Technical Support Document

for the

Proposed Phase 3 Action on the Federal 

Implementation Plan for the Regional Haze

Program in the State of Arizona

Docket No. EPA-R09-OAR-2013-0588

Air Division

U.S. EPA Region 9

January 27, 2013
Page 2 of 133

Authors:

Eugene Chen

Air Permits

(415) 947-4304

chen.eugene@epa.gov

Geoffrey Glass

Air Permits

(415) 972-3498

glass.geoffrey@epa.gov

Shaheerah Kelly

Air Permits

(415) 947-4156

kelly.shaheerah@epa.gov

Scott Bohning

Air Quality Analysis

(415) 947-4127

bohning.scott@epa.gov

Greg Nudd

Air Planning

(415) 947-4107

nudd.gregory@epa.gov

U.S. Environmental Protection Agency – Region 9

75 Hawthorne Street

San Francisco, California 94105
Page 3 of 133

Table of Contents

I. Purpose of this Technical Support Document ............................................................................. 5

II. Visibility Modeling Approach ................................................................................................... 5

II.A. CALMET Meteorological Inputs....................................................................................... 6

II.B. CALPUFF Dispersion Model Inputs.................................................................................. 9

II.B.1. CALPUFF Model Settings .......................................................................................... 9

II.B.2. CALPUFF Input for Facilities................................................................................... 10

II.B.3. CALPUFF Receptors................................................................................................. 11

II.C. POSTUTIL Post-processor Inputs.................................................................................... 11

II.D. CALPOST Post-processor Inputs..................................................................................... 11

II.E. Supplemental modeling by EPA....................................................................................... 15

III. Best Available Retrofit Technology (BART) Analysis.......................................................... 15

III.A. Introduction..................................................................................................................... 15

III.B. Sundt Generating Station Unit 4................................................................................... 16

III.B.1. Summary .................................................................................................................. 16

III.B.2. Facility Description.................................................................................................. 17

III.B.3 General Approach to the Five-Factor BART Analysis............................................. 18

III.B.4 Particulate Matter BART Analysis ........................................................................... 22

III.B.5 NOX BART Analysis ................................................................................................ 23

III.B.6 SO2 BART Analysis.................................................................................................. 31

III.B.7 BART Alternative ..................................................................................................... 39

III.C. Lhoist Nelson Lime Plant................................................................................................ 42

III.C.1. Summary .................................................................................................................. 42

III.C.2. Facility Description.................................................................................................. 43

III.C.3 General Approach to Five-Factor BART Analysis................................................... 44

III.C.4 BART Analysis for NOX........................................................................................... 47

III.C.5 SO2 BART Analysis.................................................................................................. 52

III.C.6 PM BART Analysis .................................................................................................. 58

III.D. ASARCO Smelter........................................................................................................... 59

III.D.1. Summary .................................................................................................................. 59

III.D.2. Facility Description.................................................................................................. 60

III.D.3. General Approach to Five-Factor BART Analysis.................................................. 62
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III.D.4. SO2 BART Analysis................................................................................................. 63

III.D.5. BART Analysis for NOx .......................................................................................... 72

III.E. Freeport McMoRan Smelter............................................................................................ 73

III.E.1. Summary................................................................................................................... 73

III.E.2. Facility Description .................................................................................................. 74

III.E.3. General Approach to Five-Factor Analysis.............................................................. 77

III.E.4. BART Analysis for SO2 ........................................................................................... 78

III.E.5 BART Analysis for NOx............................................................................................ 84

IV. Reasonable Progress Goals and Controls............................................................................... 85

IV.A. Introduction and Background ......................................................................................... 85

IV.B. CalPortland Cement Company Rillito Plant ................................................................... 86

IV.B.1. Summary .................................................................................................................. 86

IV.B.2. Facility Description.................................................................................................. 87

IV.B.3. RP Analysis for NOX ............................................................................................... 90

IV.C. Phoenix Cement............................................................................................................ 100

IV.C.1. Summary ................................................................................................................ 100

IV.C.2. Facility Description................................................................................................ 101

IV.C.3. RP Analysis for NOX ............................................................................................. 103

IV.D. APS Cholla, Unit 1 ....................................................................................................... 111

IV.D.1. Summary................................................................................................................ 111

IV.D.2. Facility Description................................................................................................ 112

IV.D.3. RP Analysis for NOX ............................................................................................. 113

IV.E. TEP Springerville, Units 1-2......................................................................................... 117

IV.E.1. Summary ................................................................................................................ 117

IV.E.2. Facility Description................................................................................................ 118

IV.E.3. RP Analysis for NOX.............................................................................................. 119

IV.F. TEP Sundt, Units 1-3..................................................................................................... 123

IV.F.1. Summary................................................................................................................. 123

IV.F.2. Facility Description ................................................................................................ 124

IV.F.3. RP Analysis for NOX.............................................................................................. 125

IV.G. Area Sources of NOX and SO2...................................................................................... 130

IV.G.1. Source Identification and Emissions Estimates..................................................... 131

IV.G.2. Sources of Control Strategy Information for Identified Area Source Categories.. 133
Page 5 of 133

Technical Support Document (TSD) for the

Proposed Phase 3 Action on the Federal Implementation 

Plan for the Regional Haze Program in the State of Arizona

I. Purpose of this Technical Support Document

This TSD is not intended to be a stand-alone document. It is a compilation of detailed technical

information intended to support EPA’s 2014 proposed action on the Arizona Regional Haze FIP. 

For a comprehensive understanding of EPA’s proposal, it is important to review the proposal in 

the Federal Register and then consult this document for more details.

II. Visibility Modeling Approach

To estimate the degree of visibility improvement expected to result from various BART control 

options, EPA followed the modeling approach recommended in the BART Guidelines. We 

developed a modeling protocol, used maximum daily emissions as a baseline, applied estimated 

percent reductions for alternative control technologies, and used the CALPUFF model to 

estimate visibility impacts at Class I areas within 300 kilometers of each facility. The degree of 

visibility improvement expected to result from a control option is the difference between 

visibility impacts for the baseline, and visibility impacts with the control in operation. Our 

contractor at the University of North Carolina (UNC) carried out most of the modeling and the 

post-processing of model output into tables of visibility impacts. Additional details on this 

modeling may be found in the UNC reports prepared for EPA.1EPA supplemented the UNC 

work for certain sources by modeling of additional control scenarios, corrections to some 

scenarios and post-processing work, and some sensitivity simulations. Also, EPA performed all 

the modeling for the ASARCO Hayden and FMMI Miami smelters. Finally, Lhoist North 

America’s contractor, Trinity Consultants, performed the modeling for the Nelson Lime Plant

Appendix A to this document provides a table that shows the distance from each facility to each 

Class I area modeled within 300 km. The distances are from the facility to the nearest modeling 

receptor in each area. The accompanying map in Appendix A shows the facilities and areas.

A FIP modeling protocol2 was developed by UNC that was based on the Western Regional Air 

Partnership (WRAP) modeling protocol.

3

The WRAP protocol received extensive scrutiny 

 

1

Technical Analysis for Arizona Regional Haze FIPs: Task 7: Five-Factor BART Analysis for Chemical Lime 

Company Nelson, TEP Sundt (Irvington), and Catalyst Paper (Snowflake) Plants, EP-D-07-102 WA5-12 Task 7, 

Institute for the Environment, University of North Carolina at Chapel Hill, October 9, 2012; Technical Analysis for 

Arizona Regional Haze FIPs: Task 9: Five-Factor RP Analyses for TEP Springerville, APS Cholla, TEP Sundt, 

CalPortland Cement and Phoenix Cement Plants, EP-D-07-102 WA5-12 Task 9, Institute for the Environment, 

University of North Carolina at Chapel Hill, October 3, 2012.

2

Technical Analysis for Arizona Regional Haze FIPs: Modeling Protocol for Subject-to-BART and BART Control 

Options Analyses, EP-D-07-102 WA5-12 Task 5, Institute for the Environment, University of North Carolina at 

Chapel Hill, March 14, 2012.

3 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 
Page 6 of 133

during 2005-2006 by various States, EPA Regions, and Federal Land Managers (FLMs). 

However, there are several differences between our protocol and that of the WRAP, in 

meteorological input settings, and in the model version used.

The stack parameters and emissions for facilities modeled by UNC appear in their Task 7 and 

Task 9 reports, cited above and are also in UNC’s master emissions spreadsheets 

“AZ_BART_sources_all-Task7-8_2012-06-10.xls” and “AZ_RP_sources_all-Task9_2012-09-

30.xls”. The stack parameters and emissions for all facilities and scenarios modeled are gathered 

in one place in the spreadsheet CALPUFF_inputs_table.xlsx, which may be found in the docket. 

That spreadsheet uses includes modeling by by EPA, UNC, and Lhoist. It contains input values 

that were extracted from the CALPUFF.INP input files as a check, and includes columns that 

show the percent change between the base case and each control case. It also includes a simpler 

table showing just the stack parameters (latitude and longitude, stack height, stack exit velocity, 

etc.).

Visibility results are provided in tables below in the sections for individual facilities; a 

spreadsheet with more comprehensive visibility results is also cited for each facility. The results 

were extracted by EPA from CALPOST.LST files created by UNC or EPA. UNC provided 

results tables for its modeling in the reports just mentioned, and also in a spreadsheet for each 

facility, available in the docket (their file names end in “dollarperdv_analysis_final”). EPA 

corrected certain errors in the spreadsheets for Sundt and for CalPortland, but those corrections 

are not reflected in the UNC reports. A description of the changes EPA made and the tables in 

the UNC reports affected by them is in the docket in the file “UNC_ dollarperdv

_spreadsheet_corrections.txt”.

The actual model input and output files created by UNC and EPA and are too voluminous to be 

included in the electronic docket, but will be provided upon request.

II.A. CALMET Meteorological Inputs

CALMET is a meteorological pre-processor for CALPUFF. Both the WRAP and the EPA

protocols used meteorological inputs for 2001, 2002, and 2003 based on the Mesoscale Model 

version 5 (MM5) prognostic meteorological fields. However, EPA meteorological inputs differed 

from the WRAP’s in that they used CALMET inputs developed by the AECOM Corporation

(formerly ENSR) for modeling of emissions at the Navajo Generating Station, in consultation 

with EPA and the Federal Land Managers.

4

The meteorological fields incorporated upper air 

data, as recommended by the Federal Land Managers. In addition, 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 and more realistic wind fields than those used for WRAP, which had some abrupt 

changes as one leaves the zone of influence of a given meteorological station. Finally, this work

has more extensive use of meteorological station observations (e.g. IEXTR=-4 to extrapolate 

 

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.

4 Revised BART Analysis for the Navajo Generating Station Units 1-3, ENSR Corporation, Document No. 05830-

012-300, January 2009, Salt River Project – Navajo Generating Station, Tempe, AZ.
Page 7 of 133

surface observations up to higher layers), and thus addresses earlier FLM concerns regarding the 

“no observations” CALMET mode used by the WRAP. Various relevant CALMET option 

settings are listed in Table II.A-1.
Page 8 of 133

Table II.A-1: Selected CALMET settings

Option Description Default WRAP FIP (from 

AECOM)

Comments

version CALMET version 5.8, level 

070623

6.211, level 

060414

5.8, level 

070623

NOOBS No Observation 

Mode

0 0 or 1 

implied

0 Use 0 per FLM recommendation: use 

both surface and upper air 

observations

ICLOUD gridded cloud fields 0 0 0

IWFCOD diagnostic winds 1 1 1

IFRADJ Froude wind adj. 1 1 1

IKINE kinematic effects 0 0 0

IOBR O'Brien vertical wind 

adj.

0 0 0

ISLOPE slope flows 1 1 1

IEXTRP extrapolate wind to 

upper air

-4 1 -4 Use -4 FLM recommendation: to 

extrapolate up from surface

ICALM extrapolate calm to 

upper air

0 0 0

BIAS layer biases sfc vs. 

UA

NZ*0 NZ*0 NZ*0

IPROG gridded initial 

prognostic

0 14 14 Use prognostic inputs from MM5

RMAX1 max surface radius 

of influence

NA 50 30 Gives smoother wind fields, per 

AECOM

RMAX2 max aloft radius of 

influence

NA 100 100

RMAX3 max over-water 

radius of influence.

NA 100 100

RMIN min wind radius of 

influence.

0.1 0.1 0.1

RMIN2 min dist sfc winds 

extrap

4 4 4

TERRAD terrain radius of in 

influence

NA 10 10

R1 weight surface Step 

1 vs. obs

NA 100 18 Gives smoother wind fields, per 

AECOM

R2 weight aloft Step 1 

vs. obs

NA 200 20 Gives smoother wind fields, per 

AECOM

ITPROG 3D T from obs or 

prognostic

0 1 or 2 

implied

1 Use 1 per FLM recommendation: use 

surface station temperatures

TRADKM radius of influ. for T 

interp.

