### Proposed Rule: Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology for Four Corners Power 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 Retrofit 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 IX (EPA) finds that the BART requirement for NO

x 

### and PM of the RHR is necessary or appropriate to apply at this time to FCPP. In making our BART Determination for these facilities, we examined the following six factors as prescribed by the RHR:

� Factor 1 assesses the available technology to control emissions and determines the technical feasibility of each technology;

� Factor 2 examines the cost of compliance for the technically feasible control technologies;

� Factor 3 addresses the energy and non-air quality impacts of the control technologies;

� Factor 4 considers any existing air pollution control technologies at the source;

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

� Factor 6 assesses the degree of visibility improvement 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 and the remaining factors are frequently referred to as the “Five Factor Analysis” for the RHR BART determination.

On behalf of Arizona Public Service (APS), co-owner 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 modeling results (dated January 2008) to EPA. Based on these analyses, APS recommended the installation 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 catalytic reduction (SCR), which would achieve the greatest NO

x 

### reductions, was not cost effective because their analyses showed high costs and low average visibility improvement. For PM, FCPP concluded 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 Notice of Proposed Rulemaking (ANPRM) in the Federal Register (74 FR 44313) and requested comment on the anticipated

Page 1 of 92

### visibility improvements at surrounding Class I areas 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 this 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, and the Salt River Pima Maricopa Indian Community. Additionally, EPA received comments from 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 associated 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 proposing 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 FCPP and revised our analyses to address comments as we determined appropriate. We have addressed 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-factor analysis was similar to a topdown analysis for the Best Available Control Technology (BACT) requirement of the PSD program. Therefore, we started with the most stringent technology and evaluated the remaining factors to determine if the highest level of control should be rejected. EPA determined that even if modern LNB or LNB + OFA achieved the emission rate claimed by APS, these controls would

not reduce NO

x 

### emissions sufficiently that is adequate for BART for a facility that has consistently been one of the largest NO

x 

### emitters in the U.S. and is located on the Colorado Plateau affecting visibility in sixteen Class I areas. 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, EPA is concerned that combustion controls may result in operational difficulties. EPA therefore 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 ton for SCR ($4,300 - $5,400/ton) are within a range that has been determined reasonable for BART. EPA used B&V’s cost estimates and made several revisions to assumptions based on guidelines 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.regulations.gov.

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### 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 energy 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 economic impacts of SCR. EPA understands 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 royalties and taxes paid by these two entities. Based on an economic analysis of the increase in electricity generation costs of SCR compared to the estimated cost to purchase electricity on the wholesale market, FCPP is expected to remain competitive relative to the wholesale market, suggesting 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 than just the generation costs of power. Retail rates include the cost to transmit 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 portfolio of APS generation assets and power purchase contracts, which 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 resulting from SCR on FCPP to be significantly

lower than 22%.

As described in comments on the ANPRM, numerous other 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 associated 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 on the future decisions of FCPP owners. Without firm intentions and commitments to shut down in the near future resulting from one or more regulatory factors, EPA is only considering the results of the economic model for SCR in our analysis, which suggests that SCR will not cause 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 1980-1990’s and for PM control, venturi scrubbers on Units 1 – 3 and baghouses on Units 4 and 5. Average NO

x 

### emission rates from FCPP range from 0.5 lb/MMBtu (Units 4 and 5) to 0.78 lb/MMBtu (Unit 1). The physical limitations of the each boiler and the past operational difficulties 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 on 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 secondary PM plume from the venturi scrubber-controlled units often results in

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

The fifth factor considers the remaining useful life 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 appropriate to use as the remaining useful life of the facility. Without commitments for an early shut down, EPA cannot consider a shorter amortization period in our analysis.

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

EPA’s BART determination for FCPP is presented in Table ES-1: Summary of BART

Determination for FCPP.

Table ES-1: Summary of EPA BART Determination for FCPP

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-wide heat input-weighted average emission limit of 0.11 lb/MMBtu. This BART determination 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/MMBtu and to set the PM limit for Units 4 and 5 at 0.015 lb/MMBtu. Additionally, we are proposing to include a 10% opacity limit for all 5 units. The new PM limit on Units 1 – 3 would require the installation of any of the four technically feasible add-on PM controls discussed by APS. As an alternative for Units 1 – 3, 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. 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 determinations for NO

x 

### and PM represent the most appropriate BART determination for FCPP, the largest NO

x 

### emission source in the

United States.

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### 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 Power 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 12 Consultation with Affected States, Tribes, and FLMs

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 Reasonably 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 67

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### 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 Power Plant

B. Economic Analysis of SCR on FCPP

C. Impact of Ammonia in Fly Ash on its Beneficial Use

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### List of Tables and Figures

Number Title Page

Table 1 FCPP Operational Characteristics 10

for APS

Presented by B&V for APS

Revisions

(TAC) from Other Western Facilities

Control Cost Manual Reported in their Comments on ANPRM

Plants

Controls at FCPP Presented in ANPRM

under Straight Line Depreciation (2011 – 2035)

under Accelerated Depreciation (2011 – 2035)

Sixteen Class I Areas as Modeled by AECOM

ANPRM 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 15

Table 4 Analysis of Available PM Control Options for FCPP Units 1 – 3 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 Estimated 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 26

Table 11 Comparison of Total Capital Investment (TCI) and Total Annual Costs 27

Table 12 NPS’s Estimated Costs of Combustion Controls + SCR based on EPA 29

Table 13 Summary of EPA Revisions to B&V Cost Inputs 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 Units 1 – 5 (2008 dollars) 32

Table 16 Cost Effectiveness of SCR Retrofits estimated for Several Western Power 32

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

x 

### and PM 34

Table 18 Summary of Cost Comparisons for NO

x 

### Control versus Market Trends 37

Table 19 Summary of Cost Comparisons for NO

x 

### Control versus Market Trends 38

Table 20 Flue Gas Flow Sequence and Air Pollution Control 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 55

Table 29 Assumptions used in Sulfuric Acid (H 2 

### SO 4 

### ) Emissions Calculations 59

Table 30 Ammonia Background Concentrations in ppb Determined by EPA used in 61

Table 31 NPS Modeling Results – Average 8 th 

### High Baseline and Delta dv 67

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### Improvement from 2001 – 2003

Table 32 Class I Area Grouping for Ammonia Background used in this proposal 69

Table 33 Ammonia Background Concentrations in ppb modeled by EPA used in 70 this proposal

Table 34 EPA Modeling Inputs (lb/hr) 74

Table 35 EPA Modeling Results – 8 th 

### High Delta dv Baseline from 2001 – 2003 for 76 the Different Ammonia Background Scenarios

Table 36 EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent 78 Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am1 Ammonia Background Scenario

Table 37 EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent 79 Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am2 Ammonia Background Scenario

Table 38 EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent 80 Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am3 Ammonia Background Scenario

Table 39 EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent 81 Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am5 Ammonia Background Scenario

Table 40 Summary of BART Determination for FCPP 87

Figure 1 Map of Class I Areas near FCPP 44

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### 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 Document

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## 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, near 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 Deterioration (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. Units 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

Year Operation Unit 1 Unit 2 Unit 3 Unit 4

1963 1963 1964 1969

170 170 220 750

1863 1863 2400 7806

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

0.78 0.64 0.59 0.51

0.025 0.029 0.029 0.014 1970 Began Unit 5

Capacity (MW) 750

Heat input (gross) 7806 (MMBtu/hr)

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

boiler

NO

x Baseline

emission rate 2 0.48 (lb/MMBtu)

PM Baseline

emission rate 3 0.010 (lb/MMBtu)



### 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”.

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### source of NO

x 

### on the Navajo Nation and in the Western United States. 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 1990 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 §49.11(a)) as part of our Federal Implementation Plan (FIP) proposal that the BART requirement of the RHR is necessary or appropriate to apply at this time to FCPP. The RHR provides the following six factors that should be taken into consideration when undertaking a BART determination:

� Factor 1 assesses the available technology to control emissions and determines the technical feasibility of each technology;

� Factor 2 examines the cost of compliance for the technically feasible control technologies;

� Factor 3 addresses the energy and non-air quality impacts of the control technologies;

� Factor 4 considers any existing air pollution control technologies at the source;

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

� Factor 6 assesses the degree of visibility improvement 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 and the remaining factors are frequently referred to as the “Five Factor Analysis” for the RHR BART determination.

C. Pollutants Addressed in our BART Determination

The RHR requires an assessment of all visibility-impairing pollutants at a source that are emitted in excess of the Prevention of Significant Deterioration (PSD) significance levels (40 CFR §52.21). The BART Guidelines (40 CFR Part 51 Appendix

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### 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 it 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 Register the final rule for a source-specific Federal Implementation Plan (FIP) for FCPP (72 FR 25698). The purpose of the 2007 FIP was to make federally enforceable significant emissions

reductions of SO 2 

### , from 72% to 88% control, and to federalize emissions 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 (Units 1 and 2) and

0.65 lb/MMBtu (Units 3 – 5). The FIP included PM emission 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 conveyor, or truck unloading or loading operation were limited to 20% opacity. For the increase 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 necessary or appropriate to protect air quality. Because SO 2 

### has been reduced by 88%, and the reductions were made 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 Approach to Consultation with Affected States, Tribes, and FLMs

On August 28, 2009, EPA published in the Federal Register an Advanced Notice of Proposed Rulemaking (ANPRM) that put forth our analyses regarding the anticipated visibility improvements at surrounding Class I areas 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 for 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 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 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 generally focused either on both FCPP and NGS, or solely on NGS. Any comments received pertaining to NGS will not be

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

We received comments from six tribes located in Arizona 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, and 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 relationship 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 Community 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 River Pima Maricopa Indian Community are discussed in Section 4.D of this Technical Support Document.

In addition to tribes, we received numerous substantive comments from State environmental agencies and the Federal Land Managers 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 and utility groups, including Electric Power Research Institute (EPRI) and Utility Air Regulatory 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 impacts 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 BART 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 benefits of stringent controls on reducing ozone and nitrogen deposition. The remainder of the 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 writing 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 facilities, 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 Conservation Association, Natural Resources Defense Council, San Juan Citizens Alliance, Sierra Club, and Western Resource Advocates.

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### stringent controls were concerned about costs to consumers 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 Land Managers of the affected Class I

areas.

In our final determination, EPA will respond to comments submitted on this proposal, but will not respond to comments submitted on the ANPRM. Those who submitted comments on the ANPRM will need to resubmit comments on the proposal in order for EPA to consider those comments in finalizing this FIP.



## 2. Technology Available

A. FCPP Approach to This Factor

APS provided results of a BART engineering and cost analysis for the FCPP conducted by Black and Veatch (B&V). Sixteen options 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 control 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 control 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 technologies they excluded as technically infeasible. EPA revised the format of the information 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 information 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 determine control efficiencies or additional information for several technologies listed, e.g., biotechnological denitrification. Although one PM control technology, GE-MAX-9 is claimed to have a higher control efficiency than the three technologies not determined by B&V to be technically infeasible, GE-MAX-9 has only been demonstrated in a pilot demonstration.

Page 14 of 92

### Table 3: Analysis of Available NO

x 

### Control Options for FCPP Presented by B&V for APS

NO

x Control Description B&V Technical Feasibility Possible % Option Recommendation Control

Selective Catalytic Ammonia or urea injection in the presence of a catalyst to Yes 90 – 95% 6

Reduction (SCR) reduce NO

x to N 2

. LoTO

x Oxidation of NO

x with ozone to form nitrogen pentoxide No, no large operation units 70 – 95% 7

(N 2 O 5 ), which is scrubbed by the wet flue gas with this technology. desulfurization (FGD) unit.

THERMALONO

x Elemental phosphorus is injected into the flue gas to react No, not currently in similar type Up to 90% 8

Process with oxygen to form ozone. Similar to LoTO

x , the ozone or size facilities.

oxidizes NO

x to N 2 O 5 which is removed in the wet FGD.
SNCR/SCR Hybrid SNCR system with high ammonia slip followed by small No, technology has not been 50 – 75% 9
catalyst that provides further reductions of NO

x and demonstrated on large units ammonia slip. (Units 4-5), and no available room for ductwork expansion at economizer outlet (Units 1-3).
High Energy

Reagent OFA coupled with reagent injection. The reagent breaks

down to ammonia to reduce NO

x but functions in a Yes 50 - up to

65% 10
Technology different temperature window compared to SNCR.

(HERT)

Natural Gas Reburn Three combustion zones are used to reduce NO

x emissions. No, not currently in similar type 65% when A reburn zone, fired with natural gas burners, reduces NO

x to N 2 by stripping oxygen from NO

x to convert CO to CO 2

. or size facilities. combined

with LNB 11

Oxygen Enhanced Pure oxygen is used to stage combustion with higher local No, not currently in similar type Up to 60% 12

Combustion flame temperatures and higher local oxygen inlet or size facilities.

concentrations to reduce NO

x and unburned carbon.

Induced Flue Gas Recirculation of flue gas into the combustion zone to No, technology not applicable to ~ 60% 13

Recirculation reduce peak flame temperatures to reduce thermal NO

x coal-fired plants, especially production. pulverized coal boilers.
Rotating Opposed ROFA modifies OFA by adding rotation to improve Yes – Units 1-3, No – Units 4-5 40 – 60% Firing Air (ROFA) mixing with the flue gas. The ROTAMIX system adds urea because ROTAMIX has not

and ROTAMIX to the flue gas by injection with boosted air. In the been demonstrated on large appropriate temperature range, urea reduces NO

x to N 2

. units.

Selective Ammonia or urea injection without use of a catalyst to Yes 30 – 50% 14
Noncatalytic reduce NO

x to N 2

. Reduction (SNCR)

Low NO

x Burners LNB plus staged combustion such that excess air in the Yes 35 – 63% 15

and Overfire Air burner zone is reduced and additional air is added above Systems (OFA) the burner zone to complete combustion.

Low NO

x Burners Burner modification to stage combustion by controlling 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, March 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, March 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, March 2005.

9 Pfaff, Dale and Abrams, Rich, 2006. Hybrid SNCR/In-Duct SCR System. Presentation to the Environmental 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/F03-031

15 Srivastava et al., 2005. Journal of the Air and Waste Management Association.

Page 15 of 92(LNB) and fuel flow to create fuel-rich/O 2 -poor conditions in the burner and high temperature zones. Reduces the formation

of fuel NO

x . Combustion Computer hardware and software technology using real- Yes 15% Optimization time operational data to reduce emissions while improving System (COS) plant performance by adapting to changes in plant operation.

NO

x Star and NO

x Star is a trademark name for the injection of ammonia No, not currently marketed, but Not known 17

NO

x Star Plus and a hydrocarbon (i.e., natural gas) in the flue gas. The would be expected to achieve

ammonia reduces NOx to N 2 , and the hydrocarbon reduces similar results as SNCR with ammonia slip. lower NH3 slip.

