions. Alternative levels may be used if supported by data. In their January 200 8 BART modeling protocol (p. 4-1) APS expressed the concern that CALPUFF over-predict s ammonium nitrate in winter. On the other hand, the USDA Forest Service expressed the concern that ammonia levels used by AECOM were too low, partly b ased on measurements in the Four Corners area. 74

To address these concerns using an objective approa ch based on monitored data, EPA estimated ammonia background for all Clas s I areas (except Mesa Verde National Park, see below) by a back-calculation fro m measurements at monitors run by the IMPROVE program 75 . IMPROVE monitors do not measure ammonia directly ; rather, they measure particulate sulfate and nitrat e. In the atmosphere, particulate sulfate and nitrate are essentially all in the form of ammonium sulfate and ammonium nitrate, respectively. Using the chemical formulas of these compounds, EPA calculated the amount of ammonia needed to combine with gaseous sulfate and nitrate in order to form the measured particulate sulfate a nd nitrate. The formulas are respectively (NH 4 ) 2 SO 4 and NH 4 NO 3 , so there must be two ammonia molecules (NH 3 ) for each sulfate (SO 4 ), and one ammonia for each nitrate (NO 3 ). The IMPROVE measurements are in μg/m 3 (NH 3 mass per volume of air), while

72 Penetration factor = 1 - Control Efficiency
73 Interagency Workgroup On Air Quality Modeling (IWAQ M) Phase 2 Summary Report And Recommendations For Modeling Long Range Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998, http://www.epa.gov/scram001/7thconf/calpuff/phase2. pdf
74 Personal communication, Rick Graw, USDA Forest Ser vice to Scott Bohning, EPA, February 2, 2009.
75 Interagency Monitoring of Protected Visual Environ ments http://vista.cira.colostate.edu/improve/Page 60 of 92 CALPUFF ammonia input must be in ppb (NH 3 volume per volume of air), so results must be converted to ppb using the ideal gas law, w hich depends on temperature and pressure. Since temperature and pressure are not a vailable at IMPROVE sites, a standard atmosphere was assumed 76 (pressure of 1 atm = 101.325 kPa; temperature = 298.16 K = 25° C). The result of the calculation i s a 24-hour average ammonia estimate in ppb for each monitor and for each measu rement day (typically every 3 rd calendar day).

The monthly values required by CALPUFF were based o n these daily values, as described below. The estimate represents a lowe r bound on the ammonia that must have been present; it does not include any ammonia remaining in gaseous form, since the latter is not reflected in the particulate sulf ate and nitrate measured at the monitor. For the ANPRM and this proposal EPA consulted with the FLMs on using this method. EPA recognizes that it is not perfect, but the lack of monitored ammonia data and the limitations in how the CALPUFF model u ses ammonia make it a reasonable approach that does rely on available mea sured data.

For the ANPRM, EPA performed this back-calculation using 2005-2007 data for all 14 IMPROVE monitors at Class I areas in the modeling domains. For each monitor, EPA used the maximum calculated value for each calendar month to represent the month. Then, for each month, EPA ave raged over all monitors 77

, resulting in a single value for each of the 12 cale ndar months. For the months of May and July, this back-calculation resulted in a somew hat lower value than the IWAQM default of 1 ppb which was also used by APS; for th ese months EPA used 1 ppb. The back-calculation results ranged from 0.7 ppb in the winter to 1 ppb in summer, except for the value of 1.3 ppb in June.

As a basic check in the ANPRM on the reasonableness of the ammonia background concentrations, EPA compared the nitrate measured at the Grand Canyon with the nitrate predicted by CALPUFF for Navajo Ge nerating Station. EPA found that the predicted values were within the range of observed values, though at the high end. Thus they have a degree of conservatism while remaining realistic. In the real atmosphere, NO x from many sources competes with FCPP for the avail able ammonia. But for purposes of modeling visibility impacts rel ative to natural background, i.e. the situation for which there are no anthropogenic sour ces, it is reasonable to assume the ammonia is all available for reacting with the poll utants in the plume from FCPP.

Ammonia background concentrations for Mesa Verde Na tional Park were derived from measured ammonia concentrations in the Four Corners area, as described in Sather et al. , (2008) 78 . Monitored data was available within the park, bu t

76 The Class I areas are at higher elevations than us ed in the standard atmosphere, so pressure and also temperature would be lower. Since these work in opposite direct ions in the formula for converting to ppb, these ef fects tend to cancel each other. In any case the net effect is s mall relative to that of the other uncertainties an d assumptions in the method.
77 Results from Zion were not used, as they were inco mplete and also appeared anomalous.
78 Mark E. Sather et al. , 2008. “Baseline ambient gaseous ammonia concentra tions in the Four Corners area and eastern Oklahoma, USA”. Journal of Environmental Mo nitoring, 2008, 10, 1319-1325, DOI: 10.1039/b807984 fPage 61 of 92 because particulate formation happens within a poll utant plume as it travels, rather than instantaneously at the Class I area, EPA also examined data at locations outside the park itself. Monitored 3-week average ammonia at the Substation site, some 30 miles south of Mesa Verde, were as high as 3.5 ppb, though generally levels were less than 1.5 ppb. Maximum values in Mesa Verde were 0. 6 ppb, whereas other sites' maxima ranged from 1 to 3 ppb, but generally values were less than 2 ppb. EPA used values estimated from Figure 5 of Sather et al. , (2008), in the mid-range of the various stations plotted. The results ranged from 1.0 ppb in winter to 1.5 ppb in summer. See Table 22.

Table 30: Ammonia background concentrations in ppb determined by EPA used in ANPRM
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec All Class I areas 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9 Values for Mesa Verde only 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0

3. Hydrogen Chloride and Hydrogen Fluoride

AECOM did not include estimates of hydrogen chlorid e (HCl) or hydrogen fluoride (HF) in their visibility modeling . During discussions with the FLMs prior to our ANPRM, the National Park Service (NPS) recommended that we address HCl and HF emissions for their potential to impact visibility. HCl is known to have the capacity to react with ammonia to form particulate ammonium chloride. Therefore, although HCl and HF emissions are not included in the WRAP modeling protocol, EPA estimated emissions of these compounds and included them in the visibility modeling as fine PM 79 , and provided a detailed discussion of our emissions estimates in the ANPRM. EPRI submitted
comments 80 on the ANPRM stating that the inclusion of HCl and HF as fine PM is inappropriate and provided calculations suggesti ng that after emission into the atmosphere, HCl and HF tend to remain in the gas ph ase, not the particulate phase, and also that the solubility of chloride and fluoride ions into watercontaining particles would be inhibited by the pres ence of sulfate, whose solubility is orders of magnitude higher. Therefor e, in this proposal, EPA removed HCl and HF emissions from our modeling inpu ts for fine PM.

4. Alternative Visibility Metrics

In the ANPRM, we presented four ways to express the visibility improvement from the NO x and PM control technologies: (1) deciview improvement at each Class I area, (2) the sum of th e improvements at all areas, (3) the percentage change in deciview impacts compa red to the baseline at each area, and (4) a metric that accounts for the size o f the land area over which

79 NPS recommended HCl and HF be included in the cate gory “condensable organic PM”. For CALPUFF modeling, EPA included HCl and HF into fine PM inst ead of condensable organic PM because they are inor ganic, and because they are not subject to the chemistry i n CALPUFF that is specific to organic compounds.
80 Comments submitted by Eladio Knipping, EPRI dated October 26, 2009.Page 62 of 92 controls provide visibility benefits. Each of thes e has advantages and disadvantages. Their absolute worth is somewhat in the eye of the beholder, but all of them provide useful information on visibilit y impacts, as long as their inherent limitations are understood. Deciview impr ovement at each Class I area is the primary metric under the BART guidelines. T he third and fourth of the metrics, percentage and land area weighting, are de scribed below.

The motivation for the second and fourth metrics, which involve sums over Class I areas, is to provide a single number f or comparing control scenarios to each other. There are multiple Class I areas, wi th different visibility impacts for each, but there is no established metric for expres sing visibility impact considering all areas together in a single number. The overall impact can be assessed more or less intuitively, weighing the var ious area impacts and the number of affected Class I areas. As an alternativ e to such intuitive or implicit weighing, in the ANPRM, EPA presented two explicit metrics, described below.

For the percentage metric, EPA used least-squares regression analyses of the visibility modeling results from the 2001 – 200 3 modeling period to determine the percent change in deciview impacts resulting fr om the application of control technologies compared to the baseline. The percent change is equal to one minus the slope from linear regression of the control sce nario’s daily delta deciviews against those of the baseline. Data from all model ed days was used, not just the highest impact days. Based on the modeling we cond ucted for the ANPRM, we estimated delta deciview improvements of 42 – 59% f rom SCR on all 5 units, and 14 – 25% from LNB/LNB+OFA on all 5 units.

The percentage metric is not intended to represent the visibility improvement relative to current conditions, which i nclude impacts from many other anthropogenic and nonanthropogenic sources; 5 9% improvement does not mean that visibility impairment in the current atmo sphere is reduced by that amount. Rather, it represents improvement in just the FCPP contribution to impairment. By the nature of percentages, a featur e of this metric is that when baseline impacts are small, even a small deciview b enefit from controls may give a large percentage improvement. Conversely, when b aseline impacts are high, even a relatively large deciview improvement may gi ve only a modest percentage improvement. This metric emphasizes relative impro vements in FCPP’s impairment contribution over absolute deciview impr ovements in visibility.