500 500 500

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

MM5 already smooth enough)

JWAT1 starting land use for 

T interp. over water

999 51 51 This area has very little "water" land 

use; may set to 999 to disable 

overwater feature, and avoid a 

CALMET bug

JWAT2 ending land use for T 

interp. over water

999 55 55
Page 9 of 133

Another important difference between the FIP and the WRAP work is EPA’s use of the

regulatory version of the CALPUFF modeling system 5.85 which comprises the following source 

code versions:

 CALMET Version 5.8, Level: 070623 

 CALPUFF Version 5.8, Level: 070623

 POSTUTIL Version 1.56, Level: 070627

 CALPOST Version 6.221, Level 080724

The projection and coordinate system used was the same as used by the WRAP for Arizona 

modeling:

 Projection: Lambert Conformal Conic (LCC)

 Projection origin (latitude, longitude): 40°, -97°

 Standard parallels: 33°, 45°

 False easting and northing: 0 m, 0 m

 Projection ellipsoid: “NWS-84”, 6370 km radius sphere

The CALMET modeling domain was identical to the WRAP Arizona domain: 288 x 225 grid 

cells (X & Y), each 4 km, with total size 1152 x 900 km; southwest corner at LCC coordinates -

1944 km, -900 km. The CALPUFF domain was the same as the CALMET domain.

II.B. CALPUFF Dispersion Model Inputs

II.B.1. CALPUFF Model Settings

CALPUFF model inputs were prepared using the WRAP’s input files as a starting point, from 

the WRAP Regional Modeling Center’s “BART CalPuff Modeling” web site.

6

The default 

MESOPUFF II chemical scheme was used (MCHEM =1), including separate tracking of the 

chemical species SO2, SO4, NO3, HNO3, and also the various particulate fractions SOA 

(organic), EC (elemental carbon) , PMF (fine particulate) , and PMC (coarse particulate). For the 

two smelters, the particulate fractions were not differentiated, but rather modeled as PMF.

 

5

EPA relied on version 5.8 of CALPUFF because it is the EPA-approved version promulgated in the Guideline on 

Air Quality Models (40 CFR 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15, 2003. EPA updated the 

specific version to be used for regulatory purposes on June 29, 2007, including minor revisions as of that date; the 

approved CALPUFF modeling system includes CALPUFF version 5.8, level 070623, and CALMET version 5.8 

level 070623. At this time, any other version of the CALPUFF modeling system would be considered an “alternative 

model”, subject to the provisions of Guideline on Air Quality Models section 3.2.2(b), requiring a full theoretical

and performance evaluation.

On December 4, 2013, EPA updated the “EPA-Approved” or regulatory version for both CALMET and CALPUFF 

to Version 5.8.4 (Level 130731). (See http://www.epa.gov/ttn/scram/dispersion_prefrec.htm#calpuff ) This updated 

incorporated several minor program “bugs”, which EPA believes do not affect the modeling results for this FIP. In 

any case, the model version used was the regulatory version at the time the modeling was performed.

6 WRAP Regional Modeling Center’s “BART CalPuff Modeling” web site, 

http://pah.cert.ucr.edu/aqm/308/bart.shtml.
Page 10 of 133

The WRAP CALPFF input files and the FIP files based on them used default CALPUFF 

settings, with include several exceptions. We are retaining these because of the extensive review 

performed for the original WRAP protocol.

Non-default CALPUFF settings in WRAP and FIP modeling:

 MXSAM Max sampling steps for one time step: 99 (default) vs. 5 (WRAP)

 CDIV(2) divergence criteria: 0 & 0 (default) vs. .01 & .01 (WRAP)

 SL2PF Slug-to-puff transition: 10 (default) vs. 5 (WRAP)

 NSPLIT number of puffs after split 3 (default) vs. 2 (WRAP)

Since slugs and puff-splitting are turned off (MSLUG = 0 and MSPLIT = 0), only the CDIV 

setting is likely to make a difference. 

II.B.2. CALPUFF Input for Facilities

CALPUFF inputs were set to accommodate the facilities’ locations, stack parameters, and 

emission rates for the base case and control scenarios. Facility stack parameters, such as stack 

height and exit temperature, were generally the same as those provided by WRAP member states 

to the WRAP, except that in some cases updated parameters were provided by the facilities at 

EPA’s request.

Baseline NOx and SO2 emissions used in modeling the facilities were generally based on data 

from Continuous Emissions Monitoring (CEMS) in place at the facilities, where available. For 

Electricity Generating Units (EGUs), such as APS Cholla, TEP Sundt and TEP Springerville this 

data is available in EPA’s CAMD Acid Rain Program database. The Lhoist Nelson Lime Plant 

and the Phoenix Cement Company Rillito Plant also had CEMS data available. EPA focused on 

the period from 2008 to 2011. The maximum 24-hour emissions were used, aside from a few 

extreme values not representative of steady-state operations. However, in cases where EPA 

approved the BART emissions limits submitted by ADEQ, EPA used emission rates based on 

those limits, in lb/MMBtu, in combination with the maximum daily heat rate in MMBtu/hour

from the CAMD data.

7

The baseline emissions used by EPA reflect current fuels and control 

technologies in place at the facilities, as well as regulatory requirements the facilities will be 

required to meet independent of EPA’s BART determination. This results in a more realistic 

estimate of current visibility impacts, and of the improvements that one would expect to result

from implementation of EPA’s proposed BART controls.

The baseline particulate matter (PM) emission rate used in modeling was generally the value 

used in the WRAP’s BART modeling. However, for all sources except the two smelters, EPA 

used procedures developed by the National Park Service8to divide the particulate emissions into 

separate chemical species, and into separate coarse and fine particle fractions, to better reflect 

their varying visibility impacts. UNC prepared a speciation spreadsheet for each emitting unit 

 

7 These data and the choice of maximum emission dates are in UNC’s master emissions spreadsheets 

“AZ_BART_sources_all-Task7-8_2012-06-10.xls” and “AZ_RP_sources_all-Task9_2012-09-30.xls”, 

“Springerville_CAMD_max.xlsx”, and in other EPA spreadsheets cited below in the discussion for individual 

facilities.

8

“Particulate Matter Speciation”, National Park Service, 2006. http://www.nature.nps.gov/air/Permits/ect/index.cfm.
Page 11 of 133

based on the NPS examples; these are available in the docket. Smelter PM emissions were not 

speciated, but rather assumed to be all PM2.5 (also called “PMF” or fine particulate within the 

model input). Variations on these emissions baseline choices are discussed under the BART 

determinations for individual facilities.

Although costs and emission reductions for each candidate BART control technology must 

necessarily be calculated separately for each emitting unit of a facility, emissions from all the 

units will be emitted into the air simultaneously. EPA modeled all units (stacks) and pollutants 

simultaneously. For example, if only NOx BART alternatives were evaluated, SO2 and PM10

emissions were still also included in the modeling. Modeling all emissions from all the units 

accounts for the chemical interaction between multiple plumes, and between the plumes and the 

background concentrations. This procedure also accounts for the fact that deciview benefits from 

controls on individual units are not strictly additive, due to the logarithmic dependence of 

deciviews on emissions.

II.B.3. CALPUFF Receptors

Receptors, the geographic locations for which model output is desired, must also be specified in 

the CALPUFF input. Standard receptors are provided by the National Park Service,9and have a 

spatial density of approximately 1 per square kilometer. The WRAP modeling and the modeling 

by UNC was performed using the 2005 version of these receptors. A later, 2008 version, had 

minor changes for the Chiracahua National Monument, and a major change for the Saguaro 

National Park. The inclusion of the western unit of the Saguaro, the Tucson Mountain District, 

added 68 receptors to the 310 already present for the eastern unit, the Rincon Mountain District. 

As discussed further below, EPA performed supplemental modeling for Saguaro NP for the TEP 

Sundt and CalPortland Cement facilities.

II.C. POSTUTIL Post-processor Inputs

POSTUTIL is a post-processor for CALPUFF, used to combine or scale concentration files and 

to adjust the partitioning of NO3 between HNO3 and nitrate NO3

-

. The latter is particulate 

ammonium nitrate, which affects visibility, and whose formation is limited by the available 

ammonia. POSTUTIL inputs are not available on the WRAP web site, but input preparation was 

straightforward for HNO3/NO3- partitioning (MNITRATE = 1), with a constant 1 ppb ammonia 

background concentration (BCKNH3). Ambient ammonia measurements for use as input to 

modeling are scarce, and measurements that include it in the form of ammonium even scarcer. In 

the absence of compelling ammonia background estimates, the EPA IWAQM Phase 2 guidance 

recommends the use of a 1 ppb ammonia background for arid lands, which includes Arizona.

10

II.D. CALPOST Post-processor Inputs

CALPOST is the final CALPUFF post-processor, and converts hourly CALPUFF/POSTUTIL 

concentrations to daily visibility impacts via the IMPROVE equation, discussed further below. 

 

9 National Park Service Class I Receptors, http://www2.nature.nps.gov/air/maps/Receptors/ .

10 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.
Page 12 of 133

The WRAP’s input files were used as a starting point. CALPOST inputs include natural 

background concentrations and relative humidity adjustment factors specific to each Class I area 

and also specific to each of the various visibility calculation methods, discussed below. Values 

for these parameters are provided by the Federal Land Managers.11

Concentrations are converted to deciviews by the CALPOST post-processor in two steps. First, 

the IMPROVE12 equation is used to estimate extinction bext from the predicted concentrations of 

various pollutants. Extinction, bext, is the percent of light scattered out of a path per 10 km 

distance (units usually stated as fraction scattered per million meters, that is, 1/Mm or Mm-1). 

The IMPROVE equation is used to convert measured or modeled concentrations into extinction 

for each pollutant chemical species, and then total them, accounting for the effect of relative 

humidity, and including the Rayleigh scattering that occurs in clean air.

In the second CALPOST step this extinction is converted to deciviews, using the defining 

equation for deciviews: deciviews = 10 ln(bext / 10). The visibility impact due to a facility is the 

difference (or “delta’) between: deciviews including the impact of the facility and natural 

background, and deciviews of the natural background alone. It is this delta deciviews (Δdv) that 

is provided by CALPOST. The units of this quantity are still deciviews, so often the term 

“deciviews” is used instead of “delta deciviews”.

Each modeled day and location in the Class I area will have an associated delta deciview. For 

each day, CALPOST 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 as a measure of the facility’s impact. The visibility improvement due to a control is the 

98th percentile delta deciview impact of the facility modeled at its baseline emissions, minus the 

same quantity when the facility is modeled at its controlled emissions.

EPA followed the BART Guidelines in assessing visibility impacts. However, certain aspects of 

assessing visibility with CALPUFF are not fully addressed in the Guidelines. These aspects 

include 1) the visibility calculation method (old vs. revised IMPROVE equation), 2) natural 

background concentrations (annual average versus best 20 percent of days), and 3) which “98th 

percentile” from the model to use.

Visibility Calculation Method: Visibility impacts may be computed with CALPOST using either 

the old or the revised IMPROVE equation for translating pollutant concentrations into deciviews; 

these are respectively CALPUFF visibility methods 6 and 8 (implemented in the CALPOST 

post-processor). 

 

11 “FLAG2010”, Federal Land Managers’ Air Quality Related Values Work Group (FLAG) Phase I Report—

Revised (2010), U.S. Forest Service, National Park Service, U.S. Fish And Wildlife Service, October, 2010. 

http://www.nature.nps.gov/air/Permits/flag/.

12 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 13 of 133

The old IMPROVE equation, Method 6 in CALPOST, is:

bext = 3 * f(RH) * [sulfate] 

+ 3 * f(RH) * [nitrate]

+ 4 * [organic mass]

+ 10 * [elemental carbon] 

+ 1 * [fine soil] 

+ 0.6 * [coarse mass] 

+ 10

The bracketed quantities are concentrations in g/m3, either measured or from CALPUFF. The 

final 10 is for Rayleigh scattering, which is due to the interaction of light with molecules of air 

itself, without pollutants. The f(RH) is a water growth factor for sulfate and nitrate; its value 

depends on relative humidity (RH), ranging from 1 at low humidity to 18 at 98% humidity.

The revised IMPROVE equation13, Method 8 in CALPOST, is:

bext = 2.2 * fs(RH) * [small sulfate] + 4.8 * fL(RH) * [large sulfate]

+ 2.4 * fs(RH) * [small nitrate] + 5.1 * fL(RH) * [large nitrate]

+ 2.8 * [small organic mass] + 6.1 * [large organic mass]

+ 10 * [elemental carbon]

+ 1 * [fine soil]

+ 1.7 * fss(RH) * [sea salt]

+ 0.6 * [coarse mass]

+ Rayleigh scattering (site-specific)

+ 0.33 * [NO2 (ppb)]

In the revised equation, sulfate is assumed to be all “large sulfate” if total sulfate is over 20 

μg/m3, otherwise its fraction of the total is assumed to increase uniformly between 0 and 1 when 

the total is in the range between 0 and 20. i.e., large sulfate = (total sulfate/20)*total. A similar 

definition applies for nitrate and for organic mass. There are Class I area-specific water growth 

factors (fs(RH), etc.) for large and small sulfate and nitrate, and for sea salt, and a Class I areaspecific Rayleigh scattering term.