ECOTUBE Hybrid of Separated OFA (SOFA) and ammonia or urea No, no existing installations Not known injection, where ammonia or urea injected through exist on similar type or sized retractable lances into the gas flow to improve mixing and facilities, but would be expected

combustion characteristics. to achieve similar results as

An iron chelate is added to the wet FGD to react with NO

to form a nitrogen compound that dissolves in the FGD liquid. A catalyst is used to convert the dissolved nitrogen compound to N 2

. SNCR with lower NH3 slip.
No, not currently in similar type

or size facilities. Not known Biotechnological

Denitrification

(BioDeNO

x )



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

PM.

16 Srivastava et al., 2005. Journal of the Air and Waste Management Association.

17 For those labeled “Not known”, EPA was unable to find information on control efficiencies from this technology.

Page 16 of 92

### Table 4: Analysis of Available PM and Control Options for FCPP Units 1 – 3 Presented by B&V

for APS

PM Control Description Option

Dry Electrostatic ESPs use electrical fields to negatively charge PM for Precipitator (ESP) collection onto grounded plates by electrical attraction. The collection plates are periodically cleaned by mechanical rappers and PM are collected and removed by the ash handling system.

Wet ESP Operates on same theory as dry ESP, but collection plates

are flushed with water to remove the PM.

Pulse Jet Fabric PM is collected onto fabric filter bags. PM are cleaned

Filter (PJFF) from the bags by a pulse of air and removed by the ash handling system.
GE-MAX-9 Hybrid This technology involves an ESP using fabric filter bags instead of collection plates. PM are cleaned from the bags by a pulse of air and removed by the ash handling system.
Compact Hybrid COHPAC involves a fabric filter with a high air to cloth

Particulate Collector ratio, and thus a smaller footprint. (COHPAC)
Multiple Cyclone Multiple cyclones use several cyclones operated in parallel that remove PM from the gas stream by centrifugal force

and the inertia of PM.

PM Agglomeration Upstream of a dry ESP, a bipolar charger alternately

Upstream of Dry charges PM with a positive or negative charge. Oppositely

ESP charged PM will be attracted and agglomerate to form larger PM that are more effectively captured by the ESP.



### B. Discussion of Factor in ANPRM B&V Technical Feasibility

Recommendation

Yes

Yes

Yes

No, not demonstrated on large

size boiler units.

No, ineffective for use with

venturi scrubbers.

No, the addition of multiple cyclones to existing venturi scrubbers is not expected to provide additional PM control.

No, not demonstrated effective upstream of venturi scrubbers. Possible %

Control

99 – 99.9%

99 – 99.9%

99 – 99.9%

99.999% 18

99+% in a dry

gas stream

70 – 90%

Not known



### 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 four PM control options (three types of ESPs and one type of baghouse) that are all projected to achieve the same controlled emission rate. We did not provide detailed information in our ANPRM on all of the technologies discussed by B&V and their technological 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 capability of obtaining significant

NO

x 

### reductions from LNB retrofits at FCPP. In association 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 technology. When Unit 2 was retrofit in the 1990s, FCPP encountered 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 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/particulate_matter/en/max9/index.htm

Page 17 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 determination.

APS submitted two different reports concerning the potential for NO

x 

### reductions at FCPP. The first report written by Andover Technology Partners entitled: “Assessment

of Potential for Further NO

x 

### Reduction by Combustion-Based Control at the Four Corners Steam Electric Station”, dated April 5, 2004 (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 claimed 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 risk of adverse operational side effects outweighed the potentially modest improvement in emissions performance. Even for Units 4 and 5, where retrofit with LNB+OFA might result in some improvement in NO

x 

### performance (approaching 0.40 lb/MMBtu), the Andover Report did not recommend burner retrofits because potential operational problems 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 combination of LNB + OFA retrofit. APS cited examples of several boilers with LNB or LNB+OFA retrofits that achieve

emission rates of 0.4 lb/MMBtu or below.

EPA Clean Air Markets Division (CAMD) evaluated the 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 modern combustion modification

retrofits on those boilers. CAMD concluded that those 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 Report regarding operational risks associated with LNB/OFA retrofits, and the uncertain comparability of the boilers at FCPP with boilers that have achieved 0.4 lb/MMBtu following 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 largest NO

x 

### sources, located on the Colorado Plateau and affecting visibility at sixteen Class I areas.

C. Affected State, Tribe, and FLM Consultation

Page 18 of 92

### We did not receive comments from affected States or Tribes on additional NO

x 

### orPM control options to consider. NPS commented that APS should have evaluated tailend SCR configuration (SCR downstream of all pollution control equipment). The downstream air pollution control equipment, particularly 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 expected 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 affects of sulfuric acid control in the venturi scrubbers, air preheaters, wet FGDs, or baghouses would result in greater emissions of sulfuric acid from the stack. Sulfuric acid also impacts visibility because it contributes to ammonium sulfate formation. This would offset the visibility improvement from the

NO

x 

### reductions gained from applying SCR. EPA concludes that tail-end SCR would result in significantly higher sulfuric acid emissions which would reduce the visibility improvement resulting from SCR and could potentially increase visibility impairment. Therefore, EPA did not evaluate tail-end SCR for this proposal.

D. EPA Conclusions regarding This Factor

For the control of NO

x 

### emissions, EPA has determined that B&V has identified

the available NO

x 

### control technologies. See Table 3. In conducting our BART analysis, EPA used the analogous top-down approach of Best Available Control Technology (BACT) analyses for Prevention of Significant Deterioration (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 technologies. 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 stringent NO

x 

### control option and B&V did not eliminate as technically infeasible any options that are more stringent than SCR. Generally, LNB and LNB+OFA can be applied in addition to SCR, such that the combination of combustion controls and post-combustion controls can be expected to result in the most stringent level of control.

Based on our evaluation of the information provided 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 LNBs, 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 with SCR (without combustion controls). However, although EPA has determined that LNB and LNB+OFA

Page 19 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 most 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 further 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 technically feasible for FCPP: Dry and Wet Electrostatic Precipitators (ESP) and Fabric Filters (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 required 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 as 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 annual average emission rate, whereas the degree of visibility improvement should be calculated 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 Retrofit Technology (BART) Determinations; Final Rule”, 70 FR 39170, July 6, 2005). In this section, we will discuss the estimates of total and annual cost of control and the cost effectiveness 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 using the EPA Coal Utility Environmental Cost (CUECost) program 19 

### , information supplied by equipment vendors, estimates from previous projects, and projected costs 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 installation and operation of various pollutant control technologies, and relies upon user-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 construction services and materials 20 

### (See

19 http://www.epa.gov/ttn/catc/products.html

20 APS-FCPP did not include revised cost estimates for ROTAMIX, ROTAMIX + LNB, ROFA, and ROTAMIX + ROFA in their March 16, 2009 revised estimates.

Page 20 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 provided by B&V, but reformatted by EPA to be listed in top-down order, with several footnotes listing previous cost estimateswhere the increase in cost was particularly large. Although we are focusing on the topranked control (SCR without combustion controls) and comparing that with APS’s BART recommendation, we included cost and percent control information for the other control technologies, for informational purposes. The NO

x 

### emission rates and % NO

x 

### reductions are shown in Table 6 and the total estimated 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

SCR Total Capital Investment 22

Total Annual Cost ($/yr) 23

LNB + OFA + Total Capital Investment

HERT Total Annual Cost ($/yr)

ROTAMIX + Total Capital Investment

ROFA Total Annual Cost ($/yr)

SNCR + LNB + Total Capital Investment

OFA Total Annual Cost ($/yr)

ROFA Total Capital Investment
Total Annual Cost ($/yr)

ROTAMIX + LNB Total Capital Investment
Total Annual Cost ($/yr)

SNCR + LNB Total Capital Investment
Total Annual Cost ($/yr)

LNB + OFA Total Capital Investment
Total Annual Cost ($/yr)

LNB Total Capital Investment
Total Annual Cost ($/yr)

ROTAMIX Total Capital Investment
Total Annual Cost ($/yr)

SNCR Total Capital Investment
Total Annual Cost ($/yr)

COS Total Capital Investment
Total Annual Cost ($/yr) Unit 1

$110,664,000

$22,297,000

$10,762,000

$2,816,000

$13,672,000

$4,223,000

$15,070,000

$3,785,000

$9,657,000

$2,956,000

$11,105,000

$3,508,000

$13,796,000

$3,849,000

$5,752,000

$1,293,000

$4,109,000

$922,000

$7,282,000

$4,277,000

$10,866,000

$4,314,000

$1,429,000

$314,000 Unit 2

$119,010,000

$23,634,000

$10,762,000

$2,816,000

$13,532,000

$4,191,000

$15,360,000

$3,851,000

$9,657,000

$2,956,000

$11,105,000

$3,508,000

$14,104,000

$3,918,000

$5,752,000

$1,293,000

$4,109,000

$922,000

$7,282,000

$4,277,000

$10,742,000

$3,941,000

$1,429,000

$314,000 Unit 3 Units 4, 5 (each)

$113,084,000 $265,406,000

$23,173,000 $55,755,000

$10,076,000

$2,961,000

$13,689,000

$4,858,000

$15,626,000 $39,084,000

$4,210,000 $11,221,000

$10,705,000

$3,406,000

$11,215,000

$3,536,000

$15,409,000 $34,088,000

$4,520,000 $11,503,000

$4,701,000 $15,260,000

$1,055,000 $3,447,000

$3,999,000 $8,828,000

$897,000 $1,991,000

$7,436,000

$4,311,000

$12,137,000 $25,890,000

$4,536,000 $10,668,000

$1,429,000 $1,577,000

$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 EPA 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 EPA 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 21 of 92

### Table 6: NO

x 

### Emission Rates and Percent Reductions Estimated by B&V

NO

x Control (#) Emission Rates and % Reductions 24

Baseline Emission (lb/MMBtu)

SCR Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

ROTAMIX + Expected Emission rate (lb/MMBtu)

ROFA % NO

x reduction from baseline

LNB + OFA + Expected Emission rate (lb/MMBtu)

HERT % NO

x reduction from baseline

SNCR + LNB + Expected Emission rate (lb/MMBtu)

OFA % NO

x reduction from baseline

ROFA Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

ROTAMIX + LNB Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

SNCR + LNB Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

LNB + OFA Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

LNB Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

ROTAMIX Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

SNCR Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline

COS Expected Emission rate (lb/MMBtu)

% NO

x reduction from baseline Unit 1

0.78

0.08

89.7%

0.19

75.6%

0.20

74.3%

0.26

66.7%

0.28

64.1%

0.30

61.5%

0.32

59.0%

0.33

57.7%

0.43

44.9%

0.56

28.2%

0.56

28.2%

0.72

7.7% Unit 2

0.64

0.06

90.6%

0.19

70.3%

0.20

68.8%

0.26

59.4%

0.28

56.3%

0.30

53.1%

0.32

50% 25

0.33

48.4%

0.43

32.8%

0.45

29.7%

0.46

28.1%

0.6

6.3% Unit 3 Units 4, 5 (each)

0.59 0.49

0.06 0.06

89.8% 87.8%

0.19

67.8%

0.20

66.1%

0.26 0.26

55.9% 46.9%

0.28

52.5%

0.30

49.2%

0.32 0.32

45.8% 26 34.7%

0.33 0.35

44.1% 28.6%

0.43 0.45

27.1% 8.2%

0.45

23.7%

0.46 0.38

22% 22.4%

0.56 0.47

5.8% 4.1%

24 Percent reductions were calculated from the expected change in emission rate (lb/MMBtu) compared to baseline.

25 Table 6-3 of the 2007 B&V BART Analysis for FCPP submitted by APS in January 2008 presents cost and emission estimates twice for New LNBs, OFA, and SNCR. We assume the higher emission rate of the two actually corresponds to New LNBs and SNCR.

26 Table 6-4 of the 2007 B&V BART Analysis for FCPP submitted by APS in January 2008 presents cost and emission estimates twice for New LNBs, OFA, and SNCR. We assume the higher emission rate of the two actually corresponds to New LNBs and SNCR.

Page 22 of 92

### Table 7: NO

x 

### Reductions and Cost Effectiveness of Controls Estimated by B&V

NO

x Control Unit 1

TPY NO

x reduced

SCR 5,134 27

ROTAMIX + 4,318

ROFA

LNB + OFA 4,245

+ HERT

SNCR + 3,808

LNB + OFA

ROFA 3,662

ROTAMIX + 3,517

LNB

SNCR + 3,371 1,142 2,396 1,635 2,561 1,765

LNB

LNB + OFA 3,298 392 3,298 392 2,465 428

LNB 2,569

ROTAMIX 1,622

SNCR 28 1,622

COS 456 Cost ($/ton)

4,343

978

663

994

807

997

359

2,637

2,660

689 Unit 2

TPY NO

x reduced

4,310

3,368

3,293

2,844

2,695

2,545

2,569

1,425

1,349

302 Cost ($/ton)

5,484

1,244

855

1,354

1,097

1,378

359

3,001

2,921

1,040 Unit 3

TPY NO

x reduced

5,057

3,809

3,713

3,137

2,945

2,753

1,505

1,313

1,217

257 Cost ($/ton)

4,582

1,275

797

1,342

1,157

1,284

596

3,283

3,727

1,222 Unit 4, 5 (each)

TPY NO

x Cost

reduced ($/ton)

11,445 4,872

6,171 1,818

4,589 2,507

3,798 908

1,160 1,716

3,138 3,400

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 furnaces, which make the use of staged combustion for LNBs and OFA more challenging. Additionally, B&V state that SCR retrofits of Units 1 – 3 are costly and difficult because 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 Units 4 and 5 with SCR, B&V states that the arrangement and corresponding ductwork of the primary and secondary air heaters makes the retrofit costly and complicated.

B&V examined the emissions reductions and cost effectiveness for four PM control scenarios for Units 1 – 3 (See Table 8). Because Units 4 and 5 have existing reverse gas fabric filters for PM control, B&V determined 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 23 of 92

### Table 8: Cost Estimates and Emissions Reductions for PM Estimated by B&V

ESP Upstream PJFF Upstream of Metal ESP Membrane ESP

of add-on add-on controls Downstream of Downstream of

controls Venturi Scrubber Venturi Scrubber

Unit 1

Baseline =

0.025

lb/MMBtu

Unit 2

Baseline =

0.029

lb/MMBtu

Unit 3

Baseline =

0.029

lb/MMBtu Total Capital Investment ($)
Total Annual Cost ($/yr)

Estimated PM (lb/MMBtu)

% PM Reduction from Baseline

Additional TPY PM Reduced

Cost Effectiveness ($/ton)

Total Capital Investment ($)

Total Annual Cost ($/yr)

Estimated PM (lb/MMBtu)

% PM Reduction from Baseline

Additional TPY PM Reduced

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

Total Annual Cost ($/yr)

Estimated PM (lb/MMBtu)

% PM Reduction from Baseline

Additional TPY PM Reduced

Cost Effectiveness ($/ton) $37,236,000

$10,169,000

0.012

52%

94
$108,370

$45,702,000

$11,011,000

0.012

58.6%

129
$85,092

$40,135,000

$10,925,000

0.012

58.6%

168
$65,164 $50,515,000

$13,950,000

0.012

52%

94
$148,659

$60,992,000

$14,481,000

0.012

58.6%

129
$111,908

$59,594,000

$16,559,000

0.012

58.6%

168
$98,770 $32,136,000 $23,360,000

$8,781,000 $5,652,000

0.012 0.012

52% 52%

94 94
$93,571 $60,231

$32,879,000 $23,901,000

$8,972,000 $6,658,000

0.012 0.012

58.6% 58.6%

129 129
$69,335 $51,453

$59,594,000 $26,988,000

$10,309,000 $7,557,000

0.012 0.012

58.6% 58.6%

168 168
$61,490 $45,075



### B&V state that the four PM control scenarios are expected 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 reverse gas fabric filters.