For the land area metric, we multiplied the 98th p ercentile delta deciviews for each Class I area by its land area in km 2 , giving a size-weighted measure of visibility improvement. We presented these for eac h Class I area, and also the sum of these for all Class I areas together. This weighting by land area reflects the fact that a larger Class I area will have a vis ibility improvement at more locations than a smaller area. The Grand Canyon ha s a land area of 3972 km 2 , so this metric gives substantially more weight to impr ovements there than to the Black Canyon of the Gunnison, with an area of only 53 km 2 , whereas a simplePage 63 of 92 sum of deciviews weights them equally. The main ef fect of the land area metric, as compared to a simple sum of deciviews, is to giv e greater weight to the larger Class I areas such as Canyonlands, Capitol Reef, We st Elk, and especially the Grand Canyon.

The simple sum of delta deciviews considers each C lass I area to be equally important, while the land area weighted sum considers larger areas to be more important, reflecting the fact that a larger C lass I area will have a visibility improvement at more locations than a smaller area. A feature of the metric is that a relatively small improvement at a large area woul d count more than a large improvement at a small area. Weighting by land are a can seem reasonable or not, depending on how relevant one considers the particu lar sizes of the Class I areas defined by Congress, and how relevant the magnitude of an improvement is in comparison with the land area experiencing that imp rovement. A defect of the land area metric is that it assumes that the visibi lity improvement is the same at every location within a given Class I area; in real ity visibility impacts and improvements vary in time and space. A more elabor ate metric could consider this variation, and even the number of visitors at various times of year, the specific locations they visit, and the degree of en joyment they experience. The weighted land area metric considers the relative si zes of Class I areas, but in a way that can easily be calculated, unlike those ela borations.

Various ANPRM commenters objected to this metric o n grounds of its seeming artificiality, its complexity, and its unfa miliarity. Any metric entails judgements about the relative importance of the mag nitude, frequency, and spatial coverage of visibility improvements; this is especi ally so for a metric that combines impacts from multiple Class I areas, since it assigns an importance to each area relative to the others. Without guidance or general agreement on these various judgements, discussion tends to focus on th e merits of the metric rather than on the visibility implications of its calculat ed number. For this proposal EPA did not calculate or consider the land area weighte d metric.

F. Affected State, Tribe, and FLM Consultation

1. Baseline Visibility Impacts of FCPP

The Navajo Nation commented that coal-fired power plants are relatively small contributors to regional haze in the surround ing Class I areas based on studies by the Grand Canyon Visibility Transport Co mmission and the Western Regional Air Partnership (WRAP), which estimated th at NO x emissions from stationary sources probably cause 2 – 5% of visibil ity impairment on the Colorado Plateau 81

.

81 Stationary Source NO x and PM Emissions in the WRAP Region: An Initial As sessment of Emissions, Controls, and Air Quality Impacts – Final Report of the WRAP Market Trading Forum. October 1, 2003. http://www.wrapair.org/forums/mtf/nox-pm.html.Page 64 of 92 The estimate from the initial WRAP assessment of t he visibility impairment from stationary sources is based on the 20% worst visibility days on the Colorado Plateau. WRAP determined that on thos e worst visibility days, visibility impairment from particulate nitrates is 6 – 18%. Because stationary sources contributed 25% of the WRAP NO x emissions inventory, WRAP estimated that stationary sources were responsible for 25% of the visibility impairment (i.e., 25% of 6 – 18% = 2 – 5%). Howeve r, the 2003 WRAP report further states that upon cursory examination of the daily data collected in 2001 on the Colorado Plateau, some of the 20% worst days ar e dominated by particulate nitrate and exceed the annual average. WRAP provid ed a few examples of nitrate contributions to visibility impairment ranging from 31 – 55%. EPA notes that there is likely to be much greater variability in t he nitrate contribution to visibility impairment than suggested by the WRAP estimate of 2 – 5% based on a 20% subset of annual data.

Mesa Verde National Park, located in the State of Colorado, is the closest Class I Area to FCPP. In a letter dated May 21, 200 8 to EPA Region IX, sent prior to the ANPRM, Paul Tourangeau, Director of th e Air Pollution Control Division in the Colorado Department of Public Healt h and Environment (“Colorado”), describes a tool developed by the WRA P called the Weighted Emissions Potential (WEP, on WRAP TSS (Technical Su pport System) Source Apportionment web site, http://vista.cira.colostate .edu/TSS/Results/SA.aspx). The WEP uses back-trajectories and spatially gridded em issions data to identify the geographic regions that contribute to visibility im pairment. Colorado conducted a WEP analysis for Mesa Verde for visibility impacts from nitrate that indicates the two grid cells which contain FCPP contribute over 5 0% to the nitrate visibility impairment at Mesa Verde and Weminuche Wilderness o n worst visibility days.

2. Sulfuric Acid Emission Estimates

The Navajo Nation supported the penetration factor for the air preheater relied on by FCPP in their calculations for sulfuri c acid emissions, but encouraged EPA to use measurement data when available. The Na tion pointed to EPA’s request to Salt River Project to conduct source tes ts to measure current (baseline) sulfuric acid emissions from Navajo Generating Stat ion and recommended we review the test results and revise the modeling as necessary. The NGS test results are not directly applicable to FCPP for numerous re asons, including differences in the types of air pollution control equipment used a nd those impacts on sulfuric acid capture. Additionally, regardless of where th e source test was conducted, unless the testing protocol was designed to measure inlet and outlet concentrations at each potential sulfuric acid cont rol point (e.g., air preheater, baghouse, etc.), it is not possible, based solely o n exit emission rates from the stack, to determine which of the many assumptions u sed in the sulfuric acid emissions calculations requires revision.Page 65 of 92 However, it may still be instructive to examine predicted and measured sulfuric acid emissions from NGS. NGS conducted so urce tests on November 16 – 17, 2009 to measure baseline sulfuric acid emissi ons from all three units using the controlled condensate method 82 . These baseline emissions represent sulfuric acid emissions without SCR. From three units, NGS reported an average emission rate of 0.00009 lb/MMBtu (9 x 10 -5 ). The three units show significant variability (9.43 x 10 -5 , 1.64 x 10 -4 , and 1.75 x 10 -5 ), but are all below emissions predicted by the EPRI model using both EPA and NGS assumptions (4.2 x 10 -4 and 4.9 x 10 -4 lb/MMBtu) 83 . These source tests from NGS suggest that the cumulative result of all the assumptions is that th e model overpredicts sulfuric acid emissions compared to measurements. Because E PA used a lower penetration factor for the air preheater than AECOM , the EPA estimate is closer to the measured value 84 . Again, we believe it is not appropriate to apply results from NGS to FCPP, therefore, we rely on the rationa le we provided above, and not the NGS source tests, to justify our assumption s for the sulfuric acid emissions calculations in Section 6.E.a.

3. Ammonia Background Levels

The Arizona Department of Environmental Quality (A DEQ) stated 85 that since the back-calculation method only indirectly e stimates ammonia via measurements of sulfate and nitrate, it may not qua lify as “specific data... available for the modeling domain”, which the IWAQM Phase 2 document recommends if alternatives to the 1 ppb default are to be used 86 . This can be interpreted as an implicit ADEQ recommendation for staying with the 1 ppb default. ADEQ also expressed concern that the back -calculation method for estimating ammonia background may over-estimate the concentration, because it relies on particulate sulfate and nitrate measureme nts that a) already include the effect of FCPP emissions, leading to “double-counti ng”, and b) may have formed due to distant sources, rather than having been for med locally. Finally, ADEQ further recommended additional ammonia monitoring f or assessment of the accuracy of the back-calculation method.

The National Park Service and the U.S. Forest Serv ice (NPS and FS, and together, FLMs 87 ) supported the back-calculation methodology and re sults we

82 Salt River Project Navajo Generating Station – Aci d Mist Emissions Test Report by Catalyst Air Manage ment, Inc. Report Number 264-001 (December 31, 2009).
83 Note that for the hot-side ESP at NGS, EPA assumed a penetration factor of 1, whereas AECOM assumed a penetration factor of 0.63, thus the difference in the air preheater penetration factor used by EPA (0 .49) and AECOM (0.9) is less apparent compared to FCPP, whic h does not use hot-side ESPs.
84 If we included additional penetration from the hot -side ESP, EPA’s estimated sulfuric acid emissions would be closer to measurements.
85 ADEQ, October 28, 2009 comment letter to EPA’s ANP RM docket, comments 12- 17 (electronic file “10-28 -09 Grumbles.pdf”)
86 IWAQM Phase 2 document, section 2.2.2, p.14
87 The U.S. Fish and Wildlife Service is also a Feder al Land Manager in charge of National Wildlife Refu ge Class I areas. No refuges are within the 300 km modeling d omain of FCPP and EPA did not receive comments on o ur ANPRM from the U.S. FWS – National Wildlife Refuge System – Branch of Air Quality, therefore we use th e termPage 66 of 92 presented in the ANPRM. The FLMs determined the ba ck-calculation method was more comprehensive because it considers both am bient ammonia measurements at specific locations within the model ing domain and the amount of ammonia that must have been present along the trans port path from the emissions sources to the Class I areas. Because CALPUFF uses of only a single value for monthly concentrations to represent ammonia, which shows significant spatial and temporal variability, the FLMs determined that it is most appropriate to consider the amount of ammonia along the regional t ransport path in the ammonia background value. Additionally, the FLMs recommend ed that the modeling results be used in a relative sense for comparing c ontrol technologies rather than continue disagreement over the absolute values used for the background ammonia. However, the Forest Service still recomme nded placing more emphasis on the visibility results from EPA modeling using b ack-calculated ammonia values. The Navajo Nation supported the use of amb ient measurements where possible and noted that Salt River Project (SRP), p rimarily in the interest of Navajo Generating Station, has installed ammonia mo nitors near Grand Canyon National Park to better inform background ammonia l evels for CALPUFF modeling. Results from SRP’s ammonia monitoring pro ject will be available for consideration in our upcoming BART proposal for the Navajo Generating Station.