Many BART assessments were performed before method 8 was incorporated into CALPUFF, so 

method 6 was generally used in past assessments. However, in this proposal EPA is primarily 

relying on method 8, though method 6 results are also provided. Method 8 is currently preferred 

by the Federal Land Managers; since the revised IMPROVE equation performs better at 

estimating visibility.14 Baseline impacts using method 6 are about 10 percent higher than those 

using method 8.

 

13 Revised IMPROVE Algorithm for Estimating Light Extinction from Particle Speciation Data, IMPROVE 

technical subcommittee for algorithm review, January 2006; on web page

http://vista.cira.colostate.edu/improve/publications/graylit/gray_literature.htm

14 Pitchford, Marc, 2006, “New IMPROVE algorithm for estimating light extinction approved for use”, The 

IMPROVE Newsletter, Volume 14, Number 4, Air Resource Specialists, Inc.; web page: 

http://vista.cira.colostate.edu/improve/Publications/news_letters.htm.
Page 14 of 133

Natural Background Conditions: Another CALPOST choice is whether to calculate visibility 

impacts relative to annual average natural conditions, or relative to the best 20 percent of natural 

background days; these may be referred to as “a” and “b”. For both “a” and “b”, background 

concentrations for each Class I area are available in a Federal Land Managers’ document. EPA 

Guidance allows for the use of either “a” or “b.”15 Since the annual average has worse visibility 

and higher deciviews than the best days, a given facility impact will be smaller relative to the 

average than it is relative to the best days. That is, a facility’s impact will stand out less under 

poorer visibility conditions. Thus, modeled facility impacts and control benefits appear smaller 

when “a” is used than when “b” is used. In this proposal, EPA is relying on “b”, best 20 percent, 

consistent with initial EPA recommendations for BART assessments.

16 This is also the most 

consistent with current Federal Land Manager guidance for assessing visibility impacts at Class I 

areas. For the facilities examined in this proposal, baseline impacts would average about 20 

percent lower using background “a” than those using background “b”.

Considering visibility method and choice of background together, the BART visibility 

assessments relied on by ADEQ used method “6a”, the old IMPROVE equation, and impacts 

relative to annual average natural conditions. This is a valid approach, and is consistent with 

EPA guidance.17 However, for most of the facilities in this proposal, EPA used all four 

combinations of the IMPROVE equation version and natural background: 6a, 6b, 8a, and 8b. 

EPA primarily relied on method “8b”, that is, the revised IMPROVE equation, and impacts 

relative to the best 20 percent of natural background days. This is most consistent with our 

current understanding of how best to assess source specific visibility impacts. Combining the 

differences in visibility method and chosen background, for the facilities examined in this 

proposal, baseline impacts would average about 15 percent lower using method “6a” than those 

using method “8b”.

Note that CALPOST processing for method 6 (both 6a and 6b) performed by UNC erroneously 

included the effect of NO2 (LVNO2=T), which is supposed to be included only for method 8. 

EPA corrected this for model results for Sundt unit 4, but it remains incorrect for the other 

facilities originally modeled by UNC. For the two smelters, which were modeled by EPA, 

method 6 was run correctly. In addition, in CALPOST UNC reversed the NPS receptor sets for 

the Chiracahua National Monument (abbreviated “chir”) and the Chiracahua Wilderness Area 

(abbreviated “chrw”). This was likely because, confusingly, the name of the NPS receptor set file 

for Chiracahua NM begins with “chirwild” (for the wilderness area within the National 

Monument), whereas the NPS receptor set file for the Chiracahua Wilderness Area begins with 

“chir2”. The visibility parameters include Raleigh scattering, humidity adjustment factors, and 

natural background concentrations. Since these two Class I areas are very close to each other, the 

use of the visibility parameters for one with the receptors of the other would be expected to make 

little difference, except possibly for facilities that are nearby. EPA corrected this in the UNC 

work only for Sundt and for CalPortland Cement. All EPA modeling, for additional control 

scenarios for all facilities and for all modeling for the two smelters, used the correct receptors 

 

15 “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations”, 

memorandum from Joseph W. Paisie, EPA OAQPS, July 19, 2006, p.2.

16 BART Guidelines, 70 FR 39125, July 6, 2005. “Finally, these final BART guidelines use the natural visibility 

baseline for the 20 percent best visibility days for comparison to the ‘cause or contribute’ applicability thresholds.”

17 Additional Regional Haze Questions”, September 27, 2006 Revision, EPA OAQPS.
Page 15 of 133

and visibility parameters (i.e. Raleigh scattering, humidity adjustment factors, and natural 

background concentrations.) for the two Chiracahua areas.

98th Percentile From Model: As recommended in the BART Guidelines, the 98th percentile 

daily impact in deciviews is used as the basic metric of visibility impact. (For a given Class I 

area, and for each modeled day, the model finds the maximum impact among all the receptors. 

From among these 365 maximum daily values, the 98th percentile is chosen.) For a single 

complete year of meteorology, the 8th highest value would represent the 98th percentile 

(discarding the top 2%, or 7.3 days). Since multiple years of meteorology are modeled, there are 

at least three ways to use the model results: the maximum from among the 98th percentiles for 

the individual years 2001, 2002, and 2003 (“maximum”); the average of these three (“average”), 

or a single 98th percentile computed from all three years of data together (“merged” or “All 

Years”, the 22nd high among 1095 daily values). The average and merged values are both 

unbiased estimates of the true 98th percentile; for this proposal EPA has used the merged value. 

The more conservative maximum value would be appropriate for a screening purpose, such as 

for determining whether a source is subject to BART.

For computing multiyear visibility statistics, e.g. 98th percentile considering all days in 2001-

2003, UNC used the CALPUFF APPEND processor to concatenate POSTUTIL concentration 

files before running CALPOST on the appended file to get e.g. the 22nd high. These results from 

the UNC spreadsheets were used for Cholla unit 1, Springerville units 1&2, and Sundt units 1-3. 

However, for the other facilities, EPA took the daily values from the three CALPOST output 

files for 2001, 2002, and 2003, and used the 22nd high from the full day list. The two procedures 

are equivalent.

II.E. Supplemental modeling by EPA

While UNC performed most of the CALPUFF simulations, EPA performed simulations for 

additional controls, for additional sources (the smelters), and for sensitivity tests to explore 

specific issues. For the Nelson Lime Plant, EPA is relying on modeling performed by Trinity 

Consultants for the facility owner, Lhoist North America (LNA).

III. Best Available Retrofit Technology (BART) Analysis

III.A. Introduction

The purpose of the BART analysis is to identify and evaluate the best system of continuous 

emission reduction based on the BART Guidelines18 as summarized below. Steps 1 through 3 

address the availability, feasibility and effectiveness of retrofit control options. In our analysis of 

control technology options, we expressly include the emission baseline calculation that is a key 

 

18 See July 6, 2005 BART Guidelines, 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations.
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factor in determining control effectiveness. Step 4 is the five-factor19 BART analysis that results 

in selecting the emission limit that represents BART in Step 5. 

EPA conducted Best Available Retrofit Technology (BART) analyses and determinations for 

four sources: Sundt Generating Station Unit 4, Nelson Lime Plant Kilns 1 and 2, Hayden Smelter 

and Miami Smelter. The details of our analyses are discussed in the sections below.

III.B. Sundt Generating Station Unit 4

III.B.1. Summary 

This document contains the basis for the determination of BART control options for nitrogen 

oxides (NOX), particulate matter (PM), and sulfur dioxide (SO2) for the H. Wilson Sundt 

Generating Station, Unit I4. The Sundt Generating Station is an electric utility power plant 

located in Tucson, AZ, operated by Tucson Electric Power (TEP), and consists of four steam 

electric boilers (Units I1-4) and three stationary combustion turbines (IGT1-3) for a total net 

generating capacity of approximately 500 MW.20 Unit I4 (hereinafter referred to as “Unit 4”) is a 

dry bottom wall-fired boiler with a maximum gross capacity of 130 MW when firing coal. The 

BART analysis for each pollutant consists of the following five steps:

Step 1 – Identify all available technologies

Step 2 – Eliminate technically infeasible options

Step 3 – Evaluate control effectiveness of remaining control technologies

Step 4 – Evaluate BART factors 

Factor 1: Costs of compliance 

Factor 2: Energy and non-air quality impacts

Factor 3: Presence of existing control technology

Factor 4: Remaining useful life of the source

Factor 5: Visibility improvement

Step 5 – Select BART

This five-factor analysis is based on the following documents:

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 7: Five-Factor 

BART Analysis for Chemical Lime Company Nelson, TEP Sundt (Irvington), and 

Catalyst Paper (Snowflake) Plants, Contract No. EP-D-07-102, Work Assignment 5-12; 

Prepared for EPA Region 9 by University of North Carolina at Chapel Hill, ICF 

International, and Andover Technology Partners; October 9, 2012 (“Contractor’s 

Report”). 

 Comments from Tucson Electric Power on EPA’s proposed partial approval/partial 

disapproval of the Arizona Regional Haze SIP (“TEP’s March 6, 2013 Comment 

Letter”). Submitted March 6, 2013.

 

19 The five factors are as follows: cost of compliance, energy and non-air quality environmental impacts of 

compliance, pollution control equipment in use at the source, remaining useful life of the facility, and visibility 

impacts.

20 As described in Pima DEQ Permit No. 1052, Technical Support Document.
Page 17 of 133

 Letter from Tucson Electric Power to EPA containing visibility modeling and control 

cost information (“TEP’s May 10, 2013 Letter”). Submitted May 10, 2013. 

 Emission calculation spreadsheet, “TEP Sundt4 2001-12 CAMD Emissions.xlsx”

 Cost calculation spreadsheet, “TEP Sundt4 Control Costs (final for NPRM docket).xlsx”

As described in the following sections, we are proposing BART limits for Sundt Unit 4, based on 

the corresponding technologies listed in Table III.B-1. As further described in our NOX BART 

analysis, we are proposing an emission limit consistent with the use of SNCR as constituting 

BART for NOX. In addition, we are proposing a switch to natural gas as a better-than-BART 

alternative.

Table III.B-1: Summary of Proposed BART determinations

Pollutant Emission Limit

(lb/MMBtu)

Control Technology

Basis1

NOX 0.36 Selective Non-Catalytic 

Reduction (SNCR)

PM10 0.030 Fabric filter baghouse 

(existing)

SO2 0.23 Dry Sorbent Injection 

(DSI)

1

These control technologies are listed for reference, as the facility is not necessarily 

required to install the listed technology to meet the BART limit

III.B.2. Facility Description

Sundt Unit 4 is a steam electric boiler that was manufactured in 1964 and completed in 1967.

Originally designed to fire natural gas and fuel oil, Sundt Unit 4 was converted to fire coal in the 

early 1980s as a result of an order issued by the Department of Energy that required certain large 

power plants to convert their operations to additionally have the capacity to burn coal. As part of 

the coal conversion, the unit was equipped with a fabric filter for particulate matter control. In 

1999, Unit 4 was upgraded with low- NOX burners (LNB) and overfire air (OFA) designed to 

meet Phase II Acid Rain Program requirements. 

At present, Sundt Unit 4 operates with the following pollution control equipment, and is subject to the 

following emission limits (coal operating scenario):
Page 18 of 133

Table III.B-2: Current emission control technology

Pollutant Control Device Emission Limit

NOX LNB with OFA 0.46 lb/MMBtu21

PM Fabric filter/baghouse 233 lb/hr22

SO2 None 1 lb/MMBtu23

TEP has indicated that the generating capacity of Sundt Unit 4 while firing coal was reduced 

compared to its capacity on natural gas. As reported to the Energy Information Agency (EIA), 

Sundt Unit 4 has a 173 MW nameplate capacity while firing natural gas. However, the maximum 

gross capacity that the unit could operate at, for a sustained period of time, while burning coal is 

approximately 130 MW. This is primarily due to fact that the amount of coal that can be 

introduced to the boiler is limited by the size of the boiler. Excess coal injection causes the flame 

to impinge on the back wall of the boiler which damages the boiler tubes.24 A summary of 

historical data for a period of time extending from 2009-12 is included in Table III.B-3 below.

Table III.B-3: Sundt Unit 4, Historical Emissions (2008-12)

Year Heat Duty NOX SO2 Coal

Natural 

Gas

(MMBtu/yr) (tpy) (lb/MMBtu) (tpy) (lb/MMBtu) (tons) (MCF)

2012 6,313,719 945 0.297 371 0.118 44,049 4,660,701

2011 5,993,769 1,366 0.445 2,185 0.729 265,111 157,919

2010 6,869,999 1,303 0.368 1,733 0.505 162,212 1,904,433

2009 4,801,971 709 0.285 636 0.265 73,464 2,642,992

2008 8,709,923 1,880 0.429 2,882 0.661 378,956 18,422

III.B.3 General Approach to the Five-Factor BART Analysis

This section contains a general description of our approach to the five-factor analysis, and discusses 

certain elements of our approach that are common to each of the pollutant-specific analyses performed for 

Sundt Unit 4. An initial five-factor BART analysis was performed by our contractors, the University of 

North Carolina Institute on the Environment (UNC) and ICF International (ICF). This analysis is 

summarized in the final Contractor’s Report and associated modeling spreadsheets. In comments 

submitted on our proposed partial approval/partial disapproval of the Arizona Regional Haze SIP, and in a 

separate letter sent to EPA, TEP provided the results of its own cost calculations and visibility modeling 

relating to Sundt Unit 4. There are certain elements and issues raised by TEP that we agree with and have 

incorporated into own analysis. As a result, the analyses presented here rely primarily upon the work 

initially prepared by our contractor, except those areas where we note certain revisions or edits 

implemented as a result of TEP’s analysis. 