B. Discussion of Factor in ANPRM

In our ANPRM, we presented three sets of cost estimates for SCR – costs estimated by B&V for APS, costs estimated by EPA based on a revision to APS’s cost estimates to be more representative, and costs estimated 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 effectiveness, 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 assumptions, 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 ofapproximately 0.20. Lower interest rates used by other facilities, for example, other coalfired power plants in Arizona, New Mexico, and Oregon, 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 annualized costs and cost effectiveness, EPA applied an annual to capital cost ratio of 0.15. Finally, in the ANPRM, EPA also estimated the increase in electricity generation costs from NO

x 

### and PM controls at FCPP in terms of dollar per kilowatt-hour ($/kWh). In this TSD, we discuss increased

Page 24 of 92

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

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

Unit 1

Unit 2

Unit 3

Unit 4

Unit 5

Total Annual Costs

Unit 1

Unit 2

Unit 3

Unit 4

Unit 5
Cost Effectiveness ($/ton)

Unit 1

Unit 2

Unit 3

Unit 4

Unit 5 B&V for APS
$110,664,000

$119,010,000

$113,084,000

$265,406,000

$265,406,000

$22,297,000

$23,634,000

$23,173,000

$55,755,000

$55,755,000

$4,343

$5,484

$4,582

$4,872

$4,872 EPA

EPA did not revise B&V Total Capital Cost

estimates in the ANPRM

$16,599,600

$17,851,500

$16,962,600

$39,810,900

$39,810,900

$3,758

$4,803

$3,646

$4,341

$4,330 NPS
$18,508,764

$18,508,764

$22,187,577

$52,788,968

$52,788,968

$2,983,004

$3,052,010

$3,497,117

$9,838,997

$9,838,997

$1,558

$1,469

$1,684

$1,185

$1,357

Page 25 of 92

### Table 10: Cost Estimates for PM Control Presented in ANPRM from APS and EPA Revisions
Upstream ESP Upstream Wet Metal ESP Wet Membrane Baghouse 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 December 2007 analysis. EPA believes this value was reported by APS in error because it is unlikely a wet ESP would equal the cost of a baghouse for Unit 3, but not Units 1 and 2.

Page 26 of 92

### Table 11: Comparison of Total Capital Investment (TCI) and Total Annual Costs (TAC) from

Other Western Facilities
Facility Total Capital Total Annual TAC/TCI Description Investment ($) Cost ($) (%)

Four Corners Power Plant (Unit 1) 30 $110,664,000 $22,297,000 20% SCR

Four Corners Power Plant (Unit 2)

Four Corners Power Plant (Unit 2)

Four Corners Power Plant (Unit 4-5)
Coronado Generating Station

San Juan Generating Station (Unit 1) 31

San Juan Generating Station (Unit 2)
San Juan Generating Station (Unit 3)
San Juan Generating Station (Unit 4)

PGE Boardman 32

PGE Boardman $119,010,000

$113,084,000

$265,406,000

$145,000,000

$156,805,000

$169,251,000

$215,568,000

$199,558,000

$269,500,000

$154,300,000 $23,634,000

$23,173,000

$55,755,000

$17,086,550

$20,525,000

$21,891,000

$28,359,000

$26,592,000

$39,400,000

$19,600,000 20% SCR

20% SCR

21% SCR

11.8% Combustion

Controls + SCR

13.1% SCR

12.9% SCR

13.2% SCR

13.3% SCR

14.6% Phase 1: LNB (+ SNCR contingency)

12.7% Phase 2: Additional

SCR



### The BART guidelines state that “[i]n order to improve 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 are 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 facilities, retrofit costs should also be considered, and may include auxiliary equipment, handling and erection, piping, insulation, painting, site preparation, off-site facilities, engineering, and lost production revenue. Finally, annual costs are estimated from costs of raw materials, maintenance labor and materials, utilities, waste treatment and disposal, replacement materials, overhead, property taxes, insurance, and administrative charges.

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

, including costs of unintended consequences and “owner’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: Introduction, Chapter 2: Cost Estimation: Concepts and Methodology. EPA/452/B-02-001, January 2002.

Page 27 of 92

### C. Affected State, Tribe and FLM Consultation

The Arizona Department of Environmental Quality (ADEQ) 35 

### commented that it is inappropriate to include projected costs of controls 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 Appendix Y takes into account the most stringent emission control level that the technology is capable of achieving, therefore we should not rely on a negotiated settlement of 75% control. NMED also encouraged review of additional PM control on Units 4 and 5, which can include improvement of existing controls, not just complete replacement.

The Navajo Nation 37 

### recommended that we accept the cost estimates provided by APS because the costs appeared to fall within the scope of the BART guidelines. The Navajo Nation further recommended that EPA include an incremental cost analysis because of the potential importance the high incremental costs of SCR may have on the

final BART determination.

NPS 38 

### commented that based on data from the EPA Clean Air Markets Division, SCR retrofits result in controlled emissions of 0.05 lb/MMBtu. Therefore, NPS recommended setting NO

x 

### limits of 0.07 lb/MMBtu on a 24-hour basis, 0.06 lb/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 annual costs and determining cost effectiveness. Additionally, NPS commented that cost estimates for SCR provided by APS were not adequately justified and should have relied on the EPA Control Cost

Manual , rather than the CUECost Model and other proprietary databases. NPS used the

EPA Control Cost Manual to estimate the cost of combustion controls plus SCR on all 5 units and provided revised cost estimates in their comments on the ANPRM.

35 Letter dated October 28, 2009 from Benjamin Grumbles, 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 Shirley, Jr., Navajo Nation, to Anita Lee, EPA.

38 Letter dated November 11, 2009 from Michael Snyder, National Park Service, to Anita Lee, EPA.

Page 28 of 92

### Table 12: NPS’s Estimated Costs of Combustion Controls + SCR based on EPA Control Cost

Manual reported in their comments on ANPRM 39

Unit 1
Rating (MW gross) 185

Emissions 5,446

Reductions
Capital Cost $52,793,277
Capital Cost ($/kW) $285

O&M Cost $1,896,917

Total Annual Cost $7,221,813

Cost Effectiveness $1,326 ($/ton) 2

185

4,307

$60,676,814

$328

$2,035,967

$8,104,955

$1,882 3

235

5,417

$54,026,747

$230

$2,270,190

$7,528,210

$1,390 4

790

12,684

$113,485,159

$144

$5,897,139

$18,435,022

$1,453 5

790

11,508 Total

2185

39,361

$113,945,854

$144

$5,804,109

$18,385,478

$1,598 $394,927,651

$181

$17,904,321

$59,675,476

$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 interest 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 this proposal.

39 Based on 1998 Control Cost model with costs adjusted 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 Cost Analysis 8-26-10.xls”.

Page 29 of 92

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

Initial Catalyst

Variable Frequency Drive Included Not Included

on ID or FD Fans
Miscellaneous Equipment Included Not Included

Taxes (Direct Cost)
Tuning (Indirect Cost)
Side Effect Mitigation Included Not Included (Other Capital Cost)

Lost Revenue Included Not Included

Maintenance Labor & 3% 1.5%

Materials
Catalyst Replacement $3,154,000 $574,000

Catalyst Disposal

Side Effect Mitigation (Unintended Consequences)

Interest Rate B&V/ APS
$7,941,000

10%

Included

Included

Included

15% EPA Revision
$5,093,000

6%

Not Included

Not Included

Not Included

7% EPA Rationale for Revision
EPA used a low-oxidation catalyst cost of $5,500/m 3 based on quote from Hitachi Power Systems.
Generally, a VFD is not required for operation

of SCR and was excluded.
It was unclear what miscellaneous equipment represented and was excluded.

CCM uses 6% as default tax rate.

CCM does not include this cost.
Low oxidation catalysts were assumed, therefore side effect mitigation not needed.
EPA assumes construction would occur during scheduled major outages.

CCM uses 1.5%.

We recalculated catalyst replacement cost

according to CCM recommendations.
Disposal costs are typically included in catalyst

costs.
Low oxidation catalysts were assumed, therefore side effect mitigation not needed.

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 cost estimates. Initial cost estimates were provided to EPA in January 2008, with 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 cost 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 dated February 2010. The entire B&V report was claimed by APS as confidential. On September 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 August 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 rely on the capital and annual costs are conservatively overestimated.

41 Details for Units 1-3 and 5 are included in the spreadsheet. Unit 4 is used here as an example.

42 Four Corners Steam Electric Station Units 1 through 5 NO

x Compliance Report, Revision D. Black and Veatch Corporation, Project Number 166861, February, 2010.

Page 30 of 92

### Table 14: Comparison of APS Cost Estimates Submitted in 2009 and 2010
Total Capital Cost

From March 2009

letter – costs dated August 2008

Unit 1 $110,664,000

Unit 2 $119,010,000

Unit 3 $113,084,000

Unit 4 $265,406,000

Unit 5 $265,406,000 From February 2010

submission – costs dated May 2008 or February 2010
$94,934,000

$105,279,000

$96,423,000

$223,782,000 43

$201,268,000 From March 2009

letter – costs dated August 2008
$22,297,000

$23,634,000

$23,173,000

$56,967,000

$56,967,000 From February 2010

submission – costs dated May 2008 or February 2010
$19,334,000

$20,978,000

$19,962,000

$43,587,221

$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 Power 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 estimated by NPS.

Several commenters, including NMED and NPS, suggested that the calculations of cost effectiveness should be based on the most stringent 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 conservative in estimating costs and cost effectiveness, EPA assumed 80% control efficiency for 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 estimate 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 rely 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 that it was inappropriate to include the anticipated increase in electricity costs to consumers 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 impact and we include this discussion in Section 4 of this technical support document.

43 The costs for Unit 4 include systems in common with Unit 5.

44 April 23, 2010 email from Anthony Favale, Hitachi Power Systems America to Anita Lee, EPA.

Page 31 of 92 Total Annual Cost

### Table 15: EPA Revised Cost Estimates for SCR on Units 1 – 5 (2008 dollars)
Total Capital

Investment
Unit 1
 $90,337,340

Unit 2 $97,663,260

Unit 3 $94,180,720

Unit 4 $217,727,260

Unit 5 $217,727,260

Total Facility $717,635,840 Total Annual Cost

$11,475,000

$12,114,000

$12,068,000

$28,740,000

$28,740,000

$93,137,000 Cost Effectiveness $/KW ($/ton)

$2,515 $488

$3,163 $528

$2,678 $401

$2,622 $276

$2,908 $276



### The APS cost estimate represents the upper-range of 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 Office of Air Quality Planning and Standards (OAQPS) Air Benefit and Cost Group reviewed the cost estimates NPS submitted to EPA during the ANPRM comment period. OAQPS determined that in general, NPS used the appropriate assumptions for estimating costs of SCR, however, several assumptions warrant additional explanation. These include why different indirect and direct retrofit factors were used in the capital cost calculation and whether actual vendor information is available regarding the pressure drops across duct and catalyst layers rather than relying on assumed pressure drops from the Control Cost Manual

.

Table 16: Cost Effectiveness of SCR Retrofits estimated for Several Western Power Plants
Facility Year of Cost Size Cost Effectiveness ($/ton)

Basis

Centralia Power Plant (Units 1 – 2) 2008 702.5 MW $9,091

San Juan Generating Station (Units 1 – 4)

M.R. Young (Units 1 – 2)

Naughton (Units 1 – 3)
Jim Bridger (Units 1 – 4) 2007

2009

2006

2006 350 – 544 MW

257 – 477 MW

160 – 330 MW

530 MW $5,498 – $6,932

$3,950 – $4,250

$2,751 – $2,848

$2,256 – $4,274



### Based on the cost data presented by APS, as well as 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 estimated for other Western coal-fired powerplants (See Table 16). Therefore, EPA will continue evaluating SCR in the BART fivefactor analysis.

For this technical support document, EPA has not revised 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, therefore, 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. Additionally, 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 32 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 alternative 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 emission 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/ton, 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 on the venturi scrubber. The baghouses would be the most likely choice for APS for PM control if they want to achieve significant Hg reduction from these units.

Baghouses have already been installed on the four other coal fired EGUs in Region 9 that had historically used venturi scrubbers 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 baghouses 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 their 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 achieving 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 PM control devices in Region 9 have already installed retrofit baghouses and found that to be an economically and environmentally sound approach. Therefore, EPA continues 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 by B&V for FCPP were the disposal requirements for byproduct and waste generated from each control technology and lost generation due to extended outages for installation. 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 Effectiveness baghouse ap-42.xls”.

Page 33 of 92

### pollutant discharge site. The costs for direct energy impacts, i.e., power consumption from the control equipment and additional draft system 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 considered, consistent with the BART guidelines.

B. Discussion of this Factor in ANPRM

In the ANPRM, EPA outlined several energy and non-air quality environmental impacts of the control technologies, including increased unburned carbon in the fly ash (loss of ignition or LOI) resulting from LNBs, increased emissions of sulfuric acid that may trigger permitting requirements under the Prevention of Significant Deterioration (PSD) program from the use of traditional SCR catalysts, particularly those that are vanadium-based, and the parasitic load resulting from the operation of SCR. Although not presented under this factor in the ANPRM, EPA also 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 control. 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

Unit 1 $0.001 $0.015 $0.005 $0.007 $0.004

Unit 2 $0.001 $0.016 $0.006 $0.008 $0.004

Unit 3 $0.001 $0.011 $0.004 $0.006 $0.006

Unit 4 $0.001 $0.009

Unit 5 $0.001 $0.009 Wet

Membrane

ESP

$0.003

$0.003

$0.003



### C. Affected State, Tribe, and FLM Consultation

The Arizona Department of Environmental Quality (ADEQ) submitted comments that the non-air quality impacts of SCR, such as trucking of ammonia and challenges associated with ammonia storage and handling, as well 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 experiences high levels of Hg deposition, the Colorado Department of Public Health and Environmental (CDPHE) 46 

### commented that EPA should assess the effectiveness of new fabric filter baghouses in providing additional PM reductions and co-benefits of mercury emissions reductions. Additionally, CDPHE cited additional environmental and health benefits of reducing NO

x 

### emissions on ambient ozone concentrations, and NPS cited additional benefits of reduced nitrogen deposition resulting from more stringent NO

x 

### controls.

46 Letter dated September 25, 2009 from James B. Martin, CDPHE to Laura Yoshii and Anita Lee, EPA.

Page 34 of 92

### The Navajo Nation (the Nation) submitted comments on the potential that requiring SCR as BART for FCPP would cause the facility to shut down, resulting in great economic harm to the Navajo directly and indirectly, 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 Salt 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 business 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 auxiliary 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 of the application of SCR for NO

x 

### control will trigger PSD permitting requirements, including the application of BACT, if they exceed the H 2 

### SO 4 

### significance threshold of 7 tpy. However, the existing and expected control technology for PM emissions can be effective in reducing these emissions. Specifically, 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 wet 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 venturi scrubbers, SO 3 

### emissions will have already formed H 2 

### SO 4 

### droplets. The wet membrane ESPs can have very good 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 control devices.