4. Additional Modeling Results

During our consultations with the FLMs prior to ou r ANPRM, NPS commented that AECOM likely underestimated visibili ty impacts of the facilities because AECOM modeled inorganic condensable particu late matter as only sulfuric acid mist. NPS conducted their own CALPUF F modeling analysis (See Table 31) to estimate visibility benefits of contro ls and used AECOM estimates for SO 2 and NO x and NPS estimates of PM emissions and background a mmonia. Although NPS supported our use of back-calculated a mmonia background values, for comparison purposes, NPS used a year-round back ground ammonia concentration of 1 ppb, consistent with the IWAQM d efault.

FLM in this proposal to refer only to the National Park Service and the Forest Service. The FWS – New Mexico Biological Services Field Office did submit comment s on the ANPRM, but in the capacity of a FLM of an impacted Class I area.Page 67 of 92

Table 31: NPS Modeling Results – Average 8 th High Baseline and Delta dv Improvement from 2001 – 2003 Class I Area Baseline Improvement from LNB/LNB+OFA Improvement From LNB+SCR Arches National Park 4.22 0.72 2.59
Bandelier Wilderness Area 3.01 0.53 1.70 Black Canyon of the Gunnison WA 2.80 0.62 1.89 Canyonlands NP 5.95 0.93 3.59 Capitol Reef NP 3.42 0.61 1.99 Grand Canyon NP 2.16 0.48 1.37
Great Sand Dunes National Monument 1.27 0.31 0.82

La Garita WA 1.80 0.46 1.13
Maroon Bells Snowmass WA 1.14 0.29 0.75 Mesa Verde NP 6.22 0.54 2.59
Pecos WA 2.20 0.44 1.23
Petrified Forest NP 1.63 0.36 0.93 San Pedro Parks WA 3.97 0.76 2.22
Weminuche WA 2.13 0.53 1.48 West Elk WA 2.90 0.64 1.90
Wheeler Peak WA 1.75 0.41 1.09
Total 46.59 8.64 27.25

5. Visibility Metrics

The FLMs supported our consideration in the ANPRM of the cumulative visibility improvement anticipated at all of the im pacted Class I areas. However, the FLMs did not support the alternative visibility met ric we introduced in the ANPRM that multiplies the 98 th percentile change at the highest receptor by the l and area of the Class I areas because the metric values larger Class I area s more than smaller Class I areas. Instead, NPS and FS discussed alternatives to our a rea-weighted visibility metrics. FS discussed two different techniques for accounting f or visibility impacts over multiple days at multiple Class I areas. The first techniqu e sums the daily maximum receptor deciview impacts, over 365 days, at all Class I are as in the modeling domain to yield a metric in units of $/Class I area dv-day (dollar pe r Class I area deciview-day). The second technique is similar to the first, but the single d aily maximum receptor is chosen from all of the Class I areas in the modeling domain pooled together, yielding a metric in units of $/dv-day.

NPS introduced another visibility metric called th e pollutant effectiveness (PE) factor, which is the visibility improvement (in dv) divided by the annual emission reduction (in tons). NPS uses the PE factor to est imate visibility improvement resulting from the proposed controls on each EGU individually , without modeling each EGU separately. NPS then uses the estimated visibility improvement from each EGU to derive unit-specific dollar per dv values for the various control scenarios. Based on their modeling and cost analyses, NPS estimates that the cost effectiveness of SCR rangesPage 68 of 92

from $1.9 – 2.7 million per dv, in contrast to APS’ s cost effectiveness of $12.7 – 17.4 million per dv. NPS asserts that APS’s costs for S CR are overestimated and visibility benefits are underestimated, but acknowledge that t here are considerable uncertainties and differences between the approaches used by APS and NPS to derive their cost estimates. To create a “middle-ground” estimate, N PS combined the cost estimates from APS and their own visibility modeling results to ca lculate cost effectiveness values of $4.9 – 6.6 million per dv. Considering a $17 milli on per dv reasonable cost benchmark based on other facilities, NPS determined that all estimates of cost effectiveness, including APS’s upper range cost estimates for SCR and lower range estimates for visibility improvements, are at or below the benchm ark, and thus concluded that SCR is BART for all units at FCPP.

G. EPA Conclusions Regarding this Factor

EPA remodeled the visibility impacts of FCPP using revised emission inputs as discussed above. Briefly, we revised two assumptio ns in the sulfuric acid emissions calculation – the air preheater penetration factor (from 0.49 to 0.36) and the SO 2 to SO 3 conversion efficiency of the SCR catalyst (from 0.5 % to 0.6%). Additionally, we no longer included HCl and HF emissions in the fine PM input to CALPUFF. Finally, we relied on model results using a default 1 ppb ammon ia background; those results were corroborated using a revised version of the ammonia back-calculation approach discussed above for the ANRPM.

1. Ammonia Background Values

For ammonia background concentrations in this prop osal, EPA used the IWAQM default of 1 ppb, and corroboration from mode ling using ammonia levels from a back-calculation procedure relying on sulfate and nitrate measurements at Class I areas. EPA considered vari ous objections to the backcalculation procedure raised by commenters on the A NPRM. EPA also strongly considered the opinions of the FLMs, who generally favored the back-calculation approach. EPA has determined that the 1 ppb defaul t and corroboration from the back-calculation results are a reasonable basis for assessing visibility impacts, in light of the uncertainties involved in estimating a mmonia. However, EPA also performed sensitivity modeling using the lower ammo nia concentrations originally used by APS in their modeling. Below we describe the approach used, and then address various concerns over the back-cal culation procedure.

Based on comments we received on the ANPRM, we ree xamined the ammonia background values. For this proposal, EPA used the IWAQM default of 1 ppb, with corroboration from a variant of the bac k-calculation procedure that was used for the ANRPM, described above. In the ba ck-calculation for this proposal, instead using of the maximum for each mon th, EPA used the mean plus two standard deviations. (For the normal distribut ion, this represents the 97.5 th percentile.) This remains a conservative estimate, but compared to the maximumPage 69 of 92 it is more in line with the BART guidelines princip le of avoiding unusual meteorological conditions (the guidelines’ rationa le for using the 98 th percentile delta deciviews instead of the maximum), and partly addresses some commenters’ concerns that the method is overly conservative. T he monthly average was also considered, but was felt to be too low to represent the daily high impact conditions that can occur and that are the focus of visibility assessments under the BART guidelines. Also, instead of averaging over a ll Class I areas, EPA used different sets of values for each of five different groups of Class I areas. The groups were defined geographically, with one for ea ch of the directions northwest, northeast, southeast, southwest, and wit h the Grand Canyon in a group by itself. Areas that are nearer to each other geo graphically and have broadly similar ammonia estimates are grouped together, pro viding a better match to particular areas than the single average over all a reas used in the ANPRM. The groups are listed in Table 32 and the ammonia backg round concentrations are in Table 33. For the northwest areas, the values rang e from 0.6 to 1.0 ppb; for the northeast the range is 0.4 to 0.8 ppb; for the Gran d Canyon and the southeast group the range is 0.5 to 1.1 ppb; and for the sout hwest it is 0.6 to 1.3 ppb. The lower values are in the winter, and the higher ones in summer.

Table 32: Class I area groupings for ammonia backgr ound used in this proposal Grouping IMPROVE monitors Class I Areas Grand Canyon GRCA2 Grand Canyon
northwest areas BRCA1, CANY1, CAPI Arches, Bryce Canyon* 88 , Canyonlands, Capitol Reef

northeast areas GRSA1, WEMI1, WHPE1, WHRI1 Black Canyon of the Gunnison, Great Sand Dunes, La Garita, Maroon Bells Snowmass, Pecos, Weminuche, West Elk, Wheeler Peak
southeast areas BAND1, SAPE1 Bandelier, San Pedro Parks

southwest areas IKBA1, PEFO1, SYCA1 Mazatzal*, Petrified Forest, Pine Mountain*, Sycamo re Canyon*

88 Areas denoted with a “*” were not modeled for FCPP , but monitors included in ammonia calculation as n earest to the areas modeledPage 70 of 92

Table 33: Ammonia background concentrations in ppb modeled by EPA used in proposal Ammonia scenario Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Am1: IWAQM default 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 Am2: AECOM values 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2 Am3: EPA average of

max 89 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9

Am4: Mesa Verde only 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0 Am5gc 90 : Grand Canyon only 0.52 0.46 0.63 0.97 1.02 1.12 0.93 0.98 0.77 0.82 0.83 0.58 Am5nw: northwest areas 0.74 0.79 0.56 0.94 0.84 0.99 0.91 0.83 0.65 0.61 0.73 0.90
Am5ne: northeast areas 0.43 0.49 0.49 0.75 0.70 0.81 0.66 0.66 0.61 0.68 0.59 0.45 Am5se: southeast areas 0.80 0.66 0.62 0.82 0.79 1.14 0.94 1.11 1.00 1.01 0.81 0.50
Am5sw: southwest areas 0.71 0.67 0.76 1.11 1.09 1.27 1.05 1.10 1.05 0.99 1.04 0.61

EPA could rely solely on the IWAQM default, but be lieves the backcalculation method is also useful, since it is an o bjective approach and relies on monitored data at the Class I areas where visibilit y is being assessed, and has a degree of conservatism. EPA is aware of various li mitations inherent to the method, some of which were raised by ANPRM commente rs.

