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 NOx and PM from FCPP. 

Pursuant to the Tribal Authority Rule, EPA Region IX (EPA) finds that the BART 

requirement for NOx 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-NOx 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 NOx 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 

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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 docket1

. 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 NOx 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 NOx emissions sufficiently that is adequate for BART for a facility that has 

consistently been one of the largest NOx 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 NOx 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 NOx, 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 NOx 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 NOx 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 

NOx (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 NOx and PM represent 

the most appropriate BART determination for FCPP, the largest NOx 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 NOx Emissions from FCPP from 2001 – 2009 11
 

Table 3 Analysis of Available NOx 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 NOx Controls Estimated by B&V 21
 

Table 6 NOx Emission Rates and Percent Reductions Estimated by B&V 22
 

Table 7 NOx 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 NOx and PM 34
 

Table 18 Summary of Cost Comparisons for NOx Control versus Market Trends 37
 

Table 19 Summary of Cost Comparisons for NOx 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 H2SO4 Emission Estimates 54
 

Table 27 Ammonia Background Concentration in ppb 54
 

Table 28 Impacts of FCPP on Visibility (98th Percentile of daily maximum dv) at 55
 

Table 29 Assumptions used in Sulfuric Acid (H2SO4) Emissions Calculations 59
 

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

Table 31 NPS Modeling Results – Average 8th 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 – 8th High Delta dv Baseline from 2001 – 2003 for 76 

the Different Ammonia Background Scenarios 

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

H2SO4 Sulfuric Acid 

LNB Low NOx Burners 

NAAQS National Ambient Air Quality Standards 

NH3 Ammonia 

NOx 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 

SO2 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 

NOx Baseline 

emission rate2 0.48 

(lb/MMBtu) 

PM Baseline 

emission rate3 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 NOx emitters (in terms of tons of NOx 

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 NOx on the Navajo Nation and in the Western United States. From 2004 – 

2006 and in 2009, FCPP was the largest source of NOx in the United States. 

Table 2: Facility-wide NOx Emissions from FCPP from 2001 – 2009 

NOx Ranking Year NOx emissions (tons) Heat Input (MMBtu) NOx (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 (SO2), oxides of nitrogen (NOx), and particulate matter (PM) as 

visibility impairing pollutants. The significance thresholds for SO2 and NOx are each 40 

tpy, the significance thresholds for PM, PM10, and PM2.5 are 25, 15, and 10 tpy, 

respectively. Emissions of SO2, NOx, PM, PM10, and PM2.5 from FCPP exceed those 

significance thresholds. EPA has determined that it is necessary or appropriate to address 

emissions of NOx and particulate matter, but not SO2, 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 SO2, from 72% to 88% control, and to federalize emissions limitations 

which FCPP has historically followed for NOx, PM, opacity, and control measures for 

dust. Thus, the 2007 FIP did not require emissions reductions in the context of BART for 

NOx and PM. NOx 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 SO2 control federalized in the 

FIP, EPA determined that the 88% SO2 control was “close to or equivalent” to BART. 

This would decrease SO2 emissions 57% from historical levels, resulting in a reduction of 

approximately 22,000 tons per year. These SO2 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 SO2 has been reduced by 88%, and the reductions were made federally 

enforceable in 2007, EPA has determined SO2 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 considered4 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 organizations5 

(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 NOx. Generally, NOx control techniques utilize 1) 

combustion control to reduce the production of NOx from fuel-bound nitrogen and high 

temperature combustion, 2) post-combustion add-on control to reduce the amount of NOx 

emitted in flue gas by converting NOx to N2, 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 NOx 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 NOx 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. 

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Table 3: Analysis of Available NOx Control Options for FCPP Presented by B&V for APS 

NOx 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 NOx to N2. 

LoTOx Oxidation of NOx with ozone to form nitrogen pentoxide No, no large operation units 70 – 95%7 

(N2O5), which is scrubbed by the wet flue gas with this technology. 

desulfurization (FGD) unit. 

THERMALONOx 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 LoTOx, the ozone or size facilities. 

oxidizes NOx to N2O5 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 NOx 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 NOx 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 NOx emissions. No, not currently in similar type 65% when 

A reburn zone, fired with natural gas burners, reduces NOx 

to N2 by stripping oxygen from NOx to convert CO to CO2. 

or size facilities. combined 

with LNB11 

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 NOx 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 NOx 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 NOx to N2. units. 