 

21 Pima DEQ Permit No. 1052, Attachment F: Phase II Acid Rain Permit.

22 As determined by Pima DEQ Permit No. 1052, Specific Condition II.A.1.

23 Pima DEQ Permit No. 1052, Specific Condition II.A.2.b.

24 Page 2, TEP’s May 10, 2013 Letter.
Page 19 of 133

Factor 1: Costs of Compliance

Cost estimates 

Capital costs and annual operating costs were developed by our contractor using the Integrated 

Planning Model (IPM) Base Case v4.10 (August 2010). Developed by ICF Consulting, Inc. and 

used to support public and private sector clients, IPM is a multi-regional, dynamic, deterministic 

linear programming model of the U.S. electric power sector. IPM relies upon numerous 

components and sub-components to specify constraints and variable values that feed into the 

model algorithms used during an actual IPM model run. Specifically, we relied upon one specific 

component of IPM, the air pollution control cost development component. We used the cost 

information and equations contained in this component by manually placing them into a 

spreadsheet that calculated the capital and O&M costs for these control options. We did not, 

however, run IPM, as the type of information generated by an actual IPM model run (e.g., 

generation dispatch decisions, capacity decisions) is not relevant to our action.

For Base Case v4.10, EPA’s Clean Air Markets Division (CAMD) contracted with engineering 

firm Sargent and Lundy to perform a complete bottom-up engineering reassessment of the cost 

and performance assumptions contained in this component for SO2 and nitrogen oxides NOX

emission controls. The specific parameters and assumptions used in developing these costs are 

included in our contractor’s report and its associated spreadsheet (see “Contractor’s Report”). In 

addition, we have made certain revisions to these original cost estimates based on information 

received from TEP. These revised costs are included in our document and are summarized in the 

BART analyses below.25

Baseline Period

A review of EIA data and emission data reported to CAMD indicate that Sundt Unit 4 has fired 

natural gas for significant periods of time during 2009, 2010, and 2012. TEP has indicated that 

while Sundt Unit 4 has predominantly operated as a coal-fired unit, it has recently expanded its 

use of natural gas as a result of historically low natural gas prices.26 As a result, we used calendar 

year 2011, during which Sundt Unit 4 used predominantly coal, as the baseline period in the 

BART analysis. Although this represents only a single year of emission data, we consider this 

period of coal usage, rather than a period of primarily natural gas usage, to represent a realistic 

depiction of anticipated annual emissions.27

Capacity Factor

Due to the different maximum gross capacity of Sundt Unit 4 when burning coal (130 MW) and 

natural gas (173 MW), determining the capacity factor for years involving use of both fuels 

requires matching the appropriate max gross capacity to the corresponding period of fuel use. 

For the baseline period of 2011, which corresponds almost entirely to coal usage, this results in a 

capacity factor of 0.49, and is the highest capacity factor observed over the 2009-12 period.

 

25 “TEP Sundt4 Control Costs (final for NPRM docket).xlsx”

26 Page 2, TEP’s May 10, 2013 Letter.

27 As discussed in the BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.d.
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Factor 2: Energy and Non-air Environmental Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common elements 

relating to this factor discussed here. Pollutant-specific discussions of these issues are included in the 

following sections.

Factor 3: Pollution Equipment in Use at the Source

The presence of existing pollution control technology at each source is reflected in our BART analysis in 

two ways: first, in the consideration of available control technologies, and second, in the development of 

baseline emission rates for use in cost calculations and visibility modeling. Pollutant-specific discussions 

of these issues are included in the following sections.

Factor 4: Remaining Useful Life of the Source

We are considering each source's “remaining useful life” as one element of the overall cost 

analysis as allowed by the BART Guidelines.28 Since we are not aware of any enforceable shutdown date for Sundt Unit 4, we have used a 20-year amortization period, as noted in the EPA 

Cost Control Manual, as the remaining useful life of the facilities considered in this proposed 

action.29

Factor 5: Anticipated Degree of Visibility Improvement

Baseline Emissions 

Baseline emissions for NOX and SO2 were based on maximum daily emission rates for Sundt 

Unit 4 as reported to EPA’s CAMD Acid Rain Program database, for the period from 2008 to 

2010. While this includes time periods outside of the 2011 period that is used as the baseline 

period for the annual emission estimates used in cost calculations, the highest daily emission rate 

during the 2008-10 period corresponded to coal usage. As noted previously, the primary reason 

for using 2011 as the baseline period for annual average emission estimates were concerns that 

the extended periods of natural gas use during 2008-10 were not representative of anticipated

operations based on coal. Since the highest daily emission rates during the 2008-10 period 

correspond to coal usage, we consider them reasonable estimates of baseline emissions despite 

the fact that they are drawn from a baseline period different from the one used to calculate the 

costs of compliance. The baseline particulate matter emission rate used in the model is based on 

the value used in the original WRAP modeling, which reflects the use of the existing fabric filter

baghouse for particulate matter control. 

 

28 40 CFR Part 51, Appendix Y, section IV.D.4.k.

29 We note that the 20 year amortization period is primarily used in NOx control cost calculations, such as for SCR.

In order to promote consistency in the analysis, we have used the 20 year period in the cost calculations for other 

control options, such as for SO2 control, for which the Control Cost Manual includes examples that use an 

amortization period of 15 years.
Page 21 of 133

Control Scenario Emissions

For the CALPUFF modeling to assess visibility after application of a control technology, the 

percent control expected from the technology was applied to the baseline maximum daily 

emissions just described, as recommended in the BART Guidelines.30

Modeling Approach

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full Sundt unit 4 modeling results, including for 

the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, and 8a, can 

be found in the tables and bar graphs in docket for this action and in the spreadsheet

Sundt4_visibility_results.xlsx.

Corrections and additions to UNC modeling

As discussed above, EPA corrected the CALPOST processing for Chiracahua NM and 

Chiracahua Wilderness. In addition, EPA ran CALPUFF using the updated 2008 NPS receptor 

set for Saguaro NP, which includes both the east and west units of the park. EPA estimated 

impacts for both parts considered together (“saguboth”), the eastern unit by itself (“sagueast”), 

and the western unit by itself (“saguwest”). Finally, EPA corrected the CALPOST processing for 

all areas for visibility methods 6a and 6b. Method 6 is the old IMPROVE equation, which does 

not include an NO2 gas term, so EPA set the corresponding CALPOST input to “False” (LVNO2 

= F). These corrections and updates apply to the UNC base case and to UNC control cases 1 

through 11, covering various combinations of NOx (SNCR, SCR) and SO2 controls (DSI at 75% 

control, DFGD, WFGD). EPA performed additional modeling for Pipeline Natural Gas (PNG) 

scenarios and for DSI at 70% SO2 control, alone and in combination with SNCR and SCR, again 

for various portions of Saguaro NP.

Sensitivity analyses

The UNC model results showed disbenefits from dry and wet FGD control on SO2 for the 

Saguaro National Park. That is, the effect of the SO2 reduction was to increase visibility impacts; 

this shows up as negative numbers in tables listing visibility improvement. To investigate this, 

EPA reran CALPUFF for the base case and DFGD (“ctrl2”), and for intermediate scenarios for 

which the SO2 emissions, the PM speciation, and the stack parameters were in turned changed in 

turn from their base case values to their DFGD values. EPA found that the change in PM 

speciation caused a small disbenefit, and the lowering of stack exit velocity and temperature 

caused a large disbenefit. This applied especially to Saguaro, and to a minor degree to Galiuro 

Wilderness, not enough to overcome the benefit due to SO2 reductions. The results are described 

more fully in the spreadsheet Sundt4_DFGD_disbenefit_check.xlsx.

As discussed in the Federal Register notice, Sundt is only 17 km from the eastern portion of 

Saguaro NP, and it is possible that NOx emissions do not fully convert to NO2 by the time they 

reach there, as is assumed by CALPUFF. To explore this, EPA ran the POSTUTIL post-

 

30 40 CFR Part 51, Appendix Y, section IV.D.5 (“Post-control emission rates are calculated as a percentage of precontrol emission rates. For example, if the 24-hr pre-control emission rate is 100 lb/hr of SO2, then the post control 

rate is 5 lb/hr if the control efficiency being evaluated is 95 percent.”)
Page 22 of 133

processor to scale back the NO2 , NO3, and HNO3 species in CALPUFF to various degrees, and 

found the resulting visibility impacts at the various Saguaro NP portions. EPA found that the 

benefit of proposed BART (SNCR plus DSI) and of conversion to PNG, scaled down along with 

the percent NO-to-NO2 conversion assumed. As summarized in the notice, the benefits remain 

substantial for both, and PNG shows greater visibility improvement than EPA’s BART proposal. 

The results are described more fully in the spreadsheet Sundt4_vis_NO2conv.xlsx.

III.B.4 Particulate Matter BART Analysis

Step 1 – Identify all available technologies

Fuel Supply Change

We note that since it was originally constructed as a natural gas fired boiler, Sundt Unit 4 has 

been using natural gas a primary fuel for significant periods of time since 2009. While a change 

in fuel supply to natural gas instead of coal is an inherently less polluting option, the BART 

Guidelines do not require fuel supply changes to be considered as a control option.31 As a result, 

this option is not considered further in our five-factor BART analysis, but is discussed as 

potential “better-than-BART” alternative in section VII below.

Sundt Unit 4 presently operates with a fabric filter baghouse for particulate control. A baghouse

operates on the same principle as a vacuum cleaner. Air carrying dust particles is forced through 

a cloth bag that is designed and manufactured to trap particles greater than a certain specified 

diameter. As the air passes through the fabric, the dust accumulates on the cloth and is removed 

from the air stream. The accumulated dust is periodically removed from the cloth by shaking or 

by reversing the air flow. The layer of dust, known as dust cake, trapped on the surface of the 

fabric has the potential to result in high efficiency rates for particles ranging in size from 

submicron to several hundred microns in diameter. A fabric filter baghouse is considered the 

most stringent control device for particulate matter control. 

The BART Guidelines provide that, where a source has controls already in place which are the 

most stringent controls available, it is not necessary to comprehensively complete a full fivefactor BART analysis, as long these most stringent controls available are made federally 

enforceable. Accordingly, instead of completing the remaining steps of a five-factor BART 

analysis, we have evaluated what the appropriate emission would be to ensure that the fabric 

filter achieves an appropriate degree of control. 

At present, the facility’s Title V operating permit indicates that Sundt Unit 4 is currently subject 

to a PM emission limit of approximately 233 lb/hr, as determined using EPA Test Method 5. In 

addition, Sundt Generating Station is a major source of hazardous air pollutants (HAPs).32 As an 

existing coal fired boiler located at a major source of HAPs, Unit 4 is an affected source under 

40 CFR, Part 63, Subpart DDDDD (also known as the Mercury and Air Toxic Standard or 

MATS), and has the option to comply with a filterable PM10 limit (as a surrogate for certain 

 

31 40 CFR 51, Appendix Y, Section IV.D.1.5, STEP 1: How do I identify all available retrofit emission control 

techniques?

32 As discussed on Page 10 of the TSD for Air Quality Permit # 1052, Sundt Generating Station has an aggregate 

HAP PTE of approximately 81 tpy.
Page 23 of 133

particulate HAPs) of 0.03 lb/MMBtu by April 16, 2015. Table III.B-4 contains the average highload particulate emissions test results from a recent performance test (2011). These results 

indicate that Unit 4 complies with its current particulate matter emission limit, and suggests that 

it will be able to comply with the MATS filterable PM10 limit.33

Table III.B-4: Sundt Unit 4 Particulate Matter Test results

Heat Duty Filterable PM10

Date (MMBtu/hr) (gr/dscf) (lb/hr) (lb/MMBtu)

6/9/2011 1,279 0.010 28.49 0.022

Because Sundt Unit 4 presently operates with a fabric filter baghouse, which is the most stringent 

control for particulate matter, we are proposing a PM10 BART emission limit of 0.03 lb/MMBtu 

(on a filterable PM10 basis) based on the use of the existing fabric filter baghouse.

III.B.5 NOX BART Analysis

Step 1 – Identify all available technologies

Fuel Supply Change

Sundt Unit 4 has used natural gas instead of coal as a primary fuel for significant periods of time 

since 2009. While a change in fuel supply to natural gas instead of coal is an inherently less 

polluting option, the BART Guidelines do not require fuel supply changes to be considered as a 

control option.34 As a result, this option is not considered further in our five-factor BART 

analysis but is discussed as potential “better-than-BART” alternative in section VII below.