APS estimated costs of SCR based on the use of urea for SCR reagent rather than anhydrous ammonia, therefore EPA does not expect the 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 located next to a major rail line, EPA does anticipate urea deliveries to increase heavy-duty truck traffic between FCPP and Gallup, New Mexico, the nearest rail station. Although this factor deals specifically with energy and non-air quality environmental impacts, EPA determined that the potential adverse health impacts of increased diesel truck traffic to and from FCPP warranted

further review.

47 Letter dated March 1, 2010 from President Diane Enos, Salt River Pima Maricopa Indian Community to Jared Blumenfeld, EPA.

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### 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 concentrations of criteria pollutants were compared against the National Ambient Air Quality Standard (NAAQS), and modeledconcentrations of hazardous air pollutants were used to estimate cancer risks and a noncancer hazard quotient for comparison against background. 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 impacted 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 population 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 quotient 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 over a lifetime exposure per one million people exposed. For the other impacted census blocks, the risks are estimated to

be as low as 1 x 10 -10 

### and the hazard quotients are estimated to be as low as 0.00001. Based on the information that the increase in risks associated with transportation emissions in the most impacted census block are well 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 health risk.

EPA agrees with CDPHE and NPS that NO

x 

### reductions from FCPP will have cobenefits for tropospheric ozone and nitrogen deposition. 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 reclassified as non-attainment for the standard. We have determined that a qualitative acknowledgement of the co-benefit for ozone and nitrogen deposition is sufficient consideration for this factor. The BART guidelines generally focus on adverse environmental impacts of control technologies, such as solid or hazardous waste generation or discharges of polluted water, however, the guidelines further state that “any important relative 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 highest level of co-benefit for reducing ozone and nitrogen deposition. EPA further agrees with CDPHE that potential co-benefits for Hg reductions are possible if baghouses are required for PM control on Units 1 – 3. Currently, APS has measured Hg reductions of approximately 90% from Units 4 and 5 with their baghouse controls, while Units 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 impacts 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.

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### 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 estimate the increase in cost to produce electricity if SCR were required for BART, to assess 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 Strategies, 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 combustion controls) were installed on all 5 units at FCPP compared with the cost to purchase electricity on the wholesale market. The final report from ES is Appendix B: Economic Analysis of SCR on Four

Corners Power Plant of this TSD and the economic model 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 accelerated 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, 1975 that install air pollution control devices. ES estimated the current Business As Usual (BAU) cost to produce electricity

and modeled the cost to add LNB/LNB+OFA or SCR to all five units. ES forecasted the market price to purchase energy on the wholesale market using the Palo Verde price index, which is determined by the most costly source 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 ANPRM. 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. The economic model uses an amortization rate of 15%, which includes the interest rate and the tax rate on the debt and equity of the project. Thus, the economic model differs from the EPA Control Cost

Manual in that the Cost Manual determines the amortization rate on a pre-tax basis, using only the interest rate and amortization period. The 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

Cost per kilowatt-hour (non-discounted cost / 25 year kWh)

Cost/kWh $0.03395 $0.03451 $0.04135 $0.04451 $0.04809

Increase compared to

BAU $0.00056 $0.00740 $0.01056 $0.01414

Net Present Value (Discounted) 25 Year Cost ($Million)

Cost $5,688 $5,776 $6,892 $7,008 $7,356

% Increase compared to

BAU 2% 21% 23% 29% Market High

$0.05192

$0.01797

$7,746

36%

49 Economic Analysis of Proposed EPA BART Determination on FCPP_r0-9_18_10 RATES.xls”.

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### 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

Cost per kilowatt-hour (non-discounted cost / 25 year kWh)

Cost/kWh $0.03395 $0.03451 $0.04021 $0.04451 $0.04809

Increase compared to

BAU $0.00049 $0.00626 $0.01056 $0.01414

Net Present Value (Discounted) 25 Year Cost ($Million)

Cost $5,688 $5,764 $6,704 $7,008 $7,356

% increase compared to

BAU 1% 18% 23% 29% Market High

$0.05192

$0.01797

$7,746

36%



### The results from the economic model suggest that the retrofit of all five units at FCPP with SCR would increase the non-discounted cost of electricity generation by an average of $0.00740/kWh over the 20 year amortization 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 with 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 electricity for FCPP that exceeded the cost to purchase electricity on the open market. Assuming 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 increase on a non-discounted basis. EPA has determined that SCR will increase the cost of electricity generation, but is not likely to force FCPP to shut down.

Retail consumers of power pay more than just the generation 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 on the entire portfolio of APS generation assets and power purchase contracts, which include coal, natural gas, nuclear, and some renewables. Therefore, a 22% increase in generation costs at only one of APS’s sources of power does not result in a commensurate 22% increase to rate payers. As discussed in Appendix B to this TSD, 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. APS 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 portfolio of power generation assets and power purchase agreements, APS estimated carbon prices 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 knowing the assumptions that went

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### 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 SCR on APS rate payers that also employed public information from APS (See “Economic Analysis of Proposed EPA BART Determination on FCPP_r0-9_18_10 RATES.xls”, Rate Impact Estimates worksheet in docket for this proposal). This analysis 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 involves numerous conservative simplifying assumptions to estimate the affect of SCR 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 customers, 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 the 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 revenues (escalated to 2015 by 1.5% annually) and then divided by estimated retail sales (kWh) based on 2009 sales (escalated to 2015 by 1.5% annually). This results in the estimated retail rate with installation and operation of SCR. The increase in the retail rate is then estimated by subtracting the estimated retail rate without SCR from the estimated rate with 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 would shut down, including lease negotiations, future regulations targeting greenhouse gas emissions, mercury and HCl emissions (Utility MACT), and ash handling (coal combustion residues). ES explored these issues in more detail in their report to EPA. There is considerable uncertainty related to greenhouse gas regulations and the effect 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, economic, and market, that each owner must consider when determining whether investment in SCR meets the needs of their stakeholders (rate payers, regulators, and owner boards) and shareholders. Because of the uncertainty associated 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 regulatory factors, EPA is only considering the

50 http://newamericamedia.org/2010/04/socal-edison-bails-out-of-coal-plant.php

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### results of the economic model for SCR in our analysis, 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 comments 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 letter how SCR would affect their fly ash business, therefore, EPA assumed potential impacts of requiring SCR include the possible shutdown of FCPP, and the impact of ammonia in the FCPP fly ash. As discussed above, EPA has determined, based on the economic 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. This report from EC/R is Appendix C of this TSD: Impact of Ammonia in Fly Ash on its Beneficial 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 other 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 determined that the impact of SCR on the fly ash at FCPP is smaller than the impact of LNB on the fly ash, and in both cases, the impact can be mitigated.

EPA concludes that energy and non-air quality impacts 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 the 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 in 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 existing level of NO

x 

### control already

meets BART.

Units 1 – 3 currently use venturi scrubbers to control PM and SO 2 

### emissions, with a PM control efficiency of 98%, with less control of PM 10 

### and PM 2.5 

### , and an SO 2 

### control efficiency of 90%. Units 4 and 5 at FCPP each use reverse gas fabric filters (RGFF) and tray tower flue gas desulfurization (FGD), also called 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 approximately 8% of the exhaust gas is bypassed around the scrubber to be used for reheat in the stack. The FCPP stack lining is

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### not capable of withstanding wet droplet conditions. Reduction of the bypass allowing a wet stack would require new stacks or new stack liners. B&V concluded that the most stringent controls have already been applied to Units 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

Boiler Boiler – LNB (NO

x )

Economizer Economizer

Air Preheater Air Preheater

Venturi Scrubber Venturi Scrubber – Venturi Scrubber – (PM, SO 2 ) Lime (PM, SO 2 ) Lime (PM, SO 2 )

Stack Stack Stack Unit 3

Boiler – LNB (NO

x )

Economizer

Air Preheater Unit 4 Unit 5

Boiler – LNB (NO

x ) Boiler – LNB (NO

x )

Economizer Economizer

Air Preheater Air Preheater

Reverse Gas Fabric Reverse Gas Fabric Filter (PM) Filter (PM)
Tray Tower Lime Tray Tower Lime

Flue Gas Flue Gas

Desulfurization Desulfurization (SO 2 ) (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 encountered 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 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 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

determination. We discussed the LNB retrofit in more detail in Section 2 above.

C. Affected State, Tribe, and FLM Consultation

We did not receive comments on the existing air pollution 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 and 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 parentheses.

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

EPA also concludes that existing PM controls for Units 1 – 3 at FCPP, the venturiscrubbers do not meet BART and are the least effective PM control devices on large coalfired EGUs, especially at a pressure drop below 8 inches 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 Permit 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 emission rates comparable to Unit 5, and that PM emissions from Units 4 and 5 are significantly 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 Part 60 Subpart Da. Most current coal fired boilers now use baghouses that are capable of meeting PM limits of about 0.01

to 0.012 lb /MMBtu.

As mentioned in Section 3 of this TSD, baghouses have 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 dollars per ton of PM removed, to allow the companies to continue to operate the units in continuous compliance with their PM and opacity limits. EPA notes that these four units operated with a re-heat of the scrubber exhaust. This allowed the use of Continuous Opacity 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 use of the re-heat system was discontinued and did not give permission for removal 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 EPA 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 meet. Thus, the regulatory agencies and the public lack this opacity tool to help assess continuing 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 Factor

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### In their analysis, FCPP stated that the remaining useful life of Units 1 – 5 were each at least 20 years. As such, the remaining useful life does not impact the cost effectiveness of controls because the remaining life 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 life 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 consistent with the EPA Control Cost Manual

. We requested comment on the use of 20 years to represent the remaining useful life of

FCPP.

C. Affected State, Tribe, and FLM Consultation

The Navajo Nation recommended that we adopt a phased 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 Navajo 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 determination 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 most appropriate to rely on a 20 year useful life as the default for amortization purposes.



## 7. Degree of Improvement in Visibility which May Reasonably 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 Guidelines is the degree of visibility improvement from the BART control options. 59 FR 39104, 39170 (July 6, 2005). The BART guidelines recommend use of the CALPUFF air quality dispersion model to estimate the visibility improvements at each 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 baseline, or current, source configuration. ENSR Corporation (now AECOM) conducted the modeling for FCPP and included sixteen Class I Areas in their modeling analysis; fifteen are within 300 km of FCPP and one Class I area, Grand Canyon National Park, is just beyond 300 km from FCPP. These are listed in Table 21 and 22 and shown in Figure 1. The measured visibility impairment

Page 43 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 Summary data, Original IMPROVE Algorithm, http://vista.cira.colostate.edu/improve/Data/IMPROVE/summary_data.htm)

Class I Area

Arches NP

Bandelier WA
Black Canyon of the Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

West Elk WA

Weminuche WA

Wheeler Peak WA 10 th Percentile Deciview Impairment

3.9

5.1

3.2

3.9

3.8

3.1

4.5

3.2

2.2

4.1

2.8

5.4

2.8

2.2

3.2

2.8 90 th Percentile Deciview Impairment

11.8

12.6

11.0

11.8

12.0

11.7

11.8

11.0

10.3

11.6

11.3

13.0

11.3

10.3

11.0

11.3

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### Figure 1: Map of Class I Areas 300 km from FCPP

Page 45 of 92

### Under the BART guidelines, the measure of the visibility 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 relative to natural background, as estimated using the CALPUFF air quality modeling system. The meaning of this is described next, followed by particulars of the application 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 visibility: a given increase in visual range is perceived differently depending on how good the original visibility was (that is, it is not on a linear scale). The deciview scale is designed to address this problem. It is linear with respect to perceived visual changes over its entire range, analogous to the decibel scale for sound: a given change in deciviews 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 extinction 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 atmospheres, and greater visual range, while increasing deciview values represent increasingly poor visibility. An increase of 1 deciview corresponds to about a 10% increase in extinction. (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 more of impairment in a Class I area “contributes” to visibility impairment and is subject 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 pollutant concentrations based on source emissions and how they disperse in the atmosphere. The CALPUFF modeling includes source emissions of the following visibility-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 incorporates 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 meteorological conditions and background ozone concentration. These concentrations are converted 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 pollutants:

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 Environments (IMPROVE) is a network of monitors in various Class I Areas, established to assess visibility impairment and its causes. The IMPROVE equation is used to converted monitored concentrations into extinction, a measure of visibility. See: http://vista.cira.colostate.edu/improve/

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

Finally, the delta deciviews ( Δ dv) represents the impact on visibility in deciviews of the source being evaluated, and is also provided by CALPUFF. It is the change, or “delta”, between deciviews with and without the source. Under the BART guidelines, delta deciviews is the difference between deciviews including the impact of the source and natural background, and deciviews of the natural background alone. Each modeled day and location in the Class I area will have an associated delta deciview. For each day, the model finds the maximum visibility impact of all locations (receptors) in the Class I area. From among these daily values, the BART guidelines 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 is 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 modeling protocols

submitted to EPA 53 

### . The modeling analysis generally followed the BART protocol developed by the Western Regional Air Partnership (WRAP), except as noted below 54



### .

The WRAP protocol received extensive scrutiny during 2005-2006 by various States, EPA Regions, and Federal Land Managers (FLMs). Some key features of the protocol are listed here. Meteorological fields were 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 modeling domain. Subdomains were extracted for use by individual states, such as Arizona and New Mexico. The MM5 fields were then processed using CALMET (meteorological 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 discussion, WRAP elected to blend meteorological station observations into the MM5 fields, instead of relying on the CALMET “no observations” (“no obs”) mode.

For visibility calculations, the pollution concentration predictions of CALPUFF are used in two post-processing steps. First, POSTUTIL considers ammonia background concentrations, temperature, and humidity to determine how much nitrate ends up as particulate ammonium nitrate; this is to reflect the 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 particular way of applying it, the

53 See BART Visibility Modeling Protocol for the Arizona Public Service Four Corners Power Plant”, ENSR Corporation, January 2008, Doc. No.: 00494-021-300

54 “CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in the Western United States”, Western Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph Morris, Abby Hoats and Yiqin Jia, August 15, 2006. Available on UCR Regional Modeling Center web site, BART CALPUFF Modeling, http://pah.cert.ucr.edu/aqm/308/bart.shtml

Page 47 of 92

### WRAP protocol specified visibility calculation “Method 6” in CALPOST, the EPArecommended approach that uses monthly average humidity.