Selective Ammonia or urea injection without use of a catalyst to Yes 30 – 50%14 

Noncatalytic reduce NOx to N2. 

Reduction (SNCR) 

Low NOx 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 NOx 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. 

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(LNB) and fuel flow to create fuel-rich/O2-poor conditions in the
 

burner and high temperature zones. Reduces the formation
 

of fuel NOx.
 

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.
 

NOxStar and NOxStar is a trademark name for the injection of ammonia No, not currently marketed, but Not known17 

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

ammonia reduces NOx to N2, 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 N2. 

SNCR with lower NH3 slip. 

No, not currently in similar type 

or size facilities. 

Biotechnological Not known 

Denitrification 

(BioDeNOx) 

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.
 

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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 NOx 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 

NOx 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 

NOx 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 NOx through burner retrofit technology. Based on the inherent 

18 http://www.gepower.com/prod_serv/products/particulate_matter/en/max9/index.htm 

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design of Units 1 – 5, we stated in our ANPRM that LNB retrofit of these units would 

provide only limited NOx control, and we requested comment on this determination. 

APS submitted two different reports concerning the potential for NOx reductions 

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

of Potential for Further NOx 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 NOx 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 NOx 

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 NOx 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 NOx 

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 NOx 

control needed for BART for one of the nation’s largest NOx sources, located on the 

Colorado Plateau and affecting visibility at sixteen Class I areas. 

C. Affected State, Tribe, and FLM Consultation 

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We did not receive comments from affected States or Tribes on additional NOx or 

PM 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 H2SO4 formed from SO2 to SO3 conversion 

on the SCR catalyst. For example baghouses are expected to provide 90% control of 

H2SO4 and the wet FGD is expected to provide 53% control of H2SO4 (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 

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

the available NOx 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 NOx control than SCR, EPA used 

available estimates of NOx 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 NOx 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 NOx control needed for BART for one of the 

nation’s largest NOx sources and we start our five-factor evaluation with SCR (without 

combustion controls). However, although EPA has determined that LNB and LNB+OFA 

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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) program19, 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 materials20 (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.
 

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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 estimates 

where 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 NOx emission rates and % NOx 

reductions are shown in Table 6 and the total estimated NOx reductions (in tons per year) 

and cost effectiveness are shown in Table 7. 

Table 5: Projected Costs (dated August 2008) for NOx Control Estimated by B&V 

NOx Control Total Capital and Annual Costs21 

SCR Total Capital Investment22 

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.
 

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Table 6: NOx Emission Rates and Percent Reductions Estimated by B&V 

NOx Control (#) Emission Rates and % Reductions24 

Baseline Emission (lb/MMBtu) 

SCR Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

ROTAMIX + Expected Emission rate (lb/MMBtu) 

ROFA % NOx reduction from baseline 

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

HERT % NOx reduction from baseline 

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

OFA % NOx reduction from baseline 

ROFA Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

ROTAMIX + LNB Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

SNCR + LNB Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

LNB + OFA Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

LNB Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

ROTAMIX Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

SNCR Expected Emission rate (lb/MMBtu) 

% NOx reduction from baseline 

COS Expected Emission rate (lb/MMBtu) 

% NOx 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. 

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Table 7: NOx Reductions and Cost Effectiveness of Controls Estimated by B&V 

NOx Control Unit 1 

TPY NOx 

reduced 

SCR 5,13427 

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 NOx 

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 NOx 

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 NOx 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.
 

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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 NOx controls of 

approximately 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 NOx 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 

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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 $59,594,00029 $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 Boardman32
 

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 234, 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. 

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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 Nation37 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. 

NPS38 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 NOx 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.
 

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

Manual reported in their comments on ANPRM39 

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 

document40 . 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”.
 

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Table 13: Summary of EPA Revisions to B&V Cost Inputs for SCR on Unit 441 

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/m3 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 docket42 . 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 NOx Compliance Report, Revision D. Black and Veatch
 

Corporation, Project Number 166861, February, 2010.
 

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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 

$223,782,00043 

$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 NOx by SCR. The 80% reduction is the minimum 

reduction expected from SCR, estimated by Hitachi Power Systems America44 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 

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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 power 

plants (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. 

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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/ton45 . With these upstream controls, APS could optimize 

the venturi scrubber for SO2 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”. 