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOX to nitrogen and water. A NOX reducing

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through

injection nozzles at the cyclone inlets. Because catalyst is not used to drive the reaction,

temperatures of 1600-2100 degrees F are required. Flue gas temperature at the point of reagent 

injection can greatly affect NOX removal efficiencies and the quantity of ammonia or urea that 

will pass through the SNCR unreacted (referred to as ammonia slip). At temperatures below the 

desired operating range, the NOX reduction reactions diminish and unreacted ammonia emissions 

increase. Above the desired temperature range, ammonia is oxidized to NOX resulting in low 

NOX reduction efficiencies.

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses either ammonia or urea in the

presence of a metal-based catalyst to selectively reduce NO and NO2 to molecular nitrogen,

water, and oxygen. The catalyst lowers the temperature required for the chemical reaction

between NOX and the reducing agent. Technical factors that impact the effectiveness of this

technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur

 

33 Tucson Electric Power, H. Wilson Sundt Irvington Generating Station, Unit #4, Compliance/CEMS Test Report, 

Test Dates: 06/08-09/11.

34 40 CFR 51, Appendix Y, Section IV.D.1.5, STEP 1: How do I identify all available retrofit emission control 

techniques?
Page 24 of 133

content of the fuel, design of the ammonia injection system, and the potential for catalyst

poisoning.

Step 2 – Eliminate technically infeasible options

Each of the control options identified in Step 1 has certain design concerns, which have been 

discussed briefly below. Despite these issues, each of the options listed in Step 1 are considered 

technically feasible.

Selective Non-Catalytic Reduction (SNCR)

Design challenges primarily involve ensuring proper mixing of the reactant and flue gas within 

the reaction zone, delivery of reagent in the proper temperature window, and sufficient residence 

time of the reagent and flue gas in that temperature window. In addition to temperature and 

mixing, several other factors influence the performance of an SNCR system, including residence 

time, reagent-to-NOX ratio, and fuel sulfur content. Factors that can influence technical feasibility 

include boiler size and configuration, which can cause difficulties in locating and installing

ammonia injection points capable of achieving adequate mixing within the required temperature 

zone. Boiler load changes affect flue gas flow rates and temperatures, which could make it 

particularly difficult to inject the needed quantity of reactant at the requisite temperature. We 

note, however, that SNCR is generally considered technically feasible and has been installed on 

numerous coal-fired boilers of varying sizes. We are not aware of any of these challenges being 

present at Unit 4 to a degree that would warrant elimination of this option as being technically 

infeasible. 

Selective Catalytic Reduction (SCR)

SCR has also been installed on numerous coal-fired boilers of varying sizes, and is considered 

technically feasible. We note that SCRs are classified as a low dust SCR (LDSCR) or high dust 

SCR (HDSCR). LDSCRs are designed for low-particulate laden streams, such as natural gas 

combustion units or after a particulate control device. HDSCR units are designed to handle 

streams with higher loading rates of particulates and potential catalyst contaminants, and are 

usually installed on solid fuel combustion units before the particulate control device. Although 

Sundt Unit 4 operates with a particulate control device, an LDSCR is not considered appropriate 

because the device in question is a fabric filter baghouse. The normal maximum allowable 

temperature for a baghouse is 400 degrees F, which is at the low end of the temperature range 

required for operation of an SCR system (approx 400-800 degrees F). As a result, the SCR 

system considered in this analysis is the HDSCR. 

Step 3 – Evaluate control effectiveness of remaining control technologies

Selective Non-Catalytic Reduction (SNCR)

Typical NOX control efficiencies range from 40% to 60%, depending on inlet NOX

concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous

reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of

interfering chemical substances in the gas stream. Guaranteed NOX reduction rates are in the

50% range to limit ammonia slip to 10 ppm. Because Sundt Unit 4 already operates with NOX

combustion controls, we have used an SNCR control efficiency of 30% from a LNB with OFA 
Page 25 of 133

baseline. Considering that typical combustion control technologies can achieve control 

efficiencies of approximately 25-30%, this results in a total control efficiency from an 

uncontrolled baseline of approximately 50%, which is in the mid-range of SNCR control 

efficiencies. 

Selective Catalytic Reduction (SCR)

Existing vendor literature and technical studies indicate that SCR systems are capable of 

achieving approximately 80-90% control efficiency, and that this emission rate can be achieved 

on a retrofit basis, particularly when combined with combustion control technology such as 

LNB. 35 Our contractor used a design emission rate of 0.050 lb/MMBtu (annual average), which 

in the case of Sundt Unit 4 corresponds to a control efficiency of 89%. While this is a value close 

to the upper range of SCR control efficiency, at this time we consider the use of 0.050 lb/MMBtu 

appropriate for Sundt Unit 4. A review of Acid Rain Program data indicates that there are up to 

seven dry-bottom, wall-fired boilers operating with SCR on a retrofit basis that have achieved an 

annual average emission rate of 0.050 lb/MMBtu or lower in practice.36 However, there are 

design considerations we have not yet accounted for between Sundt Unit 4 and these other units, 

such as boiler size, coal type/characteristics, and loading profile, that have the potential to affect 

this comparison. If we receive additional comments that sufficiently document source-specific 

considerations justifying the use of an emission rate higher than 0.050 lb/MMBtu, we may 

incorporate such considerations in our selection of BART.

Step 4 – Evaluate BART factors 

Factor 1: Costs of compliance 

In evaluating the costs of compliance for each of the control options we considered, we 

calculated the control costs ($) and emission reductions (tons/year of pollutant) for each 

control technology, and developed average cost effectiveness ($/ton) values for each 

option. Emission reductions for each option are summarized in Table III.B-5 below. A 

more detailed version of emission calculations can be found in our docket,

37 and in our 

contractor’s report. The heat duty and capacity factor used in the calculations 

summarized below differ from the values used in the calculations originally prepared by 

our contractor, due to the unit’s lower capacity when burning coal rather than natural gas.

As noted in TEP’s May 10 letter, the 173 MW nameplate capacity of Sundt Unit 4

corresponds to periods of natural gas operation. However, the maximum gross capacity of 

Sundt Unit 4 while burning coal is approximately 130 MW. The heat duty (MMBtu/hr) 

and capacity factor used below reflect the coal-burning nameplate capacity.38

 

35 See “Emissions Control: Cost-Effective Layered Technology for Ultra-Low NOx Control” (2007), “What’s New 

in SCRs” (2006), and “Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers” (2005).

36 See spreadsheet titled “CAMD Wall-fired Coal EGUs.xlsx”.

37 See spreadsheet titled “TEP Sundt4 2001-12 CAMD Emissions.xlsx”.

38 As noted by TEP and Burns and McDonnell, although the calculated capacity factor is different, the annual 

emissions in tons per year removed do not change significantly, as the change in capacity factor is largely offset by 

the change in maximum unit gross rating.
Page 26 of 133

Table III.B-5: NOX Control Option Emission Estimates

Control Option

Control 

Efficiency

Emission 

Factor Heat Duty Capacity

NOX Emission 

Rate

NOX

Emission 

Reduction

% (lb/MMBtu) (MMBtu/hr) Factor (lb/hr) (tpy) (tpy)

Baseline 

(LNB+OFA) -- 0.445 1,371 0.49 610 1,310 --

SNCR+LNB+OFA 30% 0.312 1,371 0.49 427 917 393

SCR+LNB+OFA 89% 0.050 1,371 0.49 69 147 1,162

Detailed cost calculations can be found in our docket.39 We have relied primarily upon 

the cost calculations prepared by our contractor, but have incorporated certain elements 

of TEP’s analysis, as described in its May 10, 2013 letter, into our cost calculations. The 

most significant revisions to cost estimates include the following:

 Unit size was changed from 173 MW to 130 MW, to reflect the gross capacity 

corresponding to coal use. Since IPM calculates many costs on a $/kw basis, this has the 

net effect of decreasing certain costs, particularly several O&M costs. Overall, however, 

revised capital cost estimates increased for SCR ($45 million from $38 million) and 

SNCR ($3.1 million from $2.8 million) 

 TEP noted certain difficulties associated with retrofit installation of SCR due to site 

congestion and configuration in relation to the existing boiler structure and coal handling 

system. As a result, we have used a retrofit difficulty value of 1.5 (increased from 1.0) in 

IPM cost estimates.

 TEP stated the site congestion and coal handling configuration also requires substantial 

modifications to the air preheater for SCR installation. We have included these costs into 

IPM cost estimates (previously, there were no air preheater modification costs). 

Table III.B-6: NOX Control Option Cost Effectiveness

Control 

Option

Capital 

Cost

Annualized 

Capital 

Cost

Annual 

Operating 

Cost

Total 

Annual 

Cost

Emission 

Reduction

Cost Effectiveness 

($/ton)

($) ($) ($) ($/yr) (tpy) Ave Incremental

SNCR $3,079,089 $290,644 $975,124 $1,265,768 393 3,222 --

SCR $45,167,561 $4,263,498 $1,753,975 $6,017,474 1,162 5,176 6,174

Factor 2: Presence of existing control technology

The presence of existing pollution control technology at Sundt Unit 4 is reflected in our 

BART analysis in two ways: first, in the consideration of available control technologies, 

and second, in the development of baseline emission rates for use in cost calculations and 

visibility modeling. In the case of NOX, Sundt Unit 4 currently operates with LNB and 

OFA. This is reflected in our selection of CY2011 as the baseline period, which includes 

the use of LNB and OFA.

 

39 TEP Sundt4 Control Costs (final for NPRM docket).xlsx.
Page 27 of 133

Factor 3: Remaining useful life of the source

As explained above, we are considering the “remaining useful life” of Sundt Unit 4 as 

one element of the overall cost analysis as allowed by the BART Guidelines. Since we 

are not aware of any federally- or State-enforceable shut-down date for this unit, we have 

used a 20-year amortization period described in the EPA Cost Control Manual as the 

remaining useful life for the control options considered for Sundt Unit 4.

Factor 4: Energy and non-air quality environmental impacts

With respect to the potential energy impacts of the BART control options, we note that 

SCR incurs a draft loss that will increase parasitic loads, and that other emissions controls 

may also have modest energy impacts. The costs for direct energy impacts, i.e., power 

consumption from the control equipment and additional draft system fans from each 

control technology, are included in the cost analyses and are not considered further in this 

section. Indirect energy impacts, such as the energy to produce raw materials, are not 

considered, consistent with the BART guidelines.

Ammonia adsorption (resulting from ammonia injection from SCR or SNCR) to fly ash is 

generally not desirable due to odor but does not impact the integrity of the use of fly ash 

in concrete. However, other NOX control technologies, including LNB, also 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. 

Commercial scale technologies exist to remove ammonia and LOI from fly ash. 

Moreover, the impact of SCR on fly ash is smaller than the impact of LNB on fly ash, 

and in both cases, the adverse effects can be mitigated.40 We conclude that the ability of 

the relevant facilities to sell fly ash is unlikely to be affected by the installation of SCR 

and SNCR technologies.

SCR and SNCR may involve potential safety hazards associated with the transportation 

and handling of anhydrous ammonia. However, since the handling of anhydrous 

ammonia will involve the development of a risk management plan (RMP), we consider 

the associated safety issues to be manageable as long as established safety procedures are 

followed. As a result, we do not consider these impacts sufficient enough to warrant 

eliminating either of the available control technologies.

Factor 5: Visibility improvement

The overall visibility modeling approach is described in Section III (Factor 5). Baseline 

emission rates, control option emission rates, and stack parameters used in NOX control 

scenario modeling can be found in the model emission rate spreadsheet prepared by our 

contractor.41 Tables III.B-7 and III.B-8 show the visibility benefits (visibility method 8, 

best 20% days background concentrations) of the two control options.

 

40 See “Impact of Ammonia in Fly Ash on its Beneficial Use,” Memorandum from Nancy Jones and Stephen 

Edgerton, EC/R Incorporated, to Anita Lee, U.S. EPA/Region 9, August 31, 2010.

41 AZ_BART_sources_all-Task7-8_2012-08-29.xls
Page 28 of 133

Table III.B-7: NOX Control Option Modeling Results, Visibility Impacts

Class I Area

Control Scenario

Base 

case

SNCR

(ctrl04)

SCR

(ctrl08)

Chiricahua NM 0.43 0.40 0.31

Chiricahua Wild. 0.51 0.46 0.36

Galiuro Wild. 1.10 0.98 0.76

Gila Wild. 0.17 0.15 0.13

Mazatzal Wild. 0.19 0.17 0.15

Mount Baldy Wild. 0.15 0.13 0.12

Pine Mountain Wild. 0.15 0.14 0.12

Saguaro NP 3.40 3.17 2.62

Sierra Ancha Wild. 0.19 0.18 0.15

Superstition Wild. 0.32 0.30 0.27

Saguaro NP east 3.37 3.14 2.59

Saguaro NP west 2.56 2.35 1.93

Maximum 3.40 3.17 2.62

Cumulative (sum) 6.60 6.08 4.99

Number of areas >= 0.5 

dv 3 2 2

Table III.B-8: NOX Control Option Modeling Results, Visibility Benefits

Class I Area

Control Scenario

Base 

case

SNCR

(ctlr04)

SCR

(ctrl08)

Chiricahua NM 0.03 0.12

Chiricahua Wild. 0.05 0.15

Galiuro Wild. 0.12 0.34

Gila Wild. 0.02 0.04

Mazatzal Wild. 0.02 0.04

Mount Baldy Wild. 0.01 0.03

Pine Mountain Wild. 0.02 0.03

Saguaro NP 0.23 0.78

Sierra Ancha Wild. 0.01 0.04

Superstition Wild. 0.01 0.05

Saguaro NP east 0.23 0.78

Saguaro NP west 0.21 0.63

Maximum 0.23 0.78

Cumulative (sum) 0.52 1.61
Page 29 of 133

Number of areas >= 0.3 

dv 0 2

Step 5 – Select BART

The results of our five-factor analysis are summarized in Table III.B- below. We note that the 

remaining useful life of the source is reflected in the evaluation of cost of compliance through 

the use of a 20-year amortization period in control cost calculations. The presence of existing 

pollution control technology is reflected in the cost and visibility factors as a result of selection 

of the baseline period for cost calculations and visibility modeling that reflects the use of the 

existing control technology. In examining energy and non-air quality impacts, we note certain 

potential impacts resulting from the use of ammonia injection associated with the SNCR and 

SCR control options, but do not consider these impacts sufficient enough to warrant eliminating 

any of the available control technologies. 