The AECOM modeling protocol mainly followed the WRAP protocols. CALMET and CALPUFF settings were almost all the same; the WRAP-defined Arizona and New Mexico subdomains were used; all Class I Areas within 300 km of FCPP were included, as well as Grand Canyon National Park. However, the AECOM protocol differed in several important respects. First, AECOM 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 in meteorological station wind observations, AECOM used a lower radius of influence for stations (R1, R2, RMAX1). As shown in the wind field illustrations provided by AECOM, this resulted in smoother wind fields than those used for WRAP, which had some 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 CALMET option settings be changed. These changes resulted in a more refined approach that is more consistent with approaches used in PSD permit application modeling. The revised modeling has more extensive use of meteorological station observations (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 above. Various relevant CALMET option settings are listed in Table 23: Selected CALMET 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 48 of 92

### Table 22: Class I Areas in CALPUFF Modeling for FCPP

Class I Area

Arches

Bandelier Wilderness
Black Canyon of the Gunnison

Wilderness
Canyonlands
Capitol Reef
Grand Canyon

Great Sand Dunes National

Monument

La Garita Wilderness

Maroon Bells Snowmass

Wilderness

Mesa Verde

Pecos Wilderness

Petrified Forest

San Pedro Parks Wilderness

Weminuche Wilderness

West Elk Wilderness

Wheeler Peak Wilderness Abbreviation

arch

band

blca

cany

care

grca

grsa

laga

mabe

meve

peco pefo

sape

wemi

weel
whpe State

UT

NM

CO

UT

UT

AZ

CO

CO

CO

CO

NM

AZ

NM

CO

CO

NM Agency

NPS

NPS

NPS

NPS

NPS

NPS

NPS

USFS

USFS

NPS

NPS

NPS

USFS

USFS

USFS

USFS IMPROVE

monitor 55 Distance to FCPP (km) 56

CANY1

BAND1

WEMI1 245

216

217

CANY1

CAPI1 214

283

GRCA2 345

GRSA1 279

WEMI1 202

WHRI1 294

MEVE1 62

WHPE1 258

PEFO1 224

SAPE1 160

WEMI1 137

WHRI1 245

WHPE1 265

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

56 Distance is calculated between Unit 1 of each facility and the centroid of the Class I area.

Page 49 of 92

### Table 23: Selected CALMET settings for FCPP
Option

version

NOOBS No Observation 0 0 or 1 1

Mode implied

ICLOUD gridded cloud fields 0 0 0

IWFCOD

IFRADJ

IKINE

IOBR

ISLOPE

IEXTRP

ICALM

BIAS

IPROG

RMAX1

RMAX2

RMAX3

RMIN

RMIN2

TERRAD

R1

R2

ITPROG

TRADKM radius of influ. for T 500 500 500 interp.

IAVET spatial T averaging 1 0 1

JWAT1

JWAT2 Description

CALMET version

diagnostic winds
Froude wind adj.

kinematic effects

O'Brien vertical wind adj.
slope flows
extrapolate wind to upper air

extrapolate calm to upper air
layer biases sfc vs.

UA
gridded initial

prognostic

max surface radius of

influence

max aloft radius of

influence

max over-water
radius of influence.

min wind radius of

influence.

min dist sfc winds

extrap

terrain radius of in

influence
weight surface Step 1

vs. obs
weight aloft Step 1

vs. obs

3D T from obs or prognostic

starting land use for T interp. over water

ending land use for T

interp. over water EPA WRAP Original

default modeling 57

5.8, level 6.211, level 5.8, level

070623 060414 070623

1

1

0

0

1

-4

0

NZ*0

0

NA

NA

NA

0.1

4

NA

NA

NA

0

999

999 1

1

0

0

1

1

0

NZ*0

14

50

100

100

0.1

4

10

100

200

1 or 2 implied

51

55 1

1

0

0

1

1

0

NZ*0

14

30

100

100

0.1

4

10

18

20

2

51

55

57 January 29, 2008

58 December 16, 2009 (ENSR/AECOM report dated November 2008)

Page 50 of 92 Revised modeling 58

5.8, level

070623

0

-4

1 Comments

Change per FLM recommendation:

use both surface and upper air

observations

Change per FLM recommendation:

to extrapolate up from surface

Use prognostic inputs from MM5

Gives smoother wind fields, per

AECOM

Gives smoother wind fields, per

AECOM
Gives smoother wind fields, per

AECOM
Change per FLM recommendation:

use surface station temperatures

Smoothing turned on (WRAP thought MM5 already smooth enough)
This area has very little "water" land use; may set to 999 to disable

overwater feature, and avoid a CALMET bug

### As mentioned above, the BART guidelines recommend that impacts of sources be estimated in deciviews relative to natural background. EPA used background concentrations from Table 2-1 of “Guidance for Estimating 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 monthly variation in its visibility impact, which changes with relative humidity. The resulting backgrounds in deciviews differ by roughly 1% from those resulting from the method originally 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 control 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 particulate ammonium sulfate and ammonium nitrate, both of which degrade visibility. It is present in the atmosphere from both natural and anthropogenic sources. The latter may include livestockoperations, fertilizer application associated with farming, and ammonia slip (or unreacted ammonia) from its use in SCR or SNCR to control NO

x 

### emissions.

In the CALPUFF modeling inputs, EPA and AECOM both assumed that the remaining ammonia in the flue gas following SCR reacts with sulfuric acid to form ammonium sulfate or ammonium bisulfate before exiting 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 additional 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 direct link http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf

60 AECOM’s modeling of FCPP used the annual average deciviews from the guidance document, and calculated the background soil concentrations that would yield those deciviews; the soil concentrations were used by AECOM in the CALPOST visibility, a single value for the entire year irrespective of relative humidity.

Page 51 of 92

### Sulfuric acid (H 2 

### SO 4 

### ) is formed from coal-fired power plants from the oxidation 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 sulfate, which is an important contributor to visibility impairment. CALPUFF models emissions of H 2 

### SO 4 

### as inorganic particulate sulfate.

Sulfuric acid emissions from power plants must be reported to the Toxic Release Inventory (TRI) and are typically calculated for the 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 Institute (EPRI) 61 

### . These calculations rely

on assumed values for the amount of fuel sulfur converted 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 scrubbers, 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, baseline and post-SCR estimates of

H 2 

### SO 4 

### from FCPP are based on the best current information 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 and modeling results AECOM submitted for FCPP. Although AECOM included SNCR in addition to LNB and SCR in their modeling, we focused on the LNB 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 Tables 25. The spreadsheets where these modeling inputs were calculated are available electronically in the docket for this proposal. The modeling scenarios presented here 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 required 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 must rely on the calculation methodology to estimate sulfuric acid

emissions from FCPP.

62 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

, 1016384, Technical Update, March 2008.

Page 52 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 and LNB+OFA on Units 3 –

5 for NO

x 

### control modeled by EPA, FC3a = Visibility Impacts from SCR on Units 1 – 5 modeled by AECOM, FC3e = Visibility Impacts from SCR on Units 1 – 5 modeled by EPA.

Table 25: AECOM Modeling Inputs (lb/hr)

Scenario FC0a - Baseline

Unit 1

SO 2 464.17

SO 4 3.35

NO

x 1,841.37

SOA 8.35

PM fine 30.74

PM coarse 12.52

EC 1.18

Scenario FC1a – PM control on Units 1 - 3

SO 2 464.17

SO 4 0.34

NO

x 1,841.37

SOA 8.35

PM fine 15.34

PM coarse 11.72

EC 0.59

Unit 1

SO 2 464.17

SO 4 3.35

NO

x 1,010.91

SOA 8.35

PM fine 30.74

PM coarse 12.52

EC 1.18

Scenario FC3a – SCR on Units 1 – 5

SO 2 464.17

SO 4 30.71

NO

x 147.31

SOA 8.35

PM fine 30.74

PM coarse 12.52

EC 1.18 Unit 2

615.12

3.78

1,567.66

9.41

47.87

19.49

1.84

615.12

0.38

1,567.66

9.41

20.39

15.58

0.78

Scenario FC2a – LNB + OFA on Units 1 – 5

Unit 2

615.12

3.78

1,051.90

9.41

47.87

19.49

1.84

615.12

34.61

141.09

9.41

47.87

19.49

1.84 Unit 3

995.26

4.65

1,926.23

11.58

52.90

21.54

2.03

995.26

0.47

1,926.23

11.58

22.54

17.22

0.87

Unit 3

995.26

4.65

1,078.69

11.58

52.90

21.54

2.03

995.26

42.61

192.62

11.58

52.90

21.54

2.03 Unit 4 Unit 5

2,026.10 2,130.76

1.03 1.03

5,015.98 4,444.04

32.00 32.00

100.93 48.00

77.12 36.67

3.88 1.84

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

2,026.10 2,130.76

1.03 1.03

5,015.98 4,444.04

32.00 32.00

100.93 48.00

77.12 36.67

3.88 1.84

Unit 4 Unit 5

2,026.10 2,130.76

1.03 1.03

3,561.35 3,155.27

32.00 32.00

100.93 48.00

77.12 36.67

3.88 1.84

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

2,026.10 2,130.76

9.53 9.58

601.92 533.29

32.00 32.00

100.93 48.00

77.12 36.67

3.88 1.84

Page 53 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 outlines 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)

Controlled SO 2 emissions (lb/hr)

Conversion of SO 2 to H 2 SO 4 via SO 3 due to combustion (%)

Conversion of SO 2 to SO 3 due to SCR (%)

H 2 SO 4 penetration 64 through air preheater

H 2 SO 4 penetration through venturi

scrubber

H 2 SO 4 penetration through baghouse

H 2 SO 4 removal by wet spray tower 3,629 63

464

0.11%

1%

0.9

0.65 4,092

615

0.11%

1%

0.9

0.65 5,039

995

0.11%

1%

0.9

0.65 13,920 14,002

2,026

0.11% 2,131

0.11%

1% 1%

0.9 0.9

-­ -­

0.10

0.47 0.10

0.47



### As discussed above, in addition to emissions from the facility, the background ammonia concentrations must be specified for the model. The IWAQM default value for ammonia background is 1 ppb year-round (discussed below). AECOM used background ammonia concentrations based on concentrations 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’ visibility improvements in terms of the 98th percentile (8th highest) of the daily 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 one deciview change in visibility

63 Based on uncontrolled SO 2 = 1.7 lb/MMBtu

64 Sulfuric Acid removal efficiency = (1 - Penetration ) x 100%

Page 54 of 92

### impairment is a small but perceptible change under most circumstances when viewing scenes in a Class I area. Table 28 presents the impact 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 visibility.

Table 28: Impacts of FCPP on Visibility (98 th 

### Percentile of daily maximum dv) at Sixteen Class I Areas as Modeled by AECOM

Arches

Bandelier
Black Canyon
Canyonlands
Capitol Reef
Grand Canyon

Great Sand Dunes

La Garita

Maroon Bells

Mesa Verde

Pecos

Petrified Forest

San Pedro

West Elk

Weminuche

Wheeler Peak

Sum of Class I areas Baseline (FC0a)

1.98

1.71

1.44

2.25

1.74

1.07

1.02

1.36

1

3.17

1.55

1.21

2.21

1.22

1.90

1.20

26.03 Visibility Impact (dv) after applying:

Wet ESP (FC1a)

1.96

1.70

1.43

2.23

1.73

1.07

1.02

1.36

0.81

3.14

1.54

1.20

2.18

1.21

1.68

1.19

25.45 LNB (FC2a) SCR (FC3a)

1.74 1.23

1.57 1.12

1.21 0.75

2.06 1.67

1.53 1.15

0.95 0.66

1.02 0.62

1.08 0.58

0.66 0.35

3.01 2.73

1.31 0.88

1.05 0.68

2.04 1.51

1.03 0.56

1.66 0.94

0.97 0.64

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 particular, the rate of SO 2 

### to SO 3 

### oxidation from the SCR catalyst and the amount of sulfuric acid that penetrates through (or is lost to) the air preheater. APS submitted comments regarding our assumptions in the ANPRM. The following discussion provides a brief summary of each assumption used in the sulfuric acid emissions calculation, and a more detailed rationale for the two cases where EPA disagreed 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 55 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 available alkalinity 66 

### , therefore AECOM and EPA both rely on the value of 0.95 for estimating 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 boiler. 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 measurements. 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 0.111% 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 efficiency in our ANPRM because low conversion catalysts are commercially available to specifically

reduce H 2 

### SO 4 

### formation following the application of SCR. In their comments on the ANPRM, APS stated that conversion levels are generally 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 in the Proceedings of the 2006 Environmental Controls Conference, written by Hitachi Power Systems America, American Electric Power, and Babcock-Hitachi (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 information EPA submitted to Hitachi Power Systems America regarding FCPP, Hitachi 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 the 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 average 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-2009-0598-0195).

67 Harrison, K.E., L.S. Monroe, J.E. Cichanowicz, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 3 (2005). Southern Company Services, October 2005.

68 Anthony Favale, Hitachi Power Systems America to Anita Lee, electronic mail, April 21, 2010.

Page 56 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 achieved may be lower than the guarantee, to be conservative, EPA has determined that a 0.6% conversion rate is most appropriate for our sulfuric acid estimates used in the visibility modeling. EPA updated the cost estimates for SCR to reflect the cost of the Hitachi CX series catalysts (see Section 3, discussion of Factor 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 available 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 2008 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 units show a range of percent removal from 0 – 69%. Before calculating the average % removal of H 2 

### SO 4 

### observed from low-sulfur Eastern bituminous coal, EPRI 2008 and Harrison 2005 excluded the 0% removal value because “the data point showing 0% removal at approximately 600 ppm SO 2 

### is believed suspect, as an identical companion unit firing the same coal exhibited sulfuric acid capture of 38%”. Because data from other coal types was not available, EPRI 2008 and Harrison 2005 suggested that western coals with acidic ash (e.g., bituminous) may 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 presented in the ANPRM. This is consistent with APS’s statement cited above that their ash has low alkalinity.

In their analysis for FCPP, AECOM used an air preheater penetration factor of 0.9 (10% removal). The 0.9 penetration factor is consistent with the

value for PRB coal in Harrison 2005 and for Western bituminous and subbituminous coal in Hardman 1998, but inconsistent with the value for PRB

coal from EPRI 2008. The values in EPRI 2008 document 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 than EPRI 2008.

APS submitted comments to EPA regarding our use of 0.49, stating that APS considered the use of this factor and determined 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 preheater to be operated at low temperature and would also result in significant operational problems for FCPP, and (3) the low alkalinity ash at FCPP suggests 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, APS, to Anita Lee, EPA, October 28, 2009.