Per the ADEQ comment on the ANPRM stated above (in section F.c.), for an alternative to default ammonia levels, the conte xt in the IWAQM Phase 2 document does seem to envisage measurement of ammon ia itself, rather than of other compounds that indirectly imply ammonia conce ntrations via a calculation: “However, given all the uncertainties in ammonia da ta, IWAQM recommends use of the background levels provided above, unless spe cific data are available for the modeling domain that would discredit the values cit ed” 91 . For this proposal, EPA is considering visibility impacts estimated using t he 1 ppb ammonia default. This is consistent with BART analyses carried out in man y other parts of the country. However, EPA continues to believe that the indirect back-calculation method provides a useful estimate that is based on measure d data, and helps ensure the robustness of the BART determination.

As noted in the IWAQM Phase 2 document, ammonia concentrations vary with temperature by a factor of 3 – 4, and also var y strongly with soil pH, and with the presence of local ammonia sources 92 . Thus ammonia is expected to vary temporally and spatially. Unfortunately, there is relatively little monitored ammonia data available to determine typical concent rations or their variation. Expanded ammonia monitoring would be desirable, but the BART guidelines do not envisage the initiation of a new monitoring pro gram as necessary for BART determinations; that would be a much larger underta king than the analysis procedures described in the guidelines. Other than the IWAQM default

89 Am3 is the average over all areas of the maximum calcu lated ammonia; used in the ANPRM, but not in this current proposal.. 90 Am5xx is the average over areas in group xx of the mean plus two standard deviations of calcul ated ammonia.
91 IWAQM Phase 2 document, section 2.2.2, p.14
92 IWAQM Phase 2 document, section 2.2.2, pp.14-15Page 71 of 92 supplemented by available measurements, there is no t an accepted method for estimating ammonia for use in CALPUFF visibility mo deling. In addition, even if such data were available, CALPUFF accepts only a si ngle ammonia value for each modeled month for the whole modeling domain, s o it uses little temporal variation, and no spatial variation. There are sub stantial uncertainties associated with the background ammonia concentration, and also compromises involved in any approach to estimate it.

EPA views the back-calculation method as providing a reasonable objective indicator of ammonia concentrations that the emission source’s plume can encounter as it travels to a Class I area, and not necessarily as a definitive estimate of ammonia concentration within the Class I area itself. It is not definitive because it is not a direct ammonia measu rement, but rather an indirect estimate based on integrated 24-hour sulfate and ni trate measurements. An effect of the indirectness is that it can only account for ammonia that is present at the monitor in the form of particulate ammonium (NH 4 + ), and not any that is present as free gaseous ammonia (NH 3 ). The method thus provides a lower bound on the total amount of ammonia present, and tends to under estimate the total ammonia available to interact with the source plume. (Conv ersely, a direct measurement of free ammonia does not include particulate ammonium, and so would also tend to underestimate the total ammonia available.)

While the method may tend to underestimate the tot al ammonia available, another aspect of the method is that it assumes tha t all of that ammonia is available to interact with emissions from the singl e source being modeled. In the real atmosphere, SO x and NO x emissions from multiple sources compete for the available ammonia. But CALPUFF modeling using the ammonia back-calculated from those measurements assumes all that ammonia is available to interact with the FCPP plume. This procedure would not be approp riate for assessing the actual impact of FCPP in the real atmosphere as par t of a source apportionment; in that case it might be considered “double countin g”, since the calculated ammonia includes ammonium from FCPP itself as well as from other sources. But for BART modeling it is acceptable. The assump tion that all the ammonia is available to FCPP emissions is comparable to assumi ng that there are no competing sources, similar to natural background co nditions. EPA believes that the back-calculation method is in accord with the B ART guidelines’ recommendation to assess visibility impacts relativ e to natural conditions.

The above-mentioned 24-hour integration aspect of the back-calculation method is desirable in that concentrations in the s ource plume when it arrives at the Class I area are the cumulative (integrated) re sult of conditions the plume has encountered on the way. The IMPROVE concentrations reflect ammonium particulate formation that resulted from various ga seous ammonia concentrationsPage 72 of 92 and various meteorological conditions encountered, which is desirable for estimating 24-hour visibility impacts. 93

On the other hand, an undesirable aspect of the in tegration is that for different hours within a given day, the sulfate and nitrate at the IMPROVE monitor may have arrived via different routes. Som e of those routes may have little relevance for the plume of the source being assessed, but the method assumes ammonia along all routes is available to in teract with the source plume. The same issue arises considering different days: s ome days’ transport routes to the monitor will have little relevance for the sour ce plume, yet their backcalculated ammonia is assumed to be available for t hat plume. That is, ammonium sulfate transported to the monitor from a completely different direction than FCPP adds to the ammonia calculated as available to the FCPP plume. Two considerations lessen the severity of t hese issues. First, other things being equal, these other transport routes would be just as likely to encounter below-average ammonia concentrations as to encounte r above-average ammonia. The various contributions to an IMPROVE monitor wit hin a day and over multiple days tend to balance each other in the ove rall distribution of calculated ammonia values, especially since averages over seve ral monitors are used. Second, this potential source of inaccuracy is less ened by considering multiple years of data; in the aggregate the range of ammoni a values derived from the method for hundreds of days is likely to be seen by the source’s plume at various times during that span. In any case, to properly a ssess the net effect of these potential problems would require a much more comple x analysis than envisaged under the BART guidelines, involving modeling of mu ltiple sources, the development of an ammonia inventory, and a model wi th more complete chemistry than CALPUFF.

In view of the lack of available ammonia data, and counterbalancing tendencies for under- and overestimation within the back-calculation method, EPA believes that it remains useful as a “ballpark” estimate of ammonia concentrations contributing to particulates at IMPR OVE monitors, since it is based on actual measured data, is easily computed, and on many days would be expected to represent ammonia concentrations encoun tered by the source’s plume. It appears to be conservative, while remaining real istic. Some conservatism is warranted given the BART guidelines’ emphasis on th e higher (98 th percentile) impacts, and also given that ammonia has generally been trending upward over the past decade. 94

93 Since nitrate has a fast equilibrium between gaseo us and particulate forms, it could be argued that f or nitrate the spatial integration over the plume path is less rel evant than conditions in the immediate vicinity of the Class I area. By this argument, for nitrate the 24-hour values co uld be considered as more of a temporal integration of conditions at the area, which is still desirable for estimatin g 24-hour visibility with CALPUFF.
94 Christopher M. B. Lehmann et al. , “Monitoring Long-term Trends in Sulfate and Ammon ium in US Precipitation: Results from the National Atmospheric Deposition Pr ogram / National Trends Network”, Water, Air, & Soil Pollution: Focus, Volume 7, Numbers 1-3, March, 2007, DOI:10.1007/s11 267-006-9100-zPage 73 of 92 As a rough check on the appropriateness of the bac k-calculated ammonia background concentration estimates, EPA compared CA LPUFF predictions of nitrate impacts from FCPP to nitrate measurements a t IMPROVE monitors in the modeled areas. If the assumed ammonia is too high, then too much ammonium nitrate will be simulated in the model, and predict ed nitrate will exceed the nitrate measured at the IMPROVE monitors. Given the uncert ainty in the method, some over-prediction is acceptable, but consistently lar ge over-predictions would be grounds for concern. The comparison was made for s even Class I areas in various directions from FCPP: Canyonlands, Capitol Reef, Gr and Canyon, Mesa Verde, Petrified Forest, San Pedro Parks, and Weminuche. Particular receptor points within each area were selected based on their high modeled nitrate impacts, and then a 2001-2003 time series of daily nitrate was g enerated for each. Statistical and graphical comparisons were made between these p redictions and the IMPROVE monitor measurements.

EPA found that there are many days for which the F CPP nitrate impact is far underpredicted, especially for Canyonlands, Cap itol Reef, Grand Canyon, and San Pedro Parks. This is to be expected, since und er some conditions and wind directions the FCPP plume will have little effect o n a given area, while the monitor will continue to reflect impacts from other pollution sources. For the other areas, there were also low to moderate nitrat e impact days with substantial overprediction. However, for all the areas, the pr edicted highs were comparable to the measured highs, based on the maximum, the 98 th percentile, and inspection of peaks on the time series graphs. The only over- predictions were for the am1 ammonia scenario (constant 1 ppb); they occurred fo r the 98th percentile at Mesa Verde and San Pedro Parks. Even for these areas, t he predicted maxima were close to the measured values. For the am1 scenario , the 98th percentile of predicted nitrate impacts varied between 21% and 14 6% of the 98th percentile of the IMPROVE measurement, depending on area. The pr edicted maxima varied between 68% to 102% of the IMPROVE maxima. For the back-calculated ammonia scenario am5, the corresponding ranges were 22% to 101% for the 98th percentile, and 39% to 80% for the maxima.

While these comparisons cannot be considered a mod el performance evaluation, at the higher impacts which are of the most regulatory interest, there is general agreement between the model predictions and the measurements. Certainly there does not appear to be any systemati c overprediction of nitrate highs using either of the ammonia background scenar ios considered by EPA.