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that each of the available 

NOX control options achieves some degree of visibility improvement, and that the most stringent 

option, SCR, has the highest anticipated visibility improvement at a single Class I area at 0.78

dv. This is approximately three times the improvement anticipated for the next most stringent 

option, SNCR. 

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option. 

The most stringent option, SCR, also exhibits the highest average cost effectiveness at 

$5,176/ton, and has an incremental cost effectiveness relative to SNCR of $6,174/ton. 

We propose to find that BART for NOx is an emission limit of 0.36 lb/MMBtu on a rolling 30-

day boiler operating day (BOD) basis that is achievable by SNCR with LNB and OFA. The 

primary factors supporting this proposed finding are the average cost-effectiveness and 

anticipated visibility benefits of controls. In particular, while SCR is anticipated to achieve the 

greatest degree of visibility improvement, it is also significantly more expensive than SNCR, 

with an average cost-effectiveness of $5176/ton. We do not consider this average cost to be 

warranted by the projected visibility benefit of SCR for this facility.

We are also seeking comment on the appropriate NOX emission limit and compliance schedule 

for Sundt Unit 4. For SNCR, we propose an emission limit of 0.36 lb/MMBtu on a 30-day (boiler 

operating day [BOD]) rolling basis. In proposing this emission limit, we considered the annual 

average design value of 0.31 lb/MMBtu, as well as the need to account for emissions associated 

with startup and shutdown events. In order to account for this variability, we examined the 

difference between the highest 30-day rolling NOX value and the highest annual average NOX

value observed over the 2008-11 period, which is approximately 17%.42 We have applied this 

variability to the annual average design value to develop a 30-day (BOD) rolling emission limit, 

 

42 “TEP Sundt4 2001-12 CAMD Emissions.xlsx”.
Page 30 of 133

which we consider to provide sufficient margin for a limit that will apply at all times, including 

periods of startup and shutdown. . 

We propose to require compliance with this requirement within three years of the effective date 

of the final rule. A 2006 Institute of Clean Air Companies (ICAC) study indicated that the 

installation time for a typical SNCR retrofit, from bid to startup-up, is 10-13 months.43 However, 

because we are also requiring the installation of additional SO2 controls (as discussed in the 

sections below), we consider a three year period for compliance with both BART determinations 

to be appropriate. We are seeking comment on whether this compliance date is reasonable and

consistent with the requirement of the Clean Air Act that BART be installed “as expeditiously as 

practicable but in no event later than five years after [promulgation of the applicable FIP].”44 If 

we receive information during the comment period that establishes that a different compliance 

timeframe is appropriate, we may finalize a different compliance date.

Finally, we are proposing regulatory text that includes monitoring, reporting, and recordkeeping 

requirements to ensure that the emission limit and compliance deadline are enforceable.

Table III.B-9: NOX Five-factor Analysis Summary

Units

LNB+OFA 

(baseline) SNCR+LNB SCR+LNB

Unit Size (MW) 130

Emission Factor (lb/MMBtu) 0.445 0.312 0.05

Emission Rate (tpy) 1310 917 147

Emission Reduction (tpy) -- 393 1,162

Control Effectiveness -- 30% 89%

Cost of Compliance

Capital Cost $ -- $3,079,089 $45,167,561

Annualized Capital Cost $ -- $290,644 $4,263,498

Annual O&M $ -- $975,124 $1,753,975

Total Annual Cost $ -- $1,265,768 $6,017,474

Ave Cost Effectiveness ($/ton) -- $3,222 $5,176

Incremental Cost Effectiveness ($/ton) -- -- $6,174

Remaining Useful Life

Control technology amortization period 20 years 20 years

Energy Impacts

Energy impacts have been reflected in annual O&M costs in the costs of compliance

Non-air quality Environmental Impacts

SCR and SNCR may create potential safety and environmental hazards from the 

transportation and handling of anhydrous ammonia. We consider these impacts manageable 

 

43 See “Typical Installation Timelines for NOx Emissions Control Technologies on Industrial Sources”, Institute of 

Clean Air Companies, December 4, 2006.

44 Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4). 
Page 31 of 133

with the development of an RMP and additional safety procedures, and do not consider them 

sufficient enough to warrant eliminating either of these available control technologies.

Visibility Improvement

Single Largest Class I Improvement (dv) -- 0.23 0.78

Single Class I Area Cost Effectiveness ($/dv) -- $5,503,339 $7,714,710

Areas ≥ 0.50 dv improvement -- 0 1

Cumulative Visibility Improvement (dv) -- 0.52 1.63

Cumulative Class I Area Cost 

Effectiveness ($/dv) -- $2,434,169 $3,691,702

III.B.6 SO2 BART Analysis

Step 1 – Identify all available technologies

Fuel Supply Change

We note that since it was originally constructed as a natural gas fired boiler, Sundt Unit 4 has 

been using natural gas a primary fuel for significant periods of time since 2009. While a change 

in fuel supply to natural gas instead of coal is an inherently less polluting option, the BART 

Guidelines do not require fuel supply changes to be considered as a control option.45 As a result, 

this option is not considered further in our five-factor BART analysis, but is discussed as 

potential “better-than-BART” alternative in section VII below.

Lime or limestone-based wet Flue Gas Desulfurization (FGD)

Wet scrubbing systems mix an alkaline reagent, such as hydrated lime or limestone, with water 

to generate a scrubbing slurry. The alkaline slurry is then sprayed countercurrent to the flue gas, 

such as in a spray tower, or the flue gas may be bubbled through the alkaline slurry as in a jet 

bubbling reactor. As the alkaline slurry contacts the exhaust stream, it reacts with the SO2 in the 

flue gas. Design variations may include changes to increase the alkalinity of the scrubber slurry, 

increase slurry/ SO2 contact, and minimize scaling and equipment problems. Insoluble calcium 

sulfite (CaSO3) and calcium sulfate (CaSO4) salts are formed in the chemical reaction that occurs 

in the scrubber, and exits as part of the scrubber slurry. The salts are eventually removed and 

handled as a solid waste by-product. The waste byproduct is mainly CaSO3, which is difficult to 

dewater. Solid waste by-products from wet lime scrubbing are typically managed in dewatering 

ponds and landfills.

Lime spray dry absorber (SDA or dry FGD)

A spray dryer absorber uses a stream of either dry lime or hydrated lime (semi-dry) into a 

reaction tower where it reacts with SO2 in the flue gas to form calcium sulfite solids. Unlike wet 

FGD systems that produce a slurry byproduct that is collected separately from the fly ash, dry 

FGD systems are designed to produce a dry byproduct that must be removed with the fly ash in 

the particulate control equipment. As a result, dry FGD systems must be located upstream of the 

particulate control device to remove the reaction products and excess reactant material. In 

instances where hydrated lime is used as a reagent, the reaction towers must be designed to 

 

45 40 CFR 51, Appendix Y, Section IV.D.1.5, STEP 1: How do I identify all available retrofit emission control 

techniques?
Page 32 of 133

provide adequate contact and residence time between the exhaust gas and the slurry to produce a 

relatively dry by product. Typical process equipment associated with a spray dryer typically 

includes an alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate 

control device and a recycle system. The recycle system collects solid reaction products and 

recycles them back to the spray dryer feed system to reduce alkaline sorbent use.

Dry Sorbent Injection (DSI)

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas

exhaust stream. Dry sorbent injection systems are simple systems, and generally require a

sorbent storage tank, feeding mechanism, transfer line and blower and an injection device. The 

dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber is often 

located downstream of the injection point to increase residence time and efficiency. Particulates 

generated in the reaction are controlled in the system’s particulate control device. DSI requires 

less capital equipment, less physical space, and less modification to existing ductwork compared 

to a SDA system. However, reagent costs are much higher and depending upon the absorbent 

and amount of sorbent injected, control efficiency is lower when compared to a SDA system. 

Soda ash and trona (sodium sesquicarbonate) are potential options.

Step 2 – Eliminate technically infeasible options

Each of the control options identified in Step 1 has certain design concerns and constraints 

associated their implementation, which have been discussed briefly below. Despite these issues, 

each of the options listed in Step 1 are considered technically feasible.

Lime or limestone-based wet FGD 

Design concerns associated with wet FGD involve the substantial water usage requirements 

needed to generate the alkaline reagent slurry, as well as the substantial amount of wastewater 

and solid waste discharge associated with the spent byproduct. A wet FGD control system must 

be located after the fabric filter baghouse because the moist plume resulting from the wet 

scrubber system would create baghouse plugging issues if the control is placed ahead of the 

baghouse. In addition, a substantial footprint is required for the management of these waste 

products, as well as for the absorber tower and associated process equipment such as the slurry 

preparation, mixing, associated tanks, dewatering activities. While these design concerns do 

present some challenges, they do not warrant elimination of this option as technically 

infeasible.46

Dry Sorbent Injection

An important design consideration of DSI is the ability of the downstream particulate control 

device to accommodate the additional particulate loading resulting from the addition of the DSI 

reagent into the boiler flue gas. 

Lime spray dry absorber (SDA or dry FGD)

 

46 TEP’s review does not eliminate consideration of wet FGD, but does describe several design challenges that TEP 

notes should be reflected in the five factor analysis. We have incorporated certain elements of TEP’s review in our 

analysis, as discussed in Step 4 below. 
Page 33 of 133

As noted previously, a dry FGD system must be installed prior to the fabric filter baghouse in 

order for the reagent to be captured and recycled. As noted in our contractor’s report, the location 

of the existing fabric filter baghouse does not present enough space to install a new absorber 

between the boiler and the existing baghouse. As a result, a dry FGD at Sundt Unit 4 is assumed 

to include a new baghouse, which has been reflected in the costs of compliance in the five-factor 

analysis. 

Step 3 – Evaluate control effectiveness of remaining control technologies

The control effectiveness for dry FGD and wet FGD was determined, as noted in our contractor’s 

report, by estimating that newly constructed FGD systems could achieve design emission rates 

(annual average basis) of 0.08 lb/MMBtu and 0.06 lb/MMBtu, respectively. Relative to baseline 

SO2 emission rates, this corresponds to control efficiencies of 89% and 92%. We recognize that 

FGD systems have been designed to achieve more stringent design emission rates and have 

demonstrated an ability to achieve control efficiencies up to 98%. Our contractor’s report notes 

that these control efficiencies are regarded as conservative estimates (e.g., underestimated in this 

context). While these are not the most stringent levels of control that the technology is capable of 

achieving, we consider 89% and 92% control efficiencies to be consistent with the median values 

reported for FGD systems. 

For DSI, our contractor used a control effectiveness of 75%, as noted in the Contractor’s Report.

In a review of SO2 control options for BART eligible units, the Northeast States for Coordinated 

Air Use Management (NESCAUM) estimated control effectiveness for DSI in a range of 40-

60%.47 More recently, as part of work done as part of the Integrated Planning Model (IPM), EPA 

has estimated control effectiveness as high as 80%,48 depending upon factors such as the type of 

sorbent, the quantity of sorbent used, and the type of particulate control device employed.

Generally, the use of more effective particulate control devices allow for higher rates of sorbent 

injection, and therefore greater DSI effectiveness. Since Sundt Unit 4 operates with a fabric 

filter, we consider a control effectiveness value in the upper range appropriate, and have used 

70% control effectiveness in our calculations. This value is above the range indicated in the 

NESCAUM study, but does not involve the high sorbent injection rates required to achieve the 

upper range of indicated in IPM documentation. A summary of the remaining control 

technologies and their associated control effectiveness is presented in Table III.B- below.