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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 NOx controls 

and from the ESP and baghouse options for PM control. See Table 17. 

Table 17: Increase in Electricity Generation Costs ($/kWh) from NOx 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 NOx emissions on 

ambient ozone concentrations, and NPS cited additional benefits of reduced nitrogen 

deposition resulting from more stringent NOx controls. 

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

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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 River47 . 

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 H2SO4 at existing major stationary sources as a result of 

the application of SCR for NOx control will trigger PSD permitting requirements, 

including the application of BACT, if they exceed the H2SO4 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 H2SO4. 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 H2SO4 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, SO3 emissions will have 

already formed H2SO4 droplets. The wet membrane ESPs can have very good collection 

efficiency for any H2SO4 droplets that penetrate the venturi scrubber. H2SO4 can also be 

minimized with the use of a low SO2 to SO3 conversion SCR catalyst or additional 

control technologies such as adsorbent injection to collect the SO3/ H2SO4 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 modeled 

concentrations 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 NOx 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 NOx 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 

NOx 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 scrubbers48 . 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 proposal49 . 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 NOx 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 NOx 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-201650. 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 NOx 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 NOx, 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 NOx 

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 NOx control already 

meets BART. 

Units 1 – 3 currently use venturi scrubbers to control PM and SO2 emissions, with 

a PM control efficiency of 98%, with less control of PM10 and PM2.5, and an SO2 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 

SO2, respectively. Expected control efficiency for the baghouses is 99.9+% and the SO2 

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 Equipment51 at FCPP 

Unit 1 Unit 2 

Boiler Boiler – LNB (NOx) 

Economizer Economizer 

Air Preheater Air Preheater 

Venturi Scrubber Venturi Scrubber – Venturi Scrubber – 

(PM, SO2) Lime (PM, SO2) Lime (PM, SO2) 

Stack Stack Stack 

Unit 3
 

Boiler – LNB (NOx)
 

Economizer
 

Air Preheater
 

Unit 4 Unit 5 

Boiler – LNB (NOx) Boiler – LNB (NOx) 

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 

(SO2) (SO2) 

Stack Stack 

B. Discussion of this Factor in the ANPRM 

FCPP has had limited success in retrofitting their boilers with LoNOx 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 NOx 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 NOx 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 NOx 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 NOx control, EPA believes that LNB technology will be ineffective in 

reducing NOx 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 venturi 

scrubbers 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 PM10 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 10th and 90th 

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 

10th 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 

90th 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 

Page 44 of 92 
 

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 98th 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(bext / 10), where ln is the natural logarithm, and extinction bext is the 

fraction of light scattered out of a viewing path. Extinction increases with the amount of 

pollution (bext 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: SO2, SO4, 

NOx, 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 SO2 to particulate sulfate and NOx 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 IMPROVE52 equation is used to estimate 

extinction bext from the predicted concentrations of various pollutants: 

bext = 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/ 

Page 46 of 92 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 (Δdv) 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 8th 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 EPA53 . The modeling analysis generally followed the BART protocol 

developed by the Western Regional Air Partnership (WRAP), except as noted below54 . 

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 

monitor55 

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 modeling57 

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 

modeling58 

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/m3) 

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 (NH3) and sulfuric acid (H2SO4). 

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 livestock 

operations, fertilizer application associated with farming, and ammonia slip (or unreacted ammonia) from its use in SCR or SNCR to control NOx 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 (SO4) 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. 

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Sulfuric acid (H2SO4) is formed from coal-fired power plants from the oxidation 

of sulfur dioxide (SO2) to sulfur trioxide (SO3) and the subsequent reaction of SO3 with 

water vapor (SO3 + H2O = H2SO4). 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 H2SO4 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 

H2SO4 produced and the amount of H2SO4 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 SO2, the amount of SO2 

oxidized to SO3, and the amount of H2SO4 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 H2SO4 emissions from FCPP were available, it is not 

possible to know the individual production and loss terms for H2SO4 in the system unless 

a detailed measurement program of H2SO4 up and downstream of the various ductwork 

components were conducted as well. Therefore, baseline and post-SCR estimates of 

H2SO4 from FCPP are based on the best current information available from EPRI62 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.
 