2. Revised Emission Inputs for CALPUFF Modeling

For this proposal, we remodeled the anticipated vis ibility improvement from the use of LNB/LNB+OFA or SCR on Units 1 – 5 f or NO x control and PM controls on Units 1 – 3. The emission inputs we us ed are listed in Table 34 and are provided in more detail in the docket 95 . Because the modeling files are in a

95 See Excel spreadsheet titled “FCPP_BART_Scenarios_ Emissions_EPA_proposal.xls”.Page 74 of 92 format that cannot be uploaded to www.regulations.gov , these files are not in our online docket but are available upon request.

Table 34: EPA Modeling Inputs (lb/hr) Scenario FC0e- Baseline Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 522.54 615.12 1042.09 2026.10 2131.85
SO 4 1.51 1.51 1.95 0.37 0.37
NO x 2020.14 1599.47 1970.80 5015.98 4508.56
SOA 9.40 9.41 12.13 32.00 32.20 PM fine 38.07 57.76 59.56 100.93 48.02
PM coarse 15.50 23.52 24.26 77.12 36.69
EC 1.46 2.22 2.29 3.88 1.85 Scenario FC1e – PM control on Units 1 - 3 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 522.54 615.12 1042.09 2026.10 2131.85
SO 4 1.09 1.09 1.40 0.37 0.37
NO x 2020.14 1599.47 1970.80 5015.98 4508.56
SOA 9.40 9.41 12.13 32.00 32.20
PM fine 17.26 20.39 23.60 100.93 48.02
PM coarse 13.19 15.58 18.03 77.12 36.69
EC 0.66 0.78 0.91 3.88 1.85 Scenario FC2e – LNB + OFA on Units 1 – 5 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 522.54 615.12 1042.09 2026.10 2131.85
SO 4 1.51 1.51 1.95 0.37 0.37
NO x 1109.06 1073.25 1103.65 3561.35 3201.08
SOA 9.40 9.41 12.13 32.00 32.20
PM fine 38.07 57.76 59.56 100.93 48.02
PM coarse 15.50 23.52 24.26 77.12 36.69
EC 1.46 2.22 2.29 3.88 1.85 Scenario FC3e – SCR on Units 1 – 5 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5
SO 2 522.54 615.12 1042.09 2026.10 2131.85
SO 4 8.57 8.58 11.06 2.24 2.25
NO x 404.03 319.89 394.16 1003.20 901.71
SOA 9.40 9.41 12.13 32.00 32.20
PM fine 38.07 57.76 59.56 100.93 48.02
PM coarse 15.50 23.52 24.26 77.12 36.69
EC 1.46 2.22 2.29 3.88 1.85

3. Baseline Visibility Impacts of FCPP

Modeled impacts on the Class I areas of FCPP withou t additional controls for each ammonia scenario are shown in Table 35: EP A Modeling Results – 8 th High Delta dv Baseline from 2001 – 2003 for the Dif ferent Ammonia BackgroundPage 75 of 92 Scenarios. The table shows the 98 th percentile delta deciview impacts, considering days from all three modeled years toget her (rather than separate 98 th percentiles for each of the modeled years as was do ne by APS). Impacts depend strongly on the background ammonia assumed, increas ing as ammonia does. From lowest to highest, the ammonia concentrations as well as the impacts are in the order Am2, Am5, Am3, Am1. These are the APS/AE COM values Am2), the back-calculated mean plus two standard deviations ( Am5), the back-calculated maximum (Am3), and the IWAQM 1 ppb (Am1) default 96 . Scenario Am2 impacts are roughly half of the other scenarios, wh ich are fairly close together. The change from the Am5 variant in the ANPRM to the Am5 that is new to this proposal is about 12% on average, though for a few areas the impact had virtually no change.

Impacts generally decline with distance from FCPP, as would be expected since the plume disperses as it travels, though con ditions can be more or less favorable for transport to Class I areas in particu lar directions. Mesa Verde is the closest area and has clearly the highest impact, wh ile Maroon Bells Snowmass is the second most distant and has the lowest impact. The Grand Canyon is the most distant area, but has a somewhat higher impact than would be expected based on distance. For all ammonia scenarios, the northwest ern areas of Arches, Canyonlands, and Capitol Reef have impacts a bit hi gh for their distance, while Weminuche impacts are a bit low for its distance.

For all areas and ammonia scenarios, the modeled i mpact of FCPP without additional controls exceeds 1 deciview (except for Maroon Bells Snowmass in Am2), confirming that FCPP causes visibility impair ment in a large number of Class I areas.

96 As for the other tables, Mesa Verde impacts in the Am3 and Am5 columns are actually Am4, with concent rations derived from ammonia measurements rather than the b ack-calculation method.Page 76 of 92

Table 35: EPA Modeling Results – 8 th High Delta dv Baseline Impacts of FCPP on 16 Class I Areas from 2001 – 2003 for the Different Ammonia Ba ckground Scenarios Class I Area Baseline Impacts
Am1 Am2 Am3 Am5 Arches National Park 4.11 1.96 4.01 3.95
Bandelier Wilderness Area 2.90 1.74 2.86 2.76 Black Canyon of the Gunnison WA 2.36 1.54 2.29 1.92

Canyonlands NP 5.24 2.29 4.68 4.84 Capitol Reef NP 3.23 1.83 3.17 3.14 Grand Canyon NP 1.63 1.06 1.62 1.42 Great Sand Dunes NM 1.16 0.96 1.15 1.08
La Garita WA 1.72 1.39 1.70 1.59
Maroon Bells Snowmass WA 1.04 0.83 1.02 0.98 Mesa Verde NP 97 5.95 3.16 6.41 6.41
Pecos WA 2.16 1.58 2.07 1.90 Petrified Forest NP 1.40 1.16 1.40 1.39
San Pedro Parks WA 3.88 2.24 3.67 3.51 Weminuche WA 1.87 1.19 1.85 1.69
West Elk WA 2.76 1.98 2.75 2.37
Wheeler Peak WA 1.53 1.18 1.49 1.37
Total 42.94 26.09 42.14 40.32

4. New Results of Anticipated Visibility Improvement

For assessing visibility improvement for this prop osals, EPA relied primarily on the ammonia scenario with the IWAQM 1 ppb default (Am1), corroborated by scenario with the back-calculated m ean plus two standard deviations (Am5), with the other scenarios consider ed as sensitivity analyses. Also, EPA mainly considered improvement in delta de civiews relative to the baseline, with additional consideration of its perc ent improvement. The delta dv improvement and percent change for each ammonia bac kground scenario are shown in Tables 36 – 39.

Summarizing results from the tables, the visibilit y improvement from applying SCR is about two and a half times as large as that from applying LNB. For the lowest ammonia scenario, APS’s Am2, the abs olute deciview improvements for Am2 are only about half of those f or the other scenarios, ranging from 0.12 dv to 0.36 dv for LNB, and 0.38 d v to 0.98 dv for SCR. All SCR benefits are at about 0.5 dv or higher, except for Grand Canyon and Maroon Bells Snowmass. The 0.5 dv level is an amount cons idered to be perceptible and to “contribute” to visibility impairment under the BART guidelines (p. 39120).

97 Ammonia background values for Mesa Verde under col umns “Am3” and “Am5” are based on scenario Am4. This applies to all tables of modeling results.Page 77 of 92 So, even for the lowest ammonia scenario, APR’s Am2 , the visibility improvement from SCR is significant, especially con sidering that 14 Class I areas would experience that improvement. By contrast, im provements from LNB are all below the 0.5 dv level.

For the other ammonia scenarios visibility improve ments for both LNB and SCR are roughly double those for Am2. For Am1 (IWAQM 1 ppb default), LNB improvements range from to 0.27 to 0.79 dv, wit h 10 of 16 areas experiencing more than a 0.5 dv improvement, but wi th all areas’ improvements under 1 dv. For SCR, benefits range from 0.65 to 2.4 dv, with all areas having an improvement greater than 0.5 dv, and 12 of 16 areas having more than a 1 dv improvement. Four have more than a 2 dv improvemen t. Thus both LNB and SCR result in visibility improvements above the “co ntribute to impairment” or just perceptible level of 0.5 dv at all 16 Class I areas. However the benefits of SCR are generally more than twice as high as for LN B, and mostly above the BART Guidelines “cause impairment” level of 1.0 dv; these changes would be definitely noticeable by most observers at the Clas s I areas.

For Am5 (back-calculated mean plus two standard de viations, except Mesa Verde), the LNB improvements range from 0.28 d v to 1.0 dv; 6 of the 16 areas’ improvements are at 0.5 dv or above. The SC R improvements are again about twice as high as for LNB, ranging from 0.65 d v to 2.25 dv. All the SCR improvements are above 0.5 dv; 9 of the 16 areas ha ve improvements over 1.0 dv, and three are at over 2 dv. While the modeled impr ovements are less than for the Am1 case, the conclusion is similar: LNB benefits w ould be perceptible and significant, and for SCR much more so, with improve ments definitely noticeable by most observers at the Class I areas.

Despite uncertainty over background ammonia concen trations, several conclusions can be drawn. There would be a visibil ity improvement from applying either LNB or SCR to FCPP, except that the LNB benefit is under 0.5 dv for the low-ammonia Am2 scenario. 98 The benefit of SCR is significantly greater than for LNB, improving visibility by a perceptible amount even for the lowest ammonia scenario, and by more noticeable amounts fo r the other ammonia scenarios.