Table III.B-10: SO2 Control Options

Control Option Control 

Effectiveness 

(%)

Dry Sorbent Injection (DSI) 70%

Lime spray dry absorber 

(SDA or dry FGD)

89%

Lime or limestone based wet 

FGD

92%

 

47 "Assessment of Control Technology Options for BART-Eligible Sources", Northeast States for Coordinated Air 

Use Management In Partnership with The Mid-Atlantic/Northeast Visibility Union, March 2005

48 IPM Model – Revisions to Cost and Performance for APC Technologies, Dry Sorbent Injection Cost 

Development Methodology, August 2010
Page 34 of 133

Step 4 – Evaluate BART factors 

Factor 1: Costs of compliance

In evaluating the costs of compliance for each of the control options we considered, we 

calculated the control costs ($) and emission reductions (tons/year of pollutant) for each 

control technology, and developed average cost effectiveness ($/ton) values for each 

option. Emission reductions for each option are summarized in Table III.B-12 below. A 

more detailed version of emission calculations can be found in our docket,

49 and in our 

contractor’s report. As noted in our NOX BART analysis above, the heat duty and 

capacity factor used in the calculations summarized below differ from the values used in 

the calculations originally prepared by our contractor because the maximum gross 

capacity of Sundt Unit 4 while burning coal is approximately 130 MW. The heat duty 

(MMBtu/hr) and capacity factor used below reflect the coal-burning nameplate 

capacity.50

Table III.B-12: SO2 Control Option Emission Estimates

Control Option

Control 

Efficiency

Emission 

Factor Heat Duty Capacity

SO2 Emission 

Rate

SO2 Emission 

Reduction

% (lb/MMBtu) (MMBtu/hr) Factor (lb/hr) (tpy) (tpy)

Baseline (no ctrl) -- 0.729 1,371 0.49 1,000 2,145 --

DSI 70% 0.219 1,371 0.49 300 644 1,502

DFGD 89% 0.080 1,371 0.49 110 236 1,909

WFGD 92% 0.060 1,371 0.49 82 177 1,969

A summary of these cost calculations is presented below. Detailed cost calculations can 

be found in the docket.51

Table III.B-13: SO2 Control Option Cost Effectiveness

Control 

Option

Capital 

Cost

Annualized 

Capital 

Cost

Annual 

Operating 

Cost

Total 

Annual 

Cost

Emission 

Reduction

Cost Effectiveness 

($/ton)

($) ($) ($) ($/yr) (tpy) Ave Incremental

DSI $3,250,000 $306,777 $2,482,116 $2,788,893 1,502 1,857 --

DFGD $72,470,559 $6,840,708 $2,880,841 9,721,549 1,909 5,091 17,007

WFGD $80,629,663 $7,610,870 $3,227,467 10,838,337 1,969 5,505 18,795

Factor 2: Presence of existing control technology

 

49 See spreadsheet titled “TEP Sundt4 2001-12 CAMD Emissions.xlsx”

50 As noted by TEP and Burns and McDonnell, although the calculated capacity factor is different, the annual 

emissions in tons per year removed do not change significantly, as the change in capacity factor is largely offset by 

the change in maximum unit gross rating.

51 See spreadsheet titled “TEP Sundt4 Control Costs (final for NPRM docket).xlsx”.
Page 35 of 133

The presence of existing pollution control technology at Sundt Unit 4 is reflected in our 

BART analysis in two ways: first, in the consideration of available control technologies, 

and second, in the development of baseline emission rates for use in cost calculations and 

visibility modeling. In the case of SO2, Sundt Unit 4 does not operate with any existing 

control technology. This is reflected in our selection of CY2011 as the baseline period, 

which represents uncontrolled coal-fired emissions.

Factor 3: Remaining useful life of the source

We are considering the “remaining useful life” of Sundt Unit 4 as one element of the 

overall cost analysis as allowed by the BART Guidelines. Since we are not aware of any 

federally- or State-enforceable shut-down date for any of the affected sources, we have 

used a 20-year amortization period described in the EPA Cost Control Manual as the 

remaining useful life for the control options considered for Sundt Unit 4.

Factor 4: Energy and non-air quality environmental impacts

For wet FGD, energy impacts include certain auxiliary power requirements that are 

necessary for operation of the wet FGD system, and to potentially compensate for 

pressure head loss through the scrubber. These energy impacts have been reflected as 

auxiliary power costs in the cost of compliance estimates. Non-air quality environmental 

impacts include water usage requirements and the storage and disposal of wet ash. Wet

FGD requires very large quantities of water in order to ensure proper control 

effectiveness. Securing such quantities of water is a significant challenge in more arid 

regions of the country such as Arizona, and would preclude the use of that water for 

potentially more beneficial uses. The on-site storage and disposal of wet ash in large 

retention ponds triggers significant additional regulatory requirements, as it represents a 

substantial water pollution threat. 

For dry FGD, the energy and non-air environmental impacts are similar to those for wet 

FGD. Operation of a dry FGD still requires securing significant supplies of water, 

although to a lesser degree than with wet FGD systems. In addition, dry FGD systems 

will result in generation of larger quantities of boiler ash, and has the potential to 

negatively affect the properties and quality of boiler ash. In some instances, boiler ash 

that is suitable to be sold for beneficial purposes may not longer be marketable following 

installation of a dry FGD system. Energy impacts also include auxiliary power 

requirements for operation of the dry FGD system, and for overcoming pressure head loss 

through the scrubber. 

DSI could potentially have an adverse effect on the quality of the boiler fly ash, which 

would make it unmarketable for beneficial uses. In addition, use of DSI also results in an 

ash by-product which would require landfill disposal, thereby increasing solid waste 

generation rates at the plant. Energy impacts are limited to auxiliary power requirements 

for operation of the DSI system. 

Factor 5: Visibility improvement
Page 36 of 133

The overall visibility modeling approach is described in Section III. Baseline emission 

rates, control option emission rates, and stack parameters used in NOX control scenario 

modeling can be found in the model emission rate spreadsheet prepared by our 

contractor.52 Tables III.B-14 and III.B-15 provide the visibility benefits (visibility method 

8, best 20% days background concentrations) of the three control options.

Table III.B-14: SO2 Control Option Modeling Results, Visibility Impacts

Class I Area

Control Scenario

Base 

case

DFGD

(ctrl02)

WFGD

(ctrl03)

DSI 70%

(ctrl14)

Chiricahua NM 0.43 0.36 0.37 0.38

Chiricahua Wild. 0.51 0.41 0.40 0.41

Galiuro Wild. 1.10 0.94 1.01 1.00

Gila Wild. 0.17 0.12 0.12 0.13

Mazatzal Wild. 0.19 0.11 0.10 0.12

Mount Baldy Wild. 0.15 0.09 0.09 0.10

Pine Mountain Wild. 0.15 0.09 0.09 0.10

Saguaro NP 3.40 3.57 3.67 3.21

Sierra Ancha Wild. 0.19 0.11 0.10 0.12

Superstition Wild. 0.32 0.22 0.22 0.23

Saguaro NP east 3.37 3.57 3.67 3.12

Saguaro NP west 2.56 2.57 2.60 2.30

Maximum 3.40 3.57 3.67 3.21

Cumulative (sum) 6.60 6.01 6.17 5.80

Number of areas >= 0.5 

dv 3 2 2 2

Table III.B-15: SO2 Control Option Modeling Results, Visibility Benefits

Class I Area

Control Scenario

Base 

case

DFGD

(ctrl02)

WFGD

(ctrl03)

DSI 70%

(ctrl14)

Chiricahua NM 0.07 0.06 0.05

Chiricahua Wild. 0.10 0.11 0.10

Galiuro Wild. 0.16 0.09 0.10

Gila Wild. 0.05 0.05 0.04

Mazatzal Wild. 0.08 0.09 0.07

Mount Baldy Wild. 0.05 0.06 0.05

 

52 AZ_BART_sources_all-Task7-8_2012-08-29.xls
Page 37 of 133

Pine Mountain Wild. 0.06 0.06 0.05

Saguaro NP -0.16 -0.27 0.20

Sierra Ancha Wild. 0.08 0.08 0.06

Superstition Wild. 0.10 0.10 0.09

Saguaro NP east -0.20 -0.30 0.25

Saguaro NP west -0.02 -0.04 0.26

Maximum 0.16 0.11 0.20

Cumulative (sum) 0.59 0.43 0.80

Number of areas >= 0.3 

dv 0 0 0

Note: Saguaro NP East and West values not included in cumulative. For DFGD and WFGD, cumulative impact 

includes the predicted visibility disbenefit at Saguaro NP.

Step 5 – Select BART

The results of our five-factor analysis are summarized in Table III.B-16 below. We note that the 

remaining useful life of the source is reflected in the evaluation of cost of compliance through 

the use of a 20-year amortization period in control cost calculations. Since there is no existing 

SO2 control technology in use in the plant, baseline emissions reflect uncontrolled SO2

emissions. In examining energy and non-air quality impacts, we note certain potential impacts 

resulting from the water resource requirements associated with wet FGD, as well as the 

additional solid waste generation associated with dry and wet FGD, but do not consider these 

impacts sufficient enough to warrant eliminating any of the available control technologies. 

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option.

Both dry and wet FGD have average cost effectiveness values much greater than DSI, which is a 

control option that we consider very cost effective at $1,857/ton. In addition, both dry and wet 

FGD have very high incremental cost effectiveness values, indicating that while they are more 

effective than the preceding control, this additional degree of effectiveness comes at a substantial 

cost.

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that each of the available 

SO2 control options achieves some degree of visibility improvement, although dry and wet FGD 

result in anticipated visibility disbenefit at a single Class I area (Saguaro). The visibility benefits

from FGD are substantially lower than those from DSI, and the visibility cost-effectiveness of 

each FGD is more than quadruple that of DSI. EPA finds that the improvement from DSI is 

substantial enough to support its selection as BART, and that it is clearly a better choice than dry 

FGD and wet FGD.

Consistent with the BART Guidelines, we are proposing an emission limit based on a 30-day 

(BOD) rolling average. In evaluating the appropriate emission limit for DSI, we considered the 

annual average design value for DSI of 0.21 lb/MMBtu, as well as the need to account for 

emissions associated with startup and shutdown events in developing the emission limit. In order 

to determine how to account for this variability, we examined the difference between the highest 
Page 38 of 133

30-day rolling SO2 value and the highest annual average SO2 value observed over the 2008-11 

period, which is approximately 9%.53 We have applied this variability to the annual average 

design value to develop a 30-day (BOD) rolling emission limit, which we consider to provide 

sufficient margin for a limit that will apply at all times. On this basis, we propose an emission 

limit of 0.23 lb/MMBtu on a 30-day (BOD) rolling basis.

We propose to require compliance with this requirement within three years of the effective date 

of the final rule. However, we are seeking comment on whether this compliance date is 

reasonable and consistent with the requirement of the Clean Air Act that BART be installed “as

expeditiously as practicable but in no event later than five years after [promulgation of the 

applicable FIP].”54 If we receive information during the comment period that establishes that a 

different compliance timeframe is appropriate, we may finalize a different compliance date.

In addition, we are also proposing regulatory text that includes monitoring, reporting, and 

recordkeeping requirements associated with this emission limit.

Table III.B-8: SO2 Five-factor Analysis Summary

Units

No ctrl 

(baseline) DSI DFGD WFGD

Unit Size (MW)

Emission Factor (lb/MMBtu) 0.729 0.219 0.08 0.06

Emission Rate (tpy) 2145 644 236 177

Emission Reduction (tpy) -- 1,502 1,909 1,969

Control Effectiveness -- 70% 89% 92%

Cost of Compliance

Capital Cost $ -- $3,250,000 $72,470,559 $80,629,663

Annualized Capital Cost $ -- $306,777 $6,840,708 $7,610,870

Annual O&M $ -- $2,482,107 $2,880,841 $3,227,467

Total Annual Cost $ -- $2,788,884 $9,721,549 $10,838,337

Ave CE ($/ton) -- $1,857 $5,091 $5,505

Incremental CE ($/ton) -- -- $17,007 $18,795

Remaining Useful Life

Control technology amortization period 20 years 20 years 20 years

Energy Impacts

Energy impacts have been reflected in annual O&M costs in the costs of compliance

Non-air quality Environmental Impacts

Wet and dry FGD involve on-site storage and disposal of wet ash that represents a substantial water pollution threat.

Wet and dry FGD have water resource requirements; potentially precludes the use of that water for potentially more 

beneficial uses.

Visibility Improvement

 

53 See spreadsheet titled “TEP Sundt4 2001-12 CAMD Emissions.xlsx”.

54 Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4). 
Page 39 of 133

Single Largest Class I Improvement (dv) -- 0.20 0.16 0.11

Single Class I Area Cost 

Effectiveness ($/dv) -- $13,944,466 $60,759,680 $98,530,339

Areas ≥ 0.50 dv Improvement -- 0 0 0

Cumulative visibility Improvement (dv) -- 0.80 0.59 0.43

Cumulative Class I Area Cost 

Effectiveness ($/dv) -- $3,486,116 $16,477,201 $25,205,436

III.B.7 BART Alternative

We are proposing a switch to natural gas on Sundt Unit 4 as a better-than-BART alternative to 

the emissions controls previously proposed in this section for a coal-fired unit. Unit 4 was 

originally constructed as a natural gas-fired boiler, and has used natural gas as a primary fuel for 

significant periods of time since 2009. While a change in fuel supply to natural gas instead of 

coal is an inherently less polluting option, the BART Guidelines do not require the consideration 

of fuel supply changes as a control option.55 As a result, the option of burning only natural gas is 

not considered in our BART analysis. However, TEP has submitted to EPA an alternative to 

BART based on the elimination of coal as a fuel source for Sundt Unit 4 by December 31, 2017. 