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FC2a = Visibility Impacts from LNB+OFA for NOx 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 NOx 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 

SO2 464.17 

SO4 3.35 

NOx 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 

SO2 464.17 

SO4 0.34 

NOx 1,841.37 

SOA 8.35 

PM fine 15.34 

PM coarse 11.72 

EC 0.59 

Unit 1 

SO2 464.17 

SO4 3.35 

NOx 1,010.91 

SOA 8.35 

PM fine 30.74 

PM coarse 12.52 

EC 1.18 

Scenario FC3a – SCR on Units 1 – 5 

SO2 464.17 

SO4 30.71 

NOx 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 

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 -- -- --

 -- -- --

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 H2SO4, which resulted in different SO4 

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 H2SO4 Emission Estimates 

Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

24-hour Maximum Uncontrolled SO2 

emissions (lb/hr) 

Controlled SO2 emissions (lb/hr) 

Conversion of SO2 to H2SO4 via SO3 

due to combustion (%) 

Conversion of SO2 to SO3 due to SCR
 

(%)
 

H2SO4 penetration64 through air
 

preheater
 

H2SO4 penetration through venturi
 

scrubber
 

H2SO4 penetration through baghouse
 

H2SO4 removal by wet spray tower 

3,62963 

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 SO2 = 1.7 lb/MMBtu
 64 Sulfuric Acid removal efficiency = (1 - Penetration ) x 100%
 

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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 (98th 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 SO2 to SO3 

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., SO2 to SO3 oxidation from the SCR catalyst and loss in the 

air preheater. 

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The amount of fuel sulfur that is oxidized to SO2 is estimated for three 

different coal types. Hardman et al. (1998)65 report sulfur conversion to SO2 

(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 SO2 in the flue gas. EPA agrees with 

APS that the ash generated at FCPP has very low available alkalinity66, therefore 

AECOM and EPA both rely on the value of 0.95 for estimating SO2 production 

from fuel sulfur. 

For coal-fired power plants without SCR, SO3 is only formed during the 

combustion process. The amount of SO2 that is oxidized to SO3 during 

combustion depends on coal type and the type of boiler. Measurements of SO3 

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 200567 both report the SO3 production factor from Western bituminous 

coal from dry bottom boilers to be 0.00111, or 0.111% of SO2 production, and 

AECOM and EPA both used this value. 

For coal-fired power plants with SCR, SO3 is also formed as a result of 

oxidation of SO2 to SO3 on the SCR catalyst. As discussed in Section 3 of this 

document, AECOM assumed a 1% conversion of SO2 to SO3 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 H2SO4 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: SO3 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 SO2 to SO3 using 3 layers of CX series catalyst, can be 

achieved while controlling NOx 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 4th layer of catalyst. Therefore, we now use 0.6% SO2 to SO3 

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.
 

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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, H2SO4 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 H2SO4 

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 SO2 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 H2SO4 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 SO2 content results in lower SO3 content, which results 

in a lower dew point for H2SO4, suggesting that less H2SO4 will condense and be 

removed by the air preheater, (2) high actual H2SO4 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 removed69 . 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. 

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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 H2SO4 in the air preheater is generally proportional to 

the flue gas sulfur dioxide (SO2) content”. APS uses this argument to justify their 

assumption that the air preheaters at FCPP will remove 10% of the H2SO4 (0.9 

penetration factor from Harrison 2005 for PRB coal). However, APS’s rationale 

(low SO2 = low H2SO4 removal efficiency) is inconsistent with Figure 3-1 of 

EPRI 2008, which shows that high sulfur Eastern bituminous coal, with high flue 

gas SO2 content, has very low percent H2SO4 removal, suggesting that flue gas 

SO2 content is not the only factor impacting the removal of H2SO4. 

The 2010 EPRI update70 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 H2SO4 from PRB 

coal to provide more than just 10% removal of H2SO4, 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 greater71 , 

we expect FCPP ash to still provide enough bulk alkalinity to provide some 

removal of H2SO4. Formation of SO3 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, H2SO4 is additionally lost to PM and 

SO2 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 SO2 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.
 

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recommended penetration factors of 0.47 through the wet FGD and 0.1 through 

the baghouses. 