98 Even though that improvement would not be percepti ble in itself, it is still worth considering as par t of the overall regional haze planning process, since it would occu r cumulatively with improvements due to controls on other

sources.Page 78 of 92 Table 36: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in De lta dv Impact Compared to Baseline Impacts from 2001 – 200 3 using Am1 Ammonia Background Scenario Class I Area Distance to FCPP Baseline

Impact Improvement From

PM Control Improvement From

LNB/LNB+OFA Improvement From SCR kilometers Delta dv Delta dv % Delta dv % Delta dv % Arches National Park 245 4.11 0.01 0 0.87 18 2.40 55
Bandelier Wilderness Area 216 2.90 0.01 0 0.54 21 1.62 57
Black Canyon of the Gunnison WA 217 2.36 0 0 0.46 23 1.42 60
Canyonlands NP 214 5.24 0.02 0 0.79 16 2.81 51 Capitol Reef NP 283 3.23 0.01 0 0.77 18 1.87 52 Grand Canyon NP 345 1.63 0.01 0 0.34 20 0.88 55
Great Sand Dunes NM 279 1.16 0 0 0.31 25 0.67 62
La Garita WA 202 1.72 0 0 0.44 25 1.05 62 Maroon Bells Snowmass WA 294 1.04 0 0 0.27 26 0.64 63

Mesa Verde NP 62 5.95 0.02 1 0.62 13 2.43 45
Pecos WA 258 2.16 0.01 0 0.52 23 1.15 58
Petrified Forest NP 224 1.40 0.01 0 0.27 21 0.65 56 San Pedro Parks WA 160 3.88 0.02 1 0.68 19 2.02 53
Weminuche WA 137 1.87 0 0 0.49 25 1.19 62 West Elk WA 245 2.76 0 0 0.65 23 1.70 60
Wheeler Peak WA 265 1.53 0.01 0 0.37 24 0.84 59
Total Delta dv or Average % Change in

Delta dv 42.94 0.13 0 8.39 21 23.34 57Page 79 of 92 Table 37: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in De lta dv Impact Compared to Baseline Impacts from 2001 – 200 3 using Am2 Ammonia Background Scenario Class I Area Distance to FCPP Baseline

Impact Improvement From

PM Control Improvement From

LNB/LNB+OFA Improvement From SCR kilometers Delta dv Delta dv % Delta dv % Delta dv % Arches National Park 245 1.96 0.01 1 0.20 10 0.63 33
Bandelier Wilderness Area 216 1.74 0.01 1 0.20 14 0.66 40

Black Canyon of the Gunnison WA 217 1.54 0.01 0 0.28 16 0.72 46
Canyonlands NP 214 2.29 0.02 1 0.22 8 0.64 27 Capitol Reef NP 283 1.83 0.01 1 0.25 11 0.62 32 Grand Canyon NP 345 1.06 0 1 0.13 12 0.38 33
Great Sand Dunes NM 279 0.96 0 0 0.24 22 0.48 57
La Garita WA 202 1.39 0 0 0.29 20 0.73 55 Maroon Bells Snowmass WA 294 0.83 0 0 0.17 20 0.43 54

Mesa Verde NP 62 3.16 0.05 1 0.12 7 0.54 25
Pecos WA 258 1.58 0.01 1 0.26 16 0.63 45
Petrified Forest NP 224 1.16 0 1 0.20 13 0.46 39 San Pedro Parks WA 160 2.24 0.02 1 0.28 11 0.72 35
Weminuche WA 137 1.19 0 0 0.19 18 0.55 51 West Elk WA 245 1.98 0.01 1 0.36 17 0.98 49
Wheeler Peak WA 265 1.18 0 0 0.19 18 0.50 50
Total Delta dv or Average % Change in

Delta dv 26.09 0.15 1 3.58 15 9.67 42Page 80 of 92 Table 38: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in De lta dv Impact Compared to Baseline Impacts from 2001 – 200 3 using Am3 Ammonia Background Scenario Class I Area Distance to FCPP Baseline

Impact Improvement From

PM Control Improvement From

LNB/LNB+OFA Improvement From SCR kilometers Delta dv Delta dv % Delta dv % Delta dv % Arches National Park 245 4.01 0.01 0 0.78 17 2.35 53
Bandelier Wilderness Area 216 2.86 0.03 0 0.64 20 1.61 55
Black Canyon of the Gunnison WA 217 2.29 0.01 0 0.61 22 1.37 59
Canyonlands NP 214 4.68 0.02 0 0.54 15 2.28 49 Capitol Reef NP 283 3.17 0.01 0 0.77 18 1.82 50 Grand Canyon NP 345 1.62 0.01 0 0.40 19 0.87 53
Great Sand Dunes NM 279 1.15 0 0 030 24 0.66 61
La Garita WA 202 1.70 0 0 0.44 24 1.03 61 Maroon Bells Snowmass WA 294 1.02 0 0 0.28 25 0.61 62

Mesa Verde NP 62 6.41 0.02 1 1.00 14 2.79 46
Pecos WA 258 2.07 0 0 0.46 22 1.06 56
Petrified Forest NP 224 1.40 0.01 0 0.29 20 0.65 55 San Pedro Parks WA 160 3.67 0.02 1 0.55 18 1.86 51
Weminuche WA 137 1.85 0 0 0.48 24 1.17 61 West Elk WA 245 2.75 0 0 0.64 22 1.69 59
Wheeler Peak WA 265 1.49 0 0 0.35 23 0.80 58
Total Delta dv or Average % Change in

Delta dv 42.14 0.14 0 8.53 20 22.62 56Page 81 of 92 Table 39: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in De lta dv Impact Compared to Baseline Impacts from 2001 – 200 3 using Am5 Ammonia Background Scenario

Class I Area Distance to

FCPP Baseline

Impact Improvement From

PM Control Improvement From

LNB/LNB+OFA Improvement From SCR kilometers Delta dv Delta dv % Delta dv % Delta dv % Arches National Park 245 3.95 0.01 0 0.85 17 2.25 53
Bandelier Wilderness Area 216 2.76 0.01 0 0.58 19 1.51 53
Black Canyon of the Gunnison WA 217 1.92 0.01 0 0.40 19 1.02 53
Canyonlands NP 214 4.84 0.01 0 0.70 15 2.46 49 Capitol Reef NP 283 3.14 0.01 0 0.75 17 1.78 50 Grand Canyon NP 345 1.42 0 0 0.35 16 0.68 48
Great Sand Dunes NM 279 1.08 0 0 0.25 23 0.60 59
La Garita WA 202 1.59 0.01 0 0.37 23 0.93 59 Maroon Bells Snowmass WA 294 0.98 0 0 0.26 23 0.58 59

Mesa Verde NP 62 6.41 0.02 1 1.00 14 2.79 46
Pecos WA 258 1.90 0.02 0 0.40 19 0.93 52
Petrified Forest NP 224 1.39 0 0 0.29 19 0.65 53 San Pedro Parks WA 160 3.51 0.02 1 0.58 17 1.74 49
Weminuche WA 137 1.69 0.01 0 0.39 21 1.03 58 West Elk WA 245 2.37 0.01 0 0.45 19 1.37 55
Wheeler Peak WA 265 1.37 0 0 0.28 21 0.70 55
Total Delta dv or Average % Change in

Delta dv 40.32 0.14 0 7.90 19 21.02 53

The modeled visibility improvement resulting from a dditional PM control is relatively small. However, the model does not capture a visibility impairing plume that is almost always present after the steam plume from Units 1, 2, and 3 evaporates.

The three small units (Units 1 – 3) at FCPP have co ntributed to significant visibility impairment in the area around the facili ty. Region IX staff and community members have seen a visible secondary plu me that appears to be formed in the steam plume that is almost always pre sent from these stacks. We have observed this plume as far as Aztec and Bloomf ield en route from Farmington from Albuquerque, New Mexico. This yell owish visible plume often extends for approximately twenty miles from the fac ility. It is particularly evident in mornings when an inversion prevents the dispersi on of the emissions from the plant. This secondary plume has not been observed from the stacks for Units 4 and 5, which are equipped with baghouses to control PM. EPA believes the secondary plume from Units 1 – 3, which are control led by venturi scrubbers, may be caused by the venturi scrubber’s poor contro l of ultrafine submicron PM. This ultrafine PM may be causing the conversion of some of the NO emissions to NO 2, which is readily dissolved in the steam plume drop lets. These NO 2 absorbedPage 82 of 92 droplets do not evaporate as readily as the water d roplets and persist in droplet form to scatter and absorb light, thus resulting in visibility impairment. Although CALPUFF is the most appropriate modeling tool for a ssessing visibility impacts, CALPUFF does not include algorithms for secondary p lume formation. Accordingly, the impacts of PM from Units 1 – 3 on the visible secondary plume are not captured in the visibility modeling results

. As part of our request for comments, EPA is specifi cally seeking information on this “secondary visible plume”, its frequency and persistence, and whether or not it impacts or can be observed from a ny Class 1 area. EPA is also seeking information as to whether this plume has be en observed from Units 4 and 5. EPA has not observed the secondary plume from U nits 4 and 5 from our frequent visits, but would like to know if it does occur at times.



### 8. Overall Proposed BART Determination

The final step in the BART analysis is to synthesiz e these factors and reach an overall proposed determination of BART.