Page 57 of 92

### to rely on the value of 0.9 for Western bituminous and subbituminous coal in Hardman 1998. However, Harrison 2005 associates the 0.9 value specifically with PRB coal, not Western bituminous and subbituminous coal. Because Harrison 2005 is the updated version of the Hardman 1998 publication from Southern Company Services, EPA concludes that the PRB 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 reported for this value (but a standard deviation was reported for the six units on which the Eastern low-sulfur bituminous value was based) in Harrison 2005, EPA concludes that the 0.9 value is based on a very limited number of data points.

APS states that “the data presented in the [EPRI] 2008 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 their assumption that the air preheaters at FCPP will remove 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 bituminous 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 removal of H 2 

### SO 4



### .

The 2010 EPRI update 70 

### to their 2008 publication revised the air preheater penetration factor for PRB coal from 0.49 (2008 version) to 0.36 (2010 version). Given the high alkalinity of PRB ash, we expect removal 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. Although 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 alkalinity 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 represent the best available

estimates for FCPP coal. Because of the inconsistencies 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 justify the use of the Hardman 1998 penetration factor of 0.9 for FCPP. We followed the 2010 version of EPRI report and used a penetration factor of 0.36 in our calculation.

Downstream of the air preheater, H 2 

### SO 4 

### is additionally lost to PM and

SO 2 

### control equipment. EPA and AECOM used a penetration factor through the

venturi scrubbers on Units 1 – 3 of 0.65. EPRI recommended 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 EPRI70 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants

, Version 2010a, 1020636, Technical Update, April 2010.

71 Coal used by FCPP is typically > 20% ash, whereas PRB coal is typically < 7% ash.

Page 58 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 ammonia 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 regions. Alternative levels may be used if supported by data. In their January 2008 BART modeling protocol (p. 4-1) APS expressed the concern that CALPUFF over-predicts 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 based on measurements in the

Four Corners area. 74



### To address these concerns using an objective approach based on monitored data, EPA estimated ammonia background for all Class I areas (except Mesa Verde National Park, see below) by a back-calculation from measurements at monitors run by the IMPROVE program 75 

### . IMPROVE monitors do not measure ammonia directly; rather, they measure particulate sulfate and nitrate. 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 and 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 (IWAQM) 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 Service to Scott Bohning, EPA, February 2, 2009.

75 Interagency Monitoring of Protected Visual Environments http://vista.cira.colostate.edu/improve/

Page 59 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, which depends on temperature and pressure. Since temperature and pressure are not available 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 is a 24-hour average ammonia estimate in ppb for each monitor and for each measurement day (typically every 3 rd


### calendar day).

The monthly values required by CALPUFF were based on these daily values, as described below. The estimate represents a lower 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 sulfate 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 uses ammonia make it a reasonable approach that does rely on available measured 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 averaged over all monitors 77



### , resulting in a single value for each of the 12 calendar months. For the months of May and July, this back-calculation resulted in a somewhat lower value than the IWAQM default of 1 ppb which was also used by APS; for these 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 Generating 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 available ammonia. But for purposes of modeling visibility impacts relative to natural background, i.e. the situation for which there are no anthropogenic sources, it is reasonable to assume the ammonia is all available for reacting with the pollutants in the plume from FCPP.

Ammonia background concentrations for Mesa Verde National 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, but

76 The Class I areas are at higher elevations than used in the standard atmosphere, so pressure and also temperature would be lower. Since these work in opposite directions in the formula for converting to ppb, these effects tend to cancel each other. In any case the net effect is small relative to that of the other uncertainties and assumptions in the

method.

77 Results from Zion were not used, as they were incomplete and also appeared anomalous.

78 Mark E. Sather et al. , 2008. “Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, USA”. Journal of Environmental Monitoring, 2008, 10, 1319-1325, DOI: 10.1039/b807984f

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### because particulate formation happens within a pollutant 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 chloride (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 suggesting that after emission into the atmosphere, HCl and HF tend to remain in the gas phase, not the particulatephase, and also that the solubility of chloride and fluoride ions into watercontaining particles would be inhibited by the presence of sulfate, whose solubility is orders of magnitude higher. Therefore, in this proposal, EPA removed HCl and HF emissions from our modeling inputs 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 the improvements at all areas, (3) the percentage change in deciview impacts compared to the baseline at each area, and (4) a metric that accounts for the size of the land area over which

79 NPS recommended HCl and HF be included in the category “condensable organic PM”. For CALPUFF modeling, EPA included HCl and HF into fine PM instead of condensable organic PM because they are inorganic, and because they are not subject to the chemistry in CALPUFF that is specific to organic compounds.

80 Comments submitted by Eladio Knipping, EPRI dated October 26, 2009.

Page 61 of 92

### controls provide visibility benefits. Each of these has advantages and disadvantages. Their absolute worth is somewhat in the eye of the beholder, but all of them provide useful information on visibility impacts, as long as their inherent limitations are understood. Deciview improvement at each Class I area is the primary metric under the BART guidelines. The third and fourth of the metrics, percentage and land area weighting, are described below.

The motivation for the second and fourth metrics, which involve sums over Class I areas, is to provide a single number for comparing control scenarios to each other. There are multiple Class I areas, with different visibility impacts for each, but there is no established metric for expressing visibility impact considering all areas together in a single number. The overall impact can be assessed more or less intuitively, weighing the various area impacts and the number of affected Class I areas. As an alternative 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 – 2003 modeling period to determine the percent change in deciview impacts resulting from 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 scenario’s daily delta deciviews against those of the baseline. Data from all modeled days was used, not just the highest impact days. Based on the modeling we conducted for the ANPRM, we estimated delta deciview improvements of 42 – 59% from 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 include impacts from many other anthropogenic and nonanthropogenic sources; 59% improvement does not mean that visibility impairment in the current atmosphere is reduced by that amount. Rather, it represents improvement in just the FCPP contribution to impairment. By the nature of percentages, a feature of this metric is that when baseline impacts are small, even a small deciview benefit from controls may give a large percentage improvement. Conversely, when baseline impacts are high, even a relatively large deciview improvement may give only a modest percentage improvement. This metric emphasizes relative improvements in FCPP’s impairment contribution over absolute deciview improvements in visibility.

For the land area metric, we multiplied the 98th percentile 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 each 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 visibility improvement at more locations than a smaller area. The Grand Canyon has a land area of 3972 km 2 

### , so this metric gives substantially more weight to improvements there than to the Black Canyon of the Gunnison, with an area of only 53 km 2 

### , whereas a simple

Page 62 of 92

### sum of deciviews weights them equally. The main effect of the land area metric, as compared to a simple sum of deciviews, is to give greater weight to the larger Class I areas such as Canyonlands, Capitol Reef, West Elk, and especially the Grand Canyon.

The simple sum of delta deciviews considers each Class 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 Class 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 would count more than a large improvement at a small area. Weighting by land area can seem reasonable or not, depending on how relevant one considers the particular 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 improvement. A defect of the land area metric is that it assumes that the visibility improvement is the same at every location within a given Class I area; in reality visibility impacts and improvements vary in time and space. A more elaborate 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 enjoyment they experience. The weighted land area metric considers the relative sizes of Class I areas, but in a way that can easily be calculated, unlike those elaborations.

Various ANPRM commenters objected to this metric on grounds of its seeming artificiality, its complexity, and its unfamiliarity. Any metric entails judgements about the relative importance of the magnitude, frequency, and spatial coverage of visibility improvements; this is especially 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 the merits of the metric rather than on the visibility implications of its calculated number. For this proposal EPA did not calculate or consider the land area weighted 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 surrounding Class I areas based on studies by the Grand Canyon Visibility Transport Commission and the Western Regional Air Partnership (WRAP), which estimated that NO

x 

### emissions from stationary sources probably cause 2 – 5% of visibility impairment on the Colorado

Plateau 81



### .

81 Stationary Source NO

x and PM Emissions in the WRAP Region: An Initial Assessment 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 63 of 92

### The estimate from the initial WRAP assessment of the visibility impairment from stationary sources is based on the 20% worst visibility days on the Colorado Plateau. WRAP determined that on those 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%). However, 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 are dominated by particulate nitrate and exceed the annual average. WRAP provided 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 the 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, 2008 to EPA Region IX, sent prior to the ANPRM, Paul Tourangeau, Director of the Air Pollution Control Division in the Colorado Department of Public Health and Environment (“Colorado”), describes a tool developed by the WRAP called the Weighted Emissions Potential (WEP, on WRAP TSS (Technical Support System) Source Apportionment web site, http://vista.cira.colostate.edu/TSS/Results/SA.aspx). The WEP uses back-trajectories and spatially gridded emissions data to identify the geographic regions that contribute to visibility impairment. Colorado conducted a WEP analysis for Mesa Verde for visibility impacts from nitrate that indicates the two grid cells which contain FCPP contribute over 50% to the nitrate visibility impairment at Mesa Verde and Weminuche Wilderness on 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 sulfuric acid emissions, but encouraged EPA to use measurement data when available. The Nation pointed to EPA’s request to Salt River Project to conduct source tests to measure current (baseline) sulfuric acid emissions from Navajo Generating Station 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 reasons, including differences in the types of air pollution control equipment used and those impacts on sulfuric acid capture. Additionally, regardless of where the source test was conducted, unless the testing protocol was designed to measure inlet and outlet concentrations at each potential sulfuric acid control point (e.g., air preheater, baghouse, etc.), it is not possible, based solely on exit emission rates from the stack, to determine which of the many assumptions used in the sulfuric acid emissions calculations requires revision.

Page 64 of 92

### However, it may still be instructive to examine predicted and measured

sulfuric acid emissions from NGS. NGS conducted source tests on November 16

– 17, 2009 to measure baseline sulfuric acid emissions 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 the model overpredicts sulfuric acid emissions compared to measurements. Because EPA 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 rationale we provided above, and not the NGS source tests, to justify our assumptions for the sulfuric acid

emissions calculations in Section 6.E.a.

3. Ammonia Background Levels

The Arizona Department of Environmental Quality (ADEQ) stated 85 

### that since the back-calculation method only indirectly estimates ammonia via measurements of sulfate and nitrate, it may not qualify 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 measurements that a) already include the effect of FCPP emissions, leading to “double-counting”, and b) may have formed due to distant sources, rather than having been formed locally. Finally, ADEQ further recommended additional ammonia monitoring for assessment of the accuracy of the back-calculation method.

The National Park Service and the U.S. Forest Service (NPS and FS, and together, FLMs 87 

### ) supported the back-calculation methodology and results we

82 Salt River Project Navajo Generating Station – Acid Mist Emissions Test Report by Catalyst Air Management, 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, which 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 ANPRM 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 Federal Land Manager in charge of National Wildlife Refuge Class I areas. No refuges are within the 300 km modeling domain of FCPP and EPA did not receive comments on our ANPRM from the U.S. FWS – National Wildlife Refuge System – Branch of Air Quality, therefore we use the term

Page 65 of 92

### presented in the ANPRM. The FLMs determined the back-calculation method was more comprehensive because it considers both ambient ammonia measurements at specific locations within the modeling domain and the amount of ammonia that must have been present along the transport 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 transport path in the ammonia background value. Additionally, the FLMs recommended that the modeling results be used in a relative sense for comparing control technologies rather than continue disagreement over the absolute values used for the background ammonia. However, the Forest Service still recommended placing more emphasis on the visibility results from EPA modeling using back-calculated ammonia values. The Navajo Nation supported the use of ambient measurements where possible and noted that Salt River Project (SRP), primarily in the interest of Navajo Generating Station, has installed ammonia monitors near Grand Canyon National Park to better inform background ammonia levels for CALPUFF modeling. Results from SRP’s ammonia monitoring project 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 our ANPRM, NPS commented that AECOM likely underestimated visibility impacts of the facilities because AECOM modeled inorganic condensable particulate matter as only sulfuric acid mist. NPS conducted their own CALPUFF modeling analysis (See Table 31) to estimate visibility benefits of controls and used AECOM estimates

for SO 2 

### and NO

x 

### and NPS estimates of PM emissions and background ammonia. Although NPS supported our use of back-calculated ammonia background values, for comparison purposes, NPS used a year-round background ammonia concentration of 1 ppb, consistent with the IWAQM default.

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 comments on the ANPRM, but in the capacity of a FLM of an impacted

Class I area.

Page 66 of 92

### Table 31: NPS Modeling Results – Average 8 th 

### High Baseline and Delta dv Improvement from

2001 – 2003

Class I Area

Arches National Park

Bandelier Wilderness Area
Black Canyon of the Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes National

Monument

La Garita WA

Maroon Bells Snowmass WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Baseline

4.22

3.01

2.80

5.95

3.42

2.16

1.27

1.80

1.14

6.22

2.20

1.63

3.97

2.13

2.90

1.75

46.59 Improvement from

LNB/LNB+OFA

0.72

0.53

0.62

0.93

0.61

0.48

0.31

0.46

0.29

0.54

0.44

0.36

0.76

0.53

0.64

0.41

8.64 Improvement From

LNB+SCR

2.59

1.70

1.89

3.59

1.99

1.37

0.82

1.13

0.75

2.59

1.23

0.93

2.22

1.48

1.90

1.09

27.25



### 5. Visibility Metrics

The FLMs supported our consideration in the ANPRM of the cumulative visibility improvement anticipated at all of the impacted Class I areas. However, the FLMs did not support the alternative visibility metric we introduced in the ANPRM that multiplies the 98 th 

### percentile change at the highest receptor by the land area of the Class I areas because the metric values larger Class I areas more than smaller Class I areas. Instead, NPS and FS discussed alternatives to our area-weighted visibility metrics. FS discussed two different techniques for accounting for visibility impacts over multiple days at multiple Class I areas. The first technique sums the daily maximum receptor deciview impacts, over 365 days, at all Class I areas in the modeling domain to yield a metric in units of $/Class I area dv-day (dollar per Class I area deciview-day). The second technique is similar to the first, but the single daily 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 the 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 estimate 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 ranges

Page 67 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 SCR are overestimated and visibility benefits are underestimated, but acknowledge that there are considerable uncertainties and differences between the approaches used by APS and NPS to derive their cost estimates. To create a “middle-ground” estimate, NPS combined the cost estimates from APS and their own visibility modeling results to calculate cost effectiveness values of $4.9 – 6.6 million per dv. Considering a $17 million 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 benchmark, 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 assumptions 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 ammonia 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 proposal, EPA used the IWAQM default of 1 ppb, and corroboration from modeling using ammonia levels from a back-calculation procedure relying on sulfate and nitratemeasurements at Class I areas. EPA considered various objections to the backcalculation procedure raised by commenters on the ANPRM. EPA also strongly considered the opinions of the FLMs, who generally favored the back-calculation approach. EPA has determined that the 1 ppb default and corroboration from the back-calculation results are a reasonable basis for assessing visibility impacts, in light of the uncertainties involved in estimating ammonia. However, EPA also performed sensitivity modeling using the lower ammonia concentrations originally used by APS in their modeling. Below we describe the approach used, and then address various concerns over the back-calculation procedure.