Table 29: Assumptions used in Sulfuric acid (H2SO4) Emissions Calculations 

AECOM EPA (ANPRM) EPA (Proposal) 

Fuel Impact Factor (SO3 formation from combustion) 0.00111 0.00111 0.00111 

Coal sulfur content (%) 0.772 0.772 0.772 

Coal S conversion to SO2 0.95 0.95 0.95 

Conversion of SO2 to SO3 from SCR catalyst (%) 1 0.5 0.6 

Penetration factor72 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 document73 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 program75 . 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 (NH4)2SO4 and NH4NO3, so there must be two ammonia molecules 

(NH3) for each sulfate (SO4), and one ammonia for each nitrate (NO3). The 

IMPROVE measurements are in μg/m3 (NH3 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/ 

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CALPUFF ammonia input must be in ppb (NH3 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 assumed76 (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 3rd 

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 monitors77 , 

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, NOx 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 PM79, and provided a detailed 

discussion of our emissions estimates in the ANPRM. EPRI submitted 

comments80 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 particulate 

phase, 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 NOx 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. 

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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 km2

, 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 km2

, so 

this metric gives substantially more weight to improvements there than to the 

Black Canyon of the Gunnison, with an area of only 53 km2

, whereas a simple 

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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 NOx emissions from 

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

Plateau81 . 

81 Stationary Source NOx 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. 

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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 NOx 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. 

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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 method82 . 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 value84 . 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) stated85 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 used86 . 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, FLMs87) 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 

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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 SO2 and NOx 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. 

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Table 31: NPS Modeling Results – Average 8th 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 98th 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 

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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 SO2 to SO3 

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 nitrate 

measurements 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 97.5th 

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

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it is more in line with the BART guidelines principle of avoiding unusual 

meteorological conditions (the guidelines’ rationale for using the 98th 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 

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89 

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 

Am5gc90: 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 sources92 . 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 

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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 (NH4

+

), and not any that is present 

as free gaseous ammonia (NH3). 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, SOx and NOx 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 

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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 to 

the 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 (98th 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 

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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 NOx 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 docket95 . Because the modeling files are in a 

95 See Excel spreadsheet titled “FCPP_BART_Scenarios_Emissions_EPA_proposal.xls”. 

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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 

SO2 522.54 

SO4 1.51 

NOx 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 

SO2 522.54 

SO4 1.09 

NOx 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 

SO2 522.54 

SO4 1.51 

NOx 1109.06 

SOA 9.40 

PM fine 38.07 

PM coarse 15.50 

EC 1.46 

Scenario FC3e – SCR on Units 1 – 5 

SO2 522.54 

SO4 8.57 

NOx 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 – 8th 

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

Page 74 of 92 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Scenarios. The table shows the 98th percentile delta deciview impacts, 

considering days from all three modeled years together (rather than separate 98th 

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) default96 . 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. 

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Table 35: EPA Modeling Results – 8th 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 NP97 

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 – 8th 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 – 8th 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 – 8th 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 – 8th 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 

NO2, which is readily dissolved in the steam plume droplets. These NO2 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 NOx 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 NOx 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 NOx 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 NOx 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-bituminous99 , 

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 NOx 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 NOx 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 NOx, 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 NOx 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 NOx 

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 NOx 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 

NOx 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 NOx 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 NOx 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 

NOx 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 NOx, 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 NOx 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 NOx 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 NOx emissions on all 5 units at FCPP as BART (See Table 40). SCR 

using an ultra low SO2 to SO3 conversion catalyst can readily achieve cost 

effective emissions reductions that provide a significant improvement in visibility. 

EPA determined that presumptive BART for NOx is not appropriate for FCPP 

considering this is one of the largest sources of NOx 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 

NOx (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 NOx per MMBtu on a plant-wide heat inputweighted average, which is an 80% reduction in baseline NOx 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% NOx reductions, 

provided emissions of ammonia and sulfuric acid are not greater than the emission 

rates resulting from SCR using a low SO2 to SO3 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, NOx emissions from FCPP were larger than from any other 

facility in the United States: annual facility-wide NOx emissions from FCPP 

exceed 40,000 tons per year (based on data from the EPA Clean Air Markets 

Division100 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 NOx on a heat input basis (in terms of lb/MMBtu), the visibility 

impacts to nearby Class I areas are dependent on the total NOx emissions into the 

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

relevant than NOx 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 NOx 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 NOx and may cause operability issues 

for the boilers. However, even if those emission rates were achievable, the NOx 

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 NOx 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 

NO2, which is readily dissolved in the steam plume droplets. These NO2 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. This 

device 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 Permit101 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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