A. FCPP Approach to This Factor

In the summary of their BART analysis, which inclu ded technology and cost analyses by B&V and visibility modeling analyses by AECOM, APS recommended that BART limits for NO x be 0.48 lb/MMBtu for Units 1 and 2, 0.39 lb/MMBtu for Unit 3, and 0.40 lb/MMBtu for Units 4 and 5. These limits a re based on the installation of LNB on Units 1 and 2 and LNB + OFA on Units 3 – 5 (Opti on 1). APS explained that Option 1 was most cost effective because of the lowest annua lized cost ($857,000 – $3,008,000), lower cost per ton reduction ($334 – $792), lowest cost per dv improvement in Class I areas, and least risk to unit operations. APS deter mined that SCR (Option 3) was not cost effective because of low average visibility improve ment, high costs, and increased risk to the local community due to the transportation and s torage of ammonia to the facility.

For PM, APS claimed that BART was already met for Units 4 and 5, which are equipped with fabric filters. APS recommended a PM emission limit for Units 4 and 5 of 0.03 lb/MMBtu, which is 40% lower than their curren t emission limit of 0.05 lb/MMBtu. For Units 1 – 3, which are currently equipped with venturi scrubbers at a limit of 0.05 lb/MMBtu, APS concluded that these units also meet BART at their current levels of control, because the reduction in PM would result i n no improvement in visibility at a high cost.

The BART Guideline provides presumptive NO x limits for coal-fired EGUs, greater than 200 MW located at power plants with a capacity that exceeds 750 MW, and operated without post-combustion controls. At FCPP, Units 1 and 2 are smaller than 200 MW; therefore the presumptive BART limits for NO x only apply to Units 3 – 5. Different presumptive limits apply depending on boi ler type and coal type (bituminous,Page 83 of 92

sub-bituminous, or lignite). APS claims that LNB+ OFA retrofit of Units 3 – 5 can achieve the NO x emission rates lower than the presumptive limit fo r bituminous coal fired in dry wall-fired boilers – 0.39 lb/MMBtu (Un it 3) and cell burner boilers – 0.40 lb/MMBtu (Units 4 and 5); therefore, APS contends L NB + OFA on Units 3 – 5 represents the Best Available Retrofit Technology.

The classification of coal used by FCPP has histor ically been sub-bituminous 99

, however, FCPP asserts that their coal has more char acteristics of bituminous coal than sub-bituminous coal, and should be classified as bi tuminous. Based on this categorization, FCPP cites the presumptive limit fo r NO x for bituminous coal of 0.39 lb/MMBtu from a dry-bottom wall fired boiler as the ir applicable presumptive BART limit for Unit 3. The presumptive limit for NO x for sub-bituminous coal is 0.23 lb/MMBtu. Generally, the high volatile content of sub-bituminous coal is known to ease burning and improve efficiency of combustion contro ls to reduce NO x , thus, the presumptive limit for sub-bituminous coal is lower than for bituminous coal. The analysis provided by APS suggested the coal they ob tain from the Navajo Mine should be considered high volatile bituminous, which at times can fall into the sub-bituminous category. Because higher volatility should result in lower emissions resulting from combustion controls, EPA expects that the retrofit of Unit 3 with LNB + OFA should achieve NO x rates closer to the sub-bituminous presumptive lim it of 0.23 lb/MMBtu than the bituminous limit in order for the retrofit on t hose units to be considered effectively meeting presumptive.

B. Affected State, Tribe, and FLM Consultation

In their comment letter on the ANPRM, CDPHE support ed state-of-the-art NO x emissions controls to reduce visibility impairment and ozone levels in northern New Mexico and in Class I areas such as Mesa Verde.

As an extension of the cost of compliance factor of the five factor analysis, APS and the Navajo Nation stressed the importance of FC PP on the Navajo economy. Specifically, FCPP employs 586 people, 72% of whom are Navajo Nation members. Additionally, FCPP annually burns approximately 10 million tons of coal from the BHP Navajo Mine. The Mine is a major employer in the N avajo Nation, providing jobs to over 300 Navajo tribal members, and is a major sour ce of revenue to the Navajo Nation, paying approximately $45.9 million in royalties and taxes.

The Navajo Nation commented that the intent of the BART requirement of the RHR was to provide a measured response to emissions from aging power plants, and that requiring expensive controls would be inconsistent with the law and regulations governing the BART process, particularly in light o f the high incremental cost of SCR and the impacts to economic interests of the Navajo Nation. The Nation recommended a phased approach to reducing emissions at FCPP to al low time for resolution of lease and right of way issues and to allow interested parties to review measurements rather rely on

99 See Determination of Four Corners Coal Ranking, Ma rch 11, 2008 by Alan Papp.Page 84 of 92

modeling results before determining the most string ent control option is appropriate. The Nation concluded that combustion controls represent BART at this time.

The National Park Service concluded in their commen t letter on our ANPRM that SCR to control NO x emissions at FCPP is technically feasible, cost ef fective, and will substantially improve visibility in the impacted Cl ass I areas. NPS compiled BART analyses across the U.S. and found that the average cost per dv proposed by either a state or a BART-subject facility is $10 – 17 million / dv . The Park Service applied the cumulative approach to assessing visibility impacts and determined that SCR at FCPP resulted in a cost per dv of $1.9 – 2.7 million / d v.

C. EPA Conclusions regarding This Factor

1. BART Guidelines

In making a BART determination for the Regional Ha ze Rule, the BART Guidelines allow states to determine that an altern ative level of control, beyond presumptive limits, may be appropriate based on car eful consideration of the statutory factors. See 70 FR 39171. APS provided information to reclassi fy their coal as bituminous, which would allow Unit 3 to mee t the presumptive limit for NO x with LNB + OFA. Their coal, as previously classifi ed, would have been subject to the lower subbituminous presumptive limi t of 0.23 lb/MMBtu, which Unit 3 cannot meet. The presumptive limit for the Unit 4 and 5 cell burner boilers burning sub-bituminous coal is 0.45 lb/MMBtu, while for bituminous coal is 0.4 lb/MMBtu. Considering the current baseline emissio ns from Units 4 and 5 are 0.49 lb/MMBtu, both the bituminous and sub-bitumino us presumptive limits provide negligible reductions of NO x emissions from these units.

The presumptive limits are not binding requirement s for BART, rather they are included in the BART guidelines as limits that most EGUs can meet through the use of current combustion control techn ologies. However, the BART guidelines further state that the reviewing authori ty may determine that an alternative control level is appropriate based on t he careful consideration of the statutory factors. Because EPA is proposing to mak e this BART determination based upon our careful examination of the five fact ors rather than relying on the general presumptions set forth in the BART Guidelin es, we have determined it unnecessary for purposes of this regulation to dete rmine whether the coal used by FCPP is bituminous or subbituminous.

The RHR allows reviewing authorities to determine the weight prescribed to each BART factor independently and on a case-by- case basis. Although APS gave most weight to the capital and incremental cos ts in determining BART, EPA is assigning more weight to the cost effectiveness and the anticipated visibility improvements from controls, rather than overall cap ital costs.Page 85 of 92 2. Summary of Five Factor Analysis

The first factor of the statutory factor analysis identified SCR as the top option for reducing NO x emissions at FCPP. Our approach for the five-fact or analysis was similar to a top-down analysis for the Best Available Control Technology (BACT) requirement of the PSD program. Therefore, we started with the most stringent technology and evaluated th e remaining factors to determine if the highest level of control should be rejected. EPA is proposing to determine that modern LNB or LNB+OFA are not techni cally feasible to significant emission reductions which would constit ute BART for this very large NO x source and may result in operational difficulties, therefore, EPA evaluated SCR without additional combustion controls.

The second factor evaluates the cost of controls. EPA finds that even using the cost analysis submitted by B&V, which are higher than other estimates, the costs per ton for SCR ($4,300 - $5,400/ton) are within a range that has been determined reasonable for BART. EPA used B&V’s cos t estimates and made several revisions to assumptions based on guideline s in the EPA Control Cost Manual to generate cost projections that are more reasona ble and consistent with the BART guidelines. EPA estimated cost effectiven ess of less than $3,000 per ton to install SCR on each of five units.

The third factor involves consideration of the ene rgy and non-air quality impacts of controls. Because of the importance of FCPP on the economy of the Navajo Nation, EPA also considered in our proposed determination the potential impacts of SCR on the Navajo economy. EPA understa nds the overall concern of the Navajo Nation is that requiring SCR as BART for FCPP will cause FCPP to shut down and result in the loss of Navajo jobs at FCPP and the BHP Mine, which supplies coal to FCPP, as well as the loss of royal ties and taxes paid by these two entities. Based on an economic analysis of the incr ease in electricity generation costs of SCR compared to the estimated cost to purc hase electricity on the wholesale market, FCPP is expected to remain compet itive relative to the wholesale market, suggesting that the cost increase for SCR alone should not force FCPP to shut down. This analysis estimates t hat the average cost of electricity generation over the 20 year amortizatio n period as a result of SCR implementation will increase by 22%, or $0.00740/kW h.

Retail electricity consumers, however, pay more th an just the generation costs of power. Retail rates include the cost to t ransmit and distribute electricity as well as generate electricity. Additionally, for APS customers, for example, the generation cost increase on FCPP due to SCR would flow into a broader retail rate impact calculation based on the entire portfol io of APS generation assets and purchases power contracts, which include coal (of w hich FCPP is only a portion of APS’s total coal portfolio), natural gas, nuclea r, and some renewables. For these reasons, EPA expects the increase to rate pay ers resulting from SCR on FCPP to be significantly lower than 22%.Page 86 of 92 As described in comments on the ANPRM, numerous ot her factors exist that will affect an owner’s decision not to invest in SCR, including upcoming regulations on greenhouse gas and mercury emissions , and coal combustion residues. Because of the uncertainty associated wi th these upcoming regulations and the complexity in determining the appropriate l evel of risk for each owner, EPA has determined that our proposed BART determina tion cannot rely on conjectures on the future decisions of FCPP owners. Without firm intentions and commitments to change operations, EPA is only relyi ng on the results of the economic model for SCR in our analysis, which sugge sts that SCR will not cause the cost of electricity generation to exceed the wh olesale market cost of electricity.