Based on comments we received on the ANPRM, we reexamined the ammonia background values. For this proposal, EPA used the IWAQM default of 1 ppb, with corroboration from a variant of the back-calculation procedure that was used for the ANRPM, described above. In the back-calculation for this proposal, instead using of the maximum for each month, EPA used the mean plus two standard deviations. (For the normal distribution, this represents the 97.5 th


### percentile.) This remains a conservative estimate, but compared to the maximum

Page 68 of 92

### it is more in line with the BART guidelines principle of avoiding unusual meteorological conditions (the guidelines’ rationale for using the 98 th 

### percentile delta deciviews instead of the maximum), and partly addresses some commenters’ concerns that the method is overly conservative. The 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 all 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 each of the directions northwest, northeast, southeast, southwest, and with the Grand Canyon in a group by itself. Areas that are nearer to each other geographically and have broadly similar ammonia estimates are grouped together, providing a better match to particular areas than the single average over all areas used in the ANPRM. The groups are listed in Table 32 and the ammonia background concentrations are in Table 33. For the northwest areas, the values range from 0.6 to 1.0 ppb; for the northeast the range is 0.4 to 0.8 ppb; for the Grand Canyon and the southeast group the range is 0.5 to 1.1 ppb; and for the southwest 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 background used in this proposal
Grouping IMPROVE monitors
Grand Canyon GRCA2

northwest areas BRCA1, CANY1, CAPI

northeast areas GRSA1, WEMI1, WHPE1, WHRI1 Class I Areas
Grand Canyon
Arches, Bryce Canyon* 88 , Canyonlands, Capitol Reef
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
Mazatzal*, Petrified Forest, Pine Mountain*, Sycamore southwest areas IKBA1, PEFO1, SYCA1 Canyon*

88 Areas denoted with a “*” were not modeled for FCPP, but monitors included in ammonia calculation as nearest to

the areas modeled

Page 69 of 9289 

### Table 33: Ammonia background concentrations in ppb modeled by EPA used in proposal

Ammonia scenario

Am1: IWAQM default

Am2: AECOM values
Am3: EPA average of

max Am4: Mesa Verde only 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5
Am5gc 90 : Grand Canyon only 0.52 0.46 0.63 0.97 1.02 1.12 0.93 0.98

Am5nw: northwest areas

Am5ne: northeast areas

Am5se: southeast areas

Am5sw: southwest areas Jan

1.0

0.2

0.8

0.74

0.43

0.80

0.71 Feb

1.0

0.2

0.7

0.79

0.49

0.66

0.67 Mar

1.0

0.5

0.7

0.56

0.49

0.62

0.76 Apr

1.0

0.5

1.0

0.94

0.75

0.82

1.11 May

1.0

1.0

1.0

0.84

0.70

0.79

1.09 Jun

1.0

1.0

1.3

0.99

0.81

1.14

1.27 Jul

1.0

1.0

1.0

0.91

0.66

0.94

1.05 Aug

1.0

1.0

1.0

0.83

0.66

1.11

1.10 Sep Oct Nov Dec

1.0 1.0 1.0 1.0

1.0 0.5 0.5 0.2

1.0 1.0 1.0 0.9

1.5 1.5 1.3 1.0

0.77 0.82 0.83 0.58

0.65 0.61 0.73 0.90

0.61 0.68 0.59 0.45

1.00 1.01 0.81 0.50

1.05 0.99 1.04 0.61



### EPA could rely solely on the IWAQM default, but believes the backcalculation method is also useful, since it is an objective approach and relies on monitored data at the Class I areas where visibility is being assessed, and has a degree of conservatism. EPA is aware of various limitations inherent to the method, some of which were raised by ANPRM commenters.

Per the ADEQ comment on the ANPRM stated above (in section F.c.), for an alternative to default ammonia levels, the context in the IWAQM Phase 2 document does seem to envisage measurement of ammonia itself, rather than of other compounds that indirectly imply ammonia concentrations via a calculation: “However, given all the uncertainties in ammonia data, IWAQM recommends use of the background levels provided above, unless specific data are available for the modeling domain that would discredit the values cited” 91 

### . For this proposal, EPA is considering visibility impacts estimated using the 1 ppb ammonia default. This is consistent with BART analyses carried out in many other parts of the country. However, EPA continues to believe that the indirect back-calculation method provides a useful estimate that is based on measured 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 vary 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 concentrations or their variation. Expanded ammonia monitoring would be desirable, but the BART guidelines do not envisage the initiation of a new monitoring program as necessary for BART determinations; that would be a much larger undertaking than the analysis procedures described in the guidelines. Other than the IWAQM default

89 Am3 is the average over all areas of the maximum calculated 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 calculated ammonia.

91 IWAQM Phase 2 document, section 2.2.2, p.14

92 IWAQM Phase 2 document, section 2.2.2, pp.14-15

Page 70 of 92

### supplemented by available measurements, there is not an accepted method for estimating ammonia for use in CALPUFF visibility modeling. In addition, even if such data were available, CALPUFF accepts only a single ammonia value for each modeled month for the whole modeling domain, so it uses little temporal variation, and no spatial variation. There are substantial 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 measurement, but rather an indirect estimate based on integrated 24-hour sulfate and nitrate 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 underestimate the total ammonia available to interact with the source plume. (Conversely, 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 total ammonia available, another aspect of the method is that it assumes that all of that ammonia is available to interact with emissions from the single 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 appropriate for assessing the actual impact of FCPP in the real atmosphere as part of a source apportionment; in that case it might be considered “double counting”, since the calculated

ammonia includes ammonium from FCPP itself as well as from other sources. But for BART modeling it is acceptable. The assumption that all the ammonia is available to FCPP emissions is comparable to assuming that there are no competing sources, similar to natural background conditions. EPA believes that the back-calculation method is in accord with the BART guidelines’ recommendation to assess visibility impacts relative to natural conditions.

The above-mentioned 24-hour integration aspect of the back-calculation method is desirable in that concentrations in the source plume when it arrives at the Class I area are the cumulative (integrated) result of conditions the plume has encountered on the way. The IMPROVE concentrations reflect ammonium particulate formation that resulted from various gaseous ammonia concentrations

Page 71 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 integration is that for different hours within a given day, the sulfate and nitrate at the IMPROVE monitor may have arrived via different routes. Some 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 interact with the source plume. The same issue arises considering different days: some days’ transport routes tothe monitor will have little relevance for the source plume, yet their backcalculated ammonia is assumed to be available for that 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 these issues. First, other things being equal, these other transport routes would be just as likely to encounter below-average ammonia concentrations as to encounter above-average ammonia. The various contributions to an IMPROVE monitor within a day and over multiple days tend to balance each other in the overall distribution of calculated ammonia values, especially since averages over several monitors are used. Second, this potential source of inaccuracy is lessened by considering multiple years of data; in the aggregate the range of ammonia 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 assess the net effect of these potential problems would require a much more complex analysis than envisaged under the BART guidelines, involving modeling of multiple sources, the development of an ammonia inventory, and a model with 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 IMPROVE monitors, since it is based on actual measured data, is easily computed, and on many days would be expected to represent ammonia concentrations encountered by the source’s plume. It appears to be conservative, while remaining realistic. Some conservatism is warranted given the BART guidelines’ emphasis on the 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 gaseous and particulate forms, it could be argued that for nitrate the spatial integration over the plume path is less relevant than conditions in the immediate vicinity of the Class I area. By this argument, for nitrate the 24-hour values could be considered as more of a temporal integration of conditions at the area, which is still desirable for estimating 24-hour visibility with CALPUFF.

94 Christopher M. B. Lehmann et al. , “Monitoring Long-term Trends in Sulfate and Ammonium in US Precipitation: Results from the National Atmospheric Deposition Program / National Trends Network”, Water, Air, & Soil
Pollution: Focus, Volume 7, Numbers 1-3, March, 2007, DOI:10.1007/s11267-006-9100-z

Page 72 of 92

### As a rough check on the appropriateness of the back-calculated ammonia background concentration estimates, EPA compared CALPUFF predictions of nitrate impacts from FCPP to nitrate measurements at 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 predicted nitrate will exceed the nitrate measured at the IMPROVE monitors. Given the uncertainty in the method, some over-prediction is acceptable, but consistently large over-predictions would be grounds for concern. The comparison was made for seven Class I areas in various directions from FCPP: Canyonlands, Capitol Reef, Grand 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 generated for each. Statistical and graphical comparisons were made between these predictions and the

IMPROVE monitor measurements.

EPA found that there are many days for which the FCPP nitrate impact is far underpredicted, especially for Canyonlands, Capitol Reef, Grand Canyon, and San Pedro Parks. This is to be expected, since under some conditions and wind directions the FCPP plume will have little effect on 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 nitrate impact days with substantial overprediction. However, for all the areas, the predicted highs were comparable to the measured highs, based on the maximum, the 98th 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 for the 98th percentile at Mesa Verde and San Pedro Parks. Even for these areas, the predicted maxima were close to the measured values. For the am1 scenario, the 98th percentile of predicted nitrate impacts varied between 21% and 146% of the 98th percentile of the IMPROVE measurement, depending on area. The predicted 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 model 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 systematic overprediction of nitrate highs using either of the ammonia background scenarios considered by EPA.

2. Revised Emission Inputs for CALPUFF Modeling

For this proposal, we remodeled the anticipated visibility improvement

from the use of LNB/LNB+OFA or SCR on Units 1 – 5 for NO

x 

### control and PM controls on Units 1 – 3. The emission inputs we used 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 73 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

SO 2 522.54

SO 4 1.51

NO

x 2020.14

SOA 9.40

PM fine 38.07

PM coarse 15.50

EC 1.46 Unit 2

615.12

1.51

1599.47

9.41

57.76

23.52

2.22 Unit 3

1042.09

1.95

1970.80

12.13

59.56

24.26

2.29

1042.09

1.40

1970.80

12.13

23.60

18.03

0.91

Unit 3

1042.09

1.95

1103.65

12.13

59.56

24.26

2.29

1042.09

11.06

394.16

12.13

59.56

24.26

2.29 Unit 4 Unit 5

2026.10 2131.85

0.37 0.37

5015.98 4508.56

32.00 32.20

100.93 48.02

77.12 36.69

3.88 1.85

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

2026.10 2131.85

0.37 0.37

5015.98 4508.56

32.00 32.20

100.93 48.02

77.12 36.69

3.88 1.85

Unit 4 Unit 5

2026.10 2131.85

0.37 0.37

3561.35 3201.08

32.00 32.20

100.93 48.02

77.12 36.69

3.88 1.85

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5

2026.10 2131.85

2.24 2.25

1003.20 901.71

32.00 32.20

100.93 48.02

77.12 36.69

3.88 1.85 Scenario FC1e – PM control on Units 1 - 3

SO 2 522.54

SO 4 1.09

NO

x 2020.14

SOA 9.40

PM fine 17.26

PM coarse 13.19

EC 0.66

Scenario FC2e – LNB + OFA on Units 1 – 5

Unit 1

SO 2 522.54

SO 4 1.51

NO

x 1109.06

SOA 9.40

PM fine 38.07

PM coarse 15.50

EC 1.46

Scenario FC3e – SCR on Units 1 – 5

SO 2 522.54

SO 4 8.57

NO

x 404.03

SOA 9.40

PM fine 38.07

PM coarse 15.50

EC 1.46 615.12

1.09

1599.47

9.41

20.39

15.58

0.78

Unit 2

615.12

1.51

1073.25

9.41

57.76

23.52

2.22

615.12

8.58

319.89

9.41

57.76

23.52

2.22



### 3. Baseline Visibility Impacts of FCPP

Modeled impacts on the Class I areas of FCPP without additional controls for each ammonia scenario are shown in Table 35: EPA Modeling Results – 8 th


### High Delta dv Baseline from 2001 – 2003 for the Different Ammonia Background

Page 74 of 92

### Scenarios. The table shows the 98 th 

### percentile delta deciview impacts, considering days from all three modeled years together (rather than separate 98 th


### percentiles for each of the modeled years as was done by APS). Impacts depend strongly on the background ammonia assumed, increasing 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/AECOM 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, which 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 conditions can be more or less favorable for transport to Class I areas in particular directions. Mesa Verde is the closest area and has clearly the highest impact, while 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 northwestern areas of Arches, Canyonlands, and Capitol Reef have impacts a bit high for their distance, while Weminuche impacts are a bit low for its distance.

For all areas and ammonia scenarios, the modeled impact of FCPP without additional controls exceeds 1 deciview (except for Maroon Bells Snowmass in Am2), confirming that FCPP causes visibility impairment 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 concentrations

derived from ammonia measurements rather than the back-calculation method.

Page 75 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 Background Scenarios

Class I Area

Arches National Park

Bandelier Wilderness Area
Black Canyon of the Gunnison

WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass WA

Mesa Verde NP 97

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Am1

4.11

2.90

2.36

5.24

3.23

1.63

1.16

1.72

1.04

5.95

2.16

1.40

3.88

1.87

2.76

1.53

42.94 Am2

1.96

1.74

1.54

2.29

1.83

1.06

0.96

1.39

0.83

3.16

1.58

1.16

2.24

1.19

1.98

1.18

26.09 Baseline Impacts

Am3 Am5

4.01 3.95

2.86 2.76

2.29 1.92

4.68 4.84

3.17 3.14

1.62 1.42

1.15 1.08

1.70 1.59

1.02 0.98

6.41 6.41

2.07 1.90

1.40 1.39

3.67 3.51

1.85 1.69

2.75 2.37

1.49 1.37

42.14 40.32



### 4. New Results of Anticipated Visibility Improvement

For assessing visibility improvement for this proposals, EPA relied primarily on the ammonia scenario with the IWAQM 1 ppb default (Am1), corroborated by scenario with the back-calculated mean plus two standard deviations (Am5), with the other scenarios considered as sensitivity analyses. Also, EPA mainly considered improvement in delta deciviews relative to the baseline, with additional consideration of its percent improvement. The delta dv improvement and percent change for each ammonia background scenario are

shown in Tables 36 – 39.

Summarizing results from the tables, the visibility 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 absolute deciview improvements for Am2 are only about half of those for the other scenarios, ranging from 0.12 dv to 0.36 dv for LNB, and 0.38 dv 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 considered to be perceptible and to “contribute” to visibility impairment under the BART guidelines (p. 39120).

97 Ammonia background values for Mesa Verde under columns “Am3” and “Am5” are based on scenario Am4. This applies to all tables of modeling results.

Page 76 of 92

### So, even for the lowest ammonia scenario, APR’s Am2, the visibility improvement from SCR is significant, especially considering that 14 Class I areas would experience that improvement. By contrast, improvements from LNB are

all below the 0.5 dv level.

For the other ammonia scenarios visibility improvements 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, with 10 of 16 areas experiencing more than a 0.5 dv improvement, but with 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 improvement. Thus both LNB and SCR result in visibility improvements above the “contribute 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 LNB, and mostly above the BART Guidelines “cause impairment” level of 1.0 dv; these changes would be definitely noticeable by most observers at the Class I areas.

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

Despite uncertainty over background ammonia concentrations, several conclusions can be drawn. There would be a visibility 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 for the other ammonia

scenarios.

98 Even though that improvement would not be perceptible in itself, it is still worth considering as part of the overall regional haze planning process, since it would occur cumulatively with improvements due to controls on other

sources.

Page 77 of 92

### Table 36: EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am1 Ammonia Background Scenario

Class I Area

Arches National Park

Bandelier Wilderness

Area
Black Canyon of the

Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass

WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Delta dv or Average % Change in

Delta dv Distance

to FCPP

kilometers

245

216

217

214

283

345

279

202

294

62

258

224

160

137

245

265 Baseline Impact

Delta dv

4.11

2.90

2.36

5.24

3.23

1.63

1.16

1.72

1.04

5.95

2.16

1.40

3.88

1.87

2.76

1.53

42.94 Improvement From

PM Control

Delta dv

0.01

0.01

0

0.02

0.01

0.01

0

0

0

0.02

0.01

0.01

0.02

0

0

0.01

0.13 %

0

0

0

0

0

0

0

0

0

1

0

0

1

0

0

0

0 Improvement From Improvement From

LNB/LNB+OFA SCR

Delta dv

0.87

0.54

0.46

0.79

0.77

0.34

0.31

0.44

0.27

0.62

0.52

0.27

0.68

0.49

0.65

0.37

8.39 % Delta dv %

18 2.40 55

21 1.62 57

23 1.42 60

16 2.81 51

18 1.87 52

20 0.88 55

25 0.67 62

25 1.05 62

26 0.64 63

13 2.43 45

23 1.15 58

21 0.65 56

19 2.02 53

25 1.19 62

23 1.70 60

24 0.84 59

21 23.34 57

Page 78 of 92

### Table 37: EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am2 Ammonia Background Scenario

Class I Area

Arches National Park

Bandelier Wilderness

Area
Black Canyon of the

Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass

WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Delta dv or Average % Change in

Delta dv Distance

to FCPP

kilometers

245

216

217

214

283

345

279

202

294

62

258

224

160

137

245

265 Baseline Impact

Delta dv

1.96

1.74

1.54

2.29

1.83

1.06

0.96

1.39

0.83

3.16

1.58

1.16

2.24

1.19

1.98

1.18

26.09 Improvement From

PM Control

Delta dv

0.01

0.01

0.01

0.02

0.01

0

0

0

0

0.05

0.01

0

0.02

0

0.01

0

0.15 %

1

1

0

1

1

1

0

0

0

1

1

1

1

0

1

0

1 Improvement From Improvement From

LNB/LNB+OFA SCR

Delta dv

0.20

0.20

0.28

0.22

0.25

0.13

0.24

0.29

0.17

0.12

0.26

0.20

0.28

0.19

0.36

0.19

3.58 % Delta dv %

10 0.63 33

14 0.66 40

16 0.72 46

8 0.64 27

11 0.62 32

12 0.38 33

22 0.48 57

20 0.73 55

20 0.43 54

7 0.54 25

16 0.63 45

13 0.46 39

11 0.72 35

18 0.55 51

17 0.98 49

18 0.50 50

15 9.67 42

Page 79 of 92

### Table 38: EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am3 Ammonia Background Scenario

Class I Area

Arches National Park

Bandelier Wilderness

Area
Black Canyon of the

Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass

WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Delta dv or Average % Change in

Delta dv Distance to

FCPP

kilometers

245

216

217

214

283

345

279

202

294

62

258

224

160

137

245

265 Baseline Impact

Delta dv

4.01

2.86

2.29

4.68

3.17

1.62

1.15

1.70

1.02

6.41

2.07

1.40

3.67

1.85

2.75

1.49

42.14 Improvement From

PM Control

Delta dv

0.01

0.03

0.01

0.02

0.01

0.01

0

0

0

0.02

0

0.01

0.02

0

0

0

0.14 %

0

0

0

0

0

0

0

0

0

1

0

0

1

0

0

0

0 Improvement From Improvement

LNB/LNB+OFA From SCR

Delta dv

0.78

0.64

0.61

0.54

0.77

0.40

030

0.44

0.28

1.00

0.46

0.29

0.55

0.48

0.64

0.35

8.53 % Delta dv %

17 2.35 53

20 1.61 55

22 1.37 59

15 2.28 49

18 1.82 50

19 0.87 53

24 0.66 61

24 1.03 61

25 0.61 62

14 2.79 46

22 1.06 56

20 0.65 55

18 1.86 51

24 1.17 61

22 1.69 59

23 0.80 58

20 22.62 56

Page 80 of 92

### Table 39: EPA Modeling Results – 8 th 

### High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Am5 Ammonia Background Scenario

Class I Area

Arches National Park

Bandelier Wilderness

Area
Black Canyon of the

Gunnison WA
Canyonlands NP
Capitol Reef NP
Grand Canyon NP

Great Sand Dunes NM

La Garita WA

Maroon Bells Snowmass

WA

Mesa Verde NP

Pecos WA

Petrified Forest NP

San Pedro Parks WA

Weminuche WA

West Elk WA

Wheeler Peak WA

Total Delta dv or Average % Change in

Delta dv Distance to

FCPP

kilometers

245

216

217

214

283

345

279

202

294

62

258

224

160

137

245

265 Baseline Impact

Delta dv

3.95

2.76

1.92

4.84

3.14

1.42

1.08

1.59

0.98

6.41

1.90

1.39

3.51

1.69

2.37

1.37

40.32 Improvement From

PM Control

Delta dv

0.01

0.01

0.01

0.01

0.01

0

0

0.01

0

0.02

0.02

0

0.02

0.01

0.01

0

0.14 %

0

0

0

0

0

0

0

0

0

1

0

0

1

0

0

0

0 Improvement From Improvement From

LNB/LNB+OFA SCR

Delta dv

0.85

0.58

0.40

0.70

0.75

0.35

0.25

0.37

0.26

1.00

0.40

0.29

0.58

0.39

0.45

0.28

7.90 % Delta dv %

17 2.25 53

19 1.51 53

19 1.02 53

15 2.46 49

17 1.78 50

16 0.68 48

23 0.60 59

23 0.93 59

23 0.58 59

14 2.79 46

19 0.93 52

19 0.65 53

17 1.74 49

21 1.03 58

19 1.37 55

21 0.70 55

19 21.02 53



### The modeled visibility improvement resulting from additional 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 contributed to significant visibility impairment in the area around the facility. Region IX staff and community members have seen a visible secondary plume that appears to be formed in the steam plume that is almost always present from these stacks. We have observed this plume as far as Aztec and Bloomfield en route from Farmington from Albuquerque, New Mexico. This yellowish visible plume often 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 Units 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 scrubbers, may be caused by the venturi scrubber’s poor control 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 droplets. These NO 2 

### absorbed

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### droplets do not evaporate as readily as the water droplets and persist in droplet form to scatter and absorb light, thus resulting in visibility impairment. Although CALPUFF is the most appropriate modeling tool for assessing visibility impacts, CALPUFF does not include algorithms for secondary plume 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 specifically seeking information on this “secondary visible plume”, its frequency and persistence, and whether or not it impacts or can be observed from any Class 1 area. EPA is also seeking information as to whether this plume has been observed from Units 4 and

5. EPA has not observed the secondary plume from Units 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 synthesize these factors and reach an overall proposed determination of BART.

A. FCPP Approach to This Factor

In the summary of their BART analysis, which included 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 are based on the installation of LNB on Units 1 and 2 and LNB + OFA on Units 3 – 5 (Option 1). APS explained that Option 1 was most cost effective because of the lowest annualized 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 determined that SCR (Option 3) was not cost effective because of low average visibility improvement, high costs, and increased risk to the local community due to the transportation and storage 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 current 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 in 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 boiler type and coal type (bituminous,

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### 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 for bituminous coal fired in dry wall-fired boilers – 0.39 lb/MMBtu (Unit 3) and cell burner boilers – 0.40 lb/MMBtu (Units 4 and 5); therefore, APS contends LNB + OFA on Units 3 – 5 represents the Best Available Retrofit Technology.

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



### , however, FCPP asserts that their coal has more characteristics of bituminous coal than sub-bituminous coal, and should be classified as bituminous. Based on this categorization, FCPP cites the presumptive limit for NO

x 

### for bituminous coal of 0.39 lb/MMBtu from a dry-bottom wall fired boiler as their 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 controls 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 obtain 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 limit of 0.23 lb/MMBtu than the bituminous limit in order for the retrofit on those units to be considered effectively meeting presumptive.

B. Affected State, Tribe, and FLM Consultation

In their comment letter on the ANPRM, CDPHE supported 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 FCPP 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 Navajo Nation, providing jobs to over 300 Navajo tribal members, and is a major source 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 of 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 allow 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, March 11, 2008 by Alan Papp.

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

The National Park Service concluded in their comment letter on our ANPRM that

SCR to control NO

x 

### emissions at FCPP is technically feasible, cost effective, and will substantially improve visibility in the impacted Class 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 / dv.

C. EPA Conclusions regarding This Factor

1. BART Guidelines

In making a BART determination for the Regional Haze Rule, the BART Guidelines allow states to determine that an alternative level of control, beyond presumptive limits, may be appropriate based on careful consideration of the statutory factors. See 70 FR 39171. APS provided information to reclassify their coal as bituminous, which would allow Unit 3 to meet the presumptive limit for

NO

x 

### with LNB + OFA. Their coal, as previously classified, would have been subject to the lower subbituminous presumptive limit 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 emissions from Units 4 and 5 are

0.49 lb/MMBtu, both the bituminous and sub-bituminous presumptive limits provide negligible reductions of NO

x 

### emissions from these units.

The presumptive limits are not binding requirements for BART, rather they are included in the BART guidelines as limits that most EGUs can meet through the use of current combustion control technologies. However, the BART guidelines further state that the reviewing authority may determine that an alternative control level is appropriate based on the careful consideration of the statutory factors. Because EPA is proposing to make this BART determination based upon our careful examination of the five factors rather than relying on the general presumptions set forth in the BART Guidelines, we have determined it unnecessary for purposes of this regulation to determine 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 costs in determining BART, EPA is assigning more weight to the cost effectiveness and the anticipated visibility improvements from controls, rather than overall capital costs.

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### 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-factor 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 the 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 technically feasible to significant emission reductions which would constitute 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 cost estimates and made several revisions to assumptions based on guidelines in the EPA Control Cost

Manual to generate cost projections that are more reasonable and consistent with the BART guidelines. EPA estimated cost effectiveness of less than $3,000 per

ton to install SCR on each of five units.

The third factor involves consideration of the energy 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 understands 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 royalties and taxes paid by these two entities. Based on an economic analysis of the increase in electricity generation costs of SCR compared to the estimated cost to purchase electricity on the wholesale market, FCPP is expected to remain competitive relative to the wholesale market, suggesting 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 than just the generation costs of power. Retail rates include the cost to transmit 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 portfolio of APS generation assets and purchases power contracts, which 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 resulting from SCR on FCPP to be significantly lower than 22%.

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### As described in comments on the ANPRM, numerous other 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 with these upcoming regulations and the complexity in determining the appropriate level of risk for each owner, EPA has determined that our proposed BART determination cannot rely on conjectures on the future decisions of FCPP owners. Without firm intentions and commitments to change operations, EPA is only relying on the results of the economic model for SCR in our analysis, which suggests that SCR will not cause 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 1980­ 1990’s and for PM control, venturi scrubbers on Units 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 difficulties 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 life of the facility.Although commenters have cited the age of FCPP and impending lease and rightof-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 appropriate to use as the remaining useful life of the facility. Without commitments for an early shut down, EPA cannot consider a shorter amortization period in our analysis.

The final factor examines the visibility improvement resulting from controls. The anticipated visibility benefits were modeled using CALPUFF with a 1 ppb ammonia background. Background ammonia concentrations assumed in the model are an important component of the visibility impacts model. Based on modeling results from four different ammonia background 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 improvement. All ammonia background scenarios result in perceptible improvements in visibility at the most impacted Class I areas.

3. EPA’s Proposed BART Determination

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### 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 Table 40). SCR using an ultra low SO 2 

### to SO 3 

### conversion catalyst can readily achieve cost effective emissions reductions that provide a significant 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 NO

x 

### in the country. The modeled visibility improvement from LNB/LNB+OFA only results in perceptible visibility improvement in only half of 16 Class I areas impacted 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 baseline 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 on all five units, however, APS may choose to use alternative technologies to achieve 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 sulfuric 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 significant 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 other 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 comments that stringent controls at FCPP are not warranted because 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 the total NO

x 

### emissions into the atmosphere. Therefore, EPA believes that total annual emissions are more

relevant than NO

x 

### emissions on a heat input basis to describe the impacts 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 FCPP when weighing the cost of controls against the anticipated NO

x 

### reductions from their recommended

100 http://camddataandmaps.epa.gov/gdm/

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### control options. EPA has determined that LNB and LNB+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 rates were achievable, the NO

x 

### emission rates proposed by FCPP as BART are too high considering the five BART factors in the context of FCPP’s status as among 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 units (Units 1 – 3) at FCPP has contributed to significant visibility impairment in the area around the facility. Region IX staff and community members have 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 often 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 Units 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 scrubbers, may be caused by the venturi scrubber’s poor control of ultrafine submicron 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 droplets. These NO 2 

### absorbed droplets do not evaporate as readily as the water droplets and persist in droplet form to scatter and absorb light, thus resulting in visibility impairment. Although CALPUFF is the most appropriate modeling tool for assessing visibility impacts, CALPUFF does not include algorithms for secondary plume 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 Units 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 option presented by APS. Thisdevice is very reasonably priced in comparison to the typical modern day BACTcontrolled coal-fired EGUs, however because wet ESPs would be placed downstream of the existing venturi scrubbers, the incremental 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 whether 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 demonstrate 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 Protection Agency, August 1, 2008. See:

http://www.navajonationepa.org/airqty/Pdf_files/FCPPpermit8-1-2008.pdf

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### emissions not to exceed 0.050 lb/MMBtu. Because PM emissions during source tests on Units 4 and 5 have achieved as low as 0.012 lb/MMBtu, EPA is proposing to find that it is appropriate at this time to reduce the PM emission limits on Units 4 and 5. EPA is proposing a BART limit for PM of 0.015 lb/MMBtu and 10% opacity, with compliance demonstrated by annual PM source tests using EPA Method 5.

Although PM BART reductions are not modeled to have a significant impact on visibility improvement, consideration of the other four factors, in particular, the fact that the existing venturi scrubber 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 satisfy BART. PM emission limits for the boilers will bring the allowable emissions to the levels achieved by some of the best technology that is available for coal-fired power plants. The reduced PM emission limits for Units 4 and 5 reflect the PM emissions that can easily be achieved and maintained at coal-fired electric generating units (EGUs) controlled by baghouses.

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### Appendix A:

Mobile Source Risk Estimates for Four Corners Power Plant

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

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### Appendix B:

Economic Analysis of SCR on FCPP

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

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### Appendix C:

Impact of Ammonia in Fly Ash on its Beneficial Use

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

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