Factor four explores the existing controls at the source. For NO x , the existing controls at FCPP include LNBs installed on Units 2 – 5 in the 1980- 1990’s and for PM control, venturi scrubbers on Uni ts 1 – 3 and baghouses on Units 4 and 5. Average NO x emission rates from FCPP range from 0.49 lb/MMBtu (Units 4 and 5) to 0.78 lb/MMBtu (Unit 1). The physical limitations of each boiler and the past operational difficultie s resulting from LNB retrofit of Unit 2, suggest that LNB and LNB+OFA retrofit will not reduce NO x emissions significantly and may cause operational challenges. The venturi scrubbers are Units 1 – 3 are very old control technologies that are no longer installed on any coal-fired power plants and do not satisfy BART for PM.

The fifth factor considers the remaining useful li fe of the facility. Although commenters have cited the age of FCPP and impending lease and rightof-way negotiations with the Navajo Nation as a rat ionale to consider a shorter useful life of the facility, EPA has determined tha t the default 20-year amortization period is most appropriate to use as t he remaining useful life of the facility. Without commitments for an early shut do wn, EPA cannot consider a shorter amortization period in our analysis.

The final factor examines the visibility improveme nt resulting from controls. The anticipated visibility benefits were modeled using CALPUFF with a 1 ppb ammonia background. Background ammonia con centrations assumed in the model are an important component of the visibil ity impacts model. Based on modeling results from four different ammonia backgr ound scenarios, the assumed ammonia concentration affects the absolute modeled visibility benefits, but it does not change the ranking of controls, i.e., the most stringent control technology, SCR, results in the highest modeled visibility impr ovement. All ammonia background scenarios result in perceptible improvem ents in visibility at the most impacted Class I areas.

3. EPA’s Proposed BART DeterminationPage 87 of 92 In weighing the five factors, EPA is proposing to require an 80% reduction in NO x emissions on all 5 units at FCPP as BART (See Tabl e 40). SCR using an ultra low SO 2 to SO 3 conversion catalyst can readily achieve cost effective emissions reductions that provide a signi ficant improvement in visibility. EPA determined that presumptive BART for NO x is not appropriate for FCPP considering this is one of the largest sources of N O x in the country. The modeled visibility improvement from LNB/LNB+OFA only result s in perceptible visibility improvement in only half of 16 Class I areas impact ed by the FCPP under the default 1 ppb ammonia background scenario.

Table 40: Summary of BART Determination for FCPP Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

NO x (lb/MMBtu) 30-day rolling average 0.16 0.13 0.12 0.10 0.10

Stack PM (lb/MMBtu) 6-hour average 0.012

10% opacity 0.012

10% opacity 0.012

10% opacity 0.015

10% opacity 0.015

10% opacity

EPA is proposing to provide FCPP with flexibility to choose the control technology to achieve 0.11 lb NO x per MMBtu on a plant-wide heat inputweighted average, which is an 80% reduction in base line NO x emissions from Units 1 – 5. The cost estimates we present in our proposal, which we have determined to be cost effective, are based on SCR o n all five units, however, APS may choose to use alternative technologies to achie ve 80% NO x reductions, provided emissions of ammonia and sulfuric acid are not greater than the emission rates resulting from SCR using a low SO 2 to SO 3 conversion catalyst. EPRI estimates that baghouses provide 90% control of sul furic acid emissions and EPA agrees that the existing baghouses on Units 4 and 5 may provide significant control of sulfuric acid. FCPP uses coal with very high ash content, approaching 25%. This ash may be sufficient to prevent a signi ficant increase in sulfuric acid emissions after installation of SCR on Units 4 and 5.

In 2009, NO x emissions from FCPP were larger than from any othe r facility in the United States: annual facility-wide NO x emissions from FCPP exceed 40,000 tons per year (based on data from the EPA Clean Air Markets Division 100 for 2003 – 2009). Although EPA received several co mments that stringent controls at FCPP are not warranted becaus e FCPP is not among the largest emitters of NO x on a heat input basis (in terms of lb/MMBtu), the visibility impacts to nearby Class I areas are dependent on th e total NO x emissions into the atmosphere. Therefore, EPA believes that total annu al emissions are more relevant than NO x emissions on a heat input basis to describe the im pacts of emissions from FCPP. Additionally, fifteen Class I areas are within 300 km of FCPP, and Grand Canyon National Park is just beyond 300 km from FCPP. These two unique considerations were not addressed by FCP P when weighing the cost of controls against the anticipated NO x reductions from their recommended

100 http://camddataandmaps.epa.gov/gdm/Page 88 of 92 control options. EPA has determined that LNB and LN B+OFA are not technically feasible to achieve significant reductions in NO x and may cause operability issues for the boilers. However, even if those emission r ates were achievable, the NO x emission rates proposed by FCPP as BART are too hig h considering the five BART factors in the context of FCPP’s status as amo ng the largest NO x emitters in the United States, and the large number of Class I Areas impacted by this facility.

The visible secondary plume from the three small u nits (Units 1 – 3) at FCPP has contributed to significant visibility impa irment in the area around the facility. Region IX staff and community members ha ve seen a visible secondary plume that appears to be formed in the steam plume that is almost always present from these stacks. This yellowish visible plume of ten extends for approximately twenty miles from the facility. It is particularly evident in mornings when an inversion prevents the dispersion of the emissions from the plant. This secondary plume has not been observed from the stacks for Uni ts 4 and 5, which are equipped with baghouses to control PM. EPA believes the secondary plume from Units 1 – 3, which are controlled by venturi scrubb ers, may be caused by the venturi scrubber’s poor control of ultrafine submic ron PM. It is suspected that this ultrafine PM may be causing the conversion of some of the NO emissions to NO 2, which is readily dissolved in the steam plume drop lets. These NO 2 absorbed droplets do not evaporate as readily as the water d roplets and persist in droplet form to scatter and absorb light, thus resulting in visibility impairment. Although CALPUFF is the most appropriate modeling tool for a ssessing visibility impacts, CALPUFF does not include algorithms for secondary p lume formation. Accordingly, the impacts of PM from Units 1 – 3 on the visible secondary plume are not captured in the visibility modeling results . The plume would be eliminated by the proposed BART controls for PM.

For PM, EPA’s proposed BART determination for Unit s 1 – 3 is to require FCPP to meet a PM emission limit of 0.012 lb/MMBtu and 10% opacity. Wet membrane ESPs were the least costly PM control opti on presented by APS. This device is very reasonably priced in comparison to t he typical modern day BACTcontrolled coal-fired EGUs, however because wet ESP s would be placed downstream of the existing venturi scrubbers, the i ncremental cost effectiveness of the wet membrane ESPs are high. The retrofit of Units 1 – 3 with new baghouses would be a reasonable option if APS also wants to achieve significant Hg reduction from these units. Because of the cost associated with new wet ESPs and baghouses, EPA is also requesting comment on wh ether APS can satisfy BART by operating the existing venturi scrubbers to meet an emissions limit of 0.03 lb/MMBtu with a 20% opacity limit to demonstra te continuous compliance.

Units 4 and 5, which are equipped with reverse gas fabric filters, are currently limited in the 2007 FIP and their Part 71 Operating Permit 101 to PM

101 Issued by the Navajo Nation Environmental Protecti on Agency, August 1, 2008. See: http://www.navajonationepa.org/airqty/Pdf_files/FCP Ppermit8-1-2008.pdfPage 89 of 92 emissions not to exceed 0.050 lb/MMBtu. Because PM emissions during source tests on Units 4 and 5 have achieved as low as 0.01 2 lb/MMBtu, EPA is proposing to find that it is appropriate at this ti me to reduce the PM emission limits on Units 4 and 5. EPA is proposing a BART l imit for PM of 0.015 lb/MMBtu and 10% opacity, with compliance demonstra ted by annual PM source tests using EPA Method 5.

Although PM BART reductions are not modeled to hav e a significant impact on visibility improvement, consideration of the other four factors, in particular, the fact that the existing venturi scru bber controls on Units 1 – 3 are very old control technologies, EPA is proposing to determine that new PM controls on these three units are required to satis fy BART. PM emission limits for the boilers will bring the allowable emissions to t he levels achieved by some of the best technology that is available for coal-fire d power plants. The reduced PM emission limits for Units 4 and 5 reflect the PM em issions that can easily be achieved and maintained at coal-fired electric gene rating units (EGUs) controlled by baghouses.Page 90 of 92 Appendix A:

Mobile Source Risk Estimates for Four Corners Power Plant

See www.regulations.gov , docket ID number EPA-R09-OAR-2010-0683Page 91 of 92 Appendix B:

Economic Analysis of SCR on FCPP

See www.regulations.gov , docket ID number EPA-R09-OAR-2010-0683Page 92 of 92 Appendix C:

Impact of Ammonia in Fly Ash on its Beneficial Use

See www.regulations.gov , docket ID number EPA-R09-OAR-2010-0683