As part of this submittal, TEP compared the potential emission reductions and visibility benefit 

between a natural gas fuel change and certain combinations of NOx and SO2 controls.56

EPA has evaluated this alternative proposal pursuant to the “better-than-BART” provisions of 

the RHR. In particular, the RHR allows for implementation of “an emissions trading program or 

other alternative measure” in lieu of BART if the alternative measure achieves greater reasonable 

progress than would be achieved through the installation and operation of BART.57 The rule 

further states that “[i]f the distribution of emissions is not substantially different than under 

BART, and the alternative measure results in greater emissions reductions, than the alternative 

measures may be deemed to achieve greater reasonable progress”.58 Because the emissions 

reductions under EPA's BART proposal for Sundt Unit 4 and the reductions from TEP’s 

proposed alternative would occur at the same facility, the distribution of emissions under BART 

and the alternative are not substantially different. Therefore, if the alternative emission control 

strategy results in greater emissions reductions than our BART proposal, EPA may deem the 

alternative emission control strategy to achieve greater reasonable progress.

As part of our review of TEP’s proposal, we have examined Unit 4’s historical operation. A 

summary of Sundt Unit 4 NOX emission rates during these periods of natural gas usage are 

included in Table III.B-9 below, based on CAMD emission data.

 

55 40 CFR 51, Appendix Y, Section IV.D.1.5, “STEP 1: How do I identify all available retrofit emission control 

techniques?”

56 See letter from TEP dated November 1, 2013 regarding TEP Sundt Unit 4 BART Alternative.

57 40 CFR 51.308(e)(2).

58 40 CFR 51.308(e)(3).
Page 40 of 133

Table III.B-9: Natural Gas Operations Emission Summary59

Year Start Date End Date NOX Emissions Heat Rate NOX Emission Factor

(tpy) (MMBtu/yr) (lb/MMBtu)

2009 2/24/2009 9/30/2009 337 3,019,513 0.22

2010 8/27/2010 1/4/2011 278 2,160,125 0.26

2011 -- -- -- -- --

2012 1/15/2012 11/3/2012 713 5,197,211 0.27

As seen above, Sundt Unit 4 has achieved NOX emission rates between 0.22 and 0.27 lb/MMBtu 

when operating on natural gas with LNB and OFA. SO2 emissions over these periods are 

approximately 0.0055 lb/MMBtu. By comparison, EPA estimates default SO2 emission factors 

for natural gas of approximately 0.00064 lb/MMBtu.60 For particulate matter, EPA estimates 

default PM10 emission factors for natural gas of 0.0076 lb/MMBtu.61 A comparison of natural 

gas and BART emission rates, based on a proposed NOX BART determination of SNCR, is 

presented below.

Table III.B-18: BART Alternative

Parameters Units

BART 

Determination

Natural 

Gas Fuel 

Switch Difference

Heat Duty MMBtu/hr 1,371 1,828

Capacity Factor 0.49 0.37

NOX Ctrl Tech SNCR+LNB+OFA LNB+OFA

lb/MMBtu10.31 0.22

tpy 917 652 265

Particulate 

Matter Ctrl Tech Fabric Filter None

lb/MMBtu10.03 0.01

tpy 88 30 59

SO2 Ctrl Tech

Dry Sorbent 

Injection None

lb/MMBtu10.22 0.00064

tpy 644 1.9 642

1 Annual average emission factors

As seen in Table III.B-18, a natural gas fuel switch as based upon a 0.22 lb/MMBtu (annual 

average) NOx emission factor, achieves lower emission factors and lower annual emissions than 

the BART determinations for each of the individual pollutants. Therefore, we propose to find 

that TEP’s proposed BART alternative meets the requirements of 40 CFR 51.308(e)(3).

 

59 See spreadsheet titled “TEP Sundt4 2001-12 CAMD Emissions.xlsx”.

60 Per AP-42 (7/98), Table 1.4-2, which lists an emission factor of 0.60 lb/MMSCF, which converts to 0.0006 

lb/MMBtu based on a natural gas heating value of 1000 BTU/SCF.

61 Per AP-42 (7/98), Table 1.4-2, based on filterable and condensable PM.
Page 41 of 133

Although visibility modeling is not required to support a better-than-BART determination in this 

instance, EPA conducted modeling to verify the visibility benefits of the proposed alternative, as 

compared with EPA’s BART determination.

This modeling was performed using approach described in Section III, and is based on the 

percent reduction attributable to the natural gas emission factors listed in Table III.B-18. Table 

III.B-19 summarizes the visibility benefits (visibility method 8, best 20% days background 

concentrations) for the natural gas fuel switch, and for the aggregate BART determinations 

(SNCR combined with DSI). 

Table III.B-19: BART Alternative Visibility Results

Class I Area Distance 

(km)

Visibility 

Impact

Visibility 

Improvement 

Base Case

SNCR; 

DSI 70%

(ctrl15)

Natl gas 

.22lb

(ctrl13)

Chiricahua NM 144 0.43 0.09 0.19

Chiricahua Wild. 141 0.51 0.16 0.25

Galiuro Wild. 64 1.10 0.24 0.47

Gila Wild. 232 0.17 0.06 0.10

Mazatzal Wild. 203 0.19 0.08 0.12

Mount Baldy Wild. 232 0.15 0.06 0.09

Pine Mountain Wild. 247 0.15 0.06 0.09

Saguaro NP 17 3.40 0.49 1.06

Sierra Ancha Wild. 178 0.19 0.08 0.12

Superstition Wild. 137 0.32 0.11 0.19

Cumulative (sum) 6.6 1.4 2.7

Maximum 3.40 0.49 1.06

# CIAs >= 0.5 dv 3 0 1

Since Sundt is only 17 km from the eastern unit of Saguaro, its emitted NOx may not be fully 

converted to NO2 by the time it reaches there, as is assumed in the CALPUFF model. It thus may 

not be fully available to form visibility-degrading particulate nitrate. EPA explored this issue in 

CALPUFF sensitivity simulations described in the TSD. For EPA’s proposed BART of SNCR 

plus DSI, the visibility improvement remains above 0.3 dv even when unrealistically low 10 

percent NO-to-NO2 conversion is assumed (i.e., no additional conversion of NO to NO2 once the 

plume leaves the stack). The improvement from switching to natural gas remains above 0.7 dv at 

Saguaro. These results show that the FIP’s proposed BART determination remains reasonable 

despite any concern over the NO conversion rate; the visibility improvement from BART 

remains substantial. The finding that natural gas provides better visibility improvement than the 

proposed BART determination also remains sound regardless of the NO conversion assumed.
Page 42 of 133

Based on this information, we consider a natural gas fuel switch to result in greater emission 

reductions and achieve greater reasonable progress than the proposed BART determinations. 

Under this scenario, we are proposing a NOx emission limit of 0.25 lb/MMBtu based on a 30-day 

BOD rolling average. As discussed previously in the NOx BART determination, this represents 

about a 17% increase from the annual average emission rate of 0.22 lb/MMBtu, which we 

consider to provide sufficient margin for a limit that will apply at all times, including periods of 

startup and shutdown. In addition, we are proposing particulate matter and SO2 emission limits 

consistent with natural gas use, as well as monitoring, reporting, and recordkeeping 

requirements.

III.C. Lhoist Nelson Lime Plant

III.C.1. Summary

This five factor analysis documents the basis for determination of the Best Available Retrofit 

Technology (BART) for control of sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate 

matter (PM) emissions at the Lhoist North America (LNA) of Arizona, Inc. Nelson Lime Plant 

(Nelson Plant), a limestone processing and lime manufacturing plant near Peach Springs in 

Yavapai County, Arizona. The facility’s address is 2.5 miles south of US 66, Mile Marker 112, 

Peach Springs, AZ 86434 (approximately six miles east of Peach Springs).

This analysis is based on the following documents:

 BART Five Factor Analysis, Lhoist North America Nelson Lime Plant; Prepared by 

Trinity Consultants in Conjunction with Lhoist North America of Arizona, Inc.; Project 

131701.0061; August 13, 2013 (Public version dated September 27, 2013).

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 7: Five-Factor 

BART Analysis for Chemical Lime Company Nelson, TEP Sundt (Irvington), and 

Catalyst Paper (Snowflake) Plants, Contract No. EP-D-07-102, Work Assignment 5-12; 

Prepared for EPA Region 9 by University of North Carolina at Chapel Hill, ICF 

International, and Andover Technology Partners; October 9, 2012 (“Contractor’s 

Report”).

 Title V Operating Permit and Technical Support Document for the Nelson Lime Plant, 

Permit # 42782, Issued August 8, 2011 by the Arizona Department of Environmental 

Quality.

EPA conducted a five step analysis, with step four incorporating the five factor analysis, in 

accordance with BART guidelines.62 This analysis consists of the following steps:

Step 1 -- Identify all available technologies

Step 2 -- Eliminate technically infeasible options

Step 3 -- Evaluate control effectiveness of remaining control technology

 

62 See July 6, 2005 BART guidelines, 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations.
Page 43 of 133

Step 4 -- Evaluate impact on emissions and document the results

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5: Evaluate visibility impacts

Step 5 – Select BART

As described in the following sections, we are proposing the following BART limits for 

Chemical Lime Company – Nelson Lime Plant as based on the corresponding technology 

listed in Table III.C-1.

Table III.C-1: Summary of Proposed BART determinations

Pollutant Emission Limit

(lb/ton feed)

Control Technology1

Kiln 1

NOX 3.80 Selective Non-Catalytic Reduction (SNCR)

PM10 0.12 Fabric filter baghouse (existing)

SO2 9.32 Lower sulfur fuel

Kiln 2

NOX 2.61 Selective Non-Catalytic Reduction (SNCR)

PM10 0.12 Fabric filter baghouse (existing)

SO2 9.73 Lower sulfur fuel

1

These control technologies are only listed for reference, as the facility is not required to install the 

listed technology to meet the BART limit.

III.C.2. Facility Description

The Nelson Lime Plant processes and manufactures lime from limestone. Figure 1 shows an 

aerial view of the facility.

Figure 1: Chemical Lime Company – Nelson Lime Plant
Page 44 of 133

The limestone processing plant consists of the following principal operations: a quarry mining 

operation, a limestone crushing and screening operation, a limestone kiln feed system, a solid 

fuel handling system, two rotary lime kilns, front and back lime handling systems, a lime 

hydrator, diesel electric generators, fuel storage tanks, and other support operations and 

equipment. The basic processes in the production of lime are: (1) quarrying raw limestone; (2) 

preparing limestone for the kilns by crushing and sizing; (3) calcining the limestone; (4) 

processing the lime further by hydrating; and (5) miscellaneous transfer, storage, and handling 

operations. The limestone processing operations consist of two quarries, a crushing and 

screening plant, and auxiliary operations.

The lime manufacturing equipment consists of two lime rotary kilns (Kiln 1 and Kiln 2) and 

auxiliary equipment necessary for receiving crushed limestone, processing it through the lime 

kilns, and processing the lime kiln product. Operations include pre-kiln limestone handling, two 

lime kilns, post-kiln handling, a hydrator, two peak demand generators, truck and rail loadout 

facilities, and solid fuel handling. The lime kilns are used to convert crushed limestone (CaCO3) 

into quicklime (CaO).

Emissions from this facility include SO2, NOx and PM. Air pollution control equipment applied 

at the Nelson Lime Plant includes a number of baghouses, two multicyclone dust collectors, and 

a Ducon wet scrubber to control particulate matter emissions. The facility does not currently 

have control equipment for NOx and SO2.

III.C.3 General Approach to Five-Factor BART Analysis

This section contains a general description of our approach to the five-factor analysis, and 

discusses certain elements of our approach that are common to each of the pollutant-specific 

analyses performed for the Nelson Plant. An initial BART analysis was performed by our 
Page 45 of 133

contractors, the University of North Carolina Institute on the Environment (UNC) and ICF 

International (ICF). This analysis is summarized in the final Contractor’s Report and associated 

modeling spreadsheets. LNA provided the results of its own five-factor BART analysis, 

including control cost estimates and visibility modeling, which we have reviewed and 

incorporated into the following analysis.

Factor 1: Costs of Compliance

Cost estimates 

Although capital costs were developed by our contractor, we have primarily relied upon the 

capital cost estimates included in LNA’s analysis, which are based on a combination of vendor 

quotes and experience from other plants. LNA has asserted a confidential business information 

(CBI) claim regarding many of its annual operating costs, such as certain fuel and production 

costs. We have developed our own estimate of operating costs based on a combination of 

publicly available information, algorithms developed by our contractor for the cement industry, 

and EPA’s Control Cost Manual. 

Baseline Emissions

LNA’s approach to establishing baseline emissions was to first establish baseline emission 

factors in lb/ton lime that represent realistic estimates of anticipated emissions and then to 

multiply the emission factors by the appropriate baseline production rates to obtain max daily 

and annual average emissions. These emission factors are based on lb/ton values observed during 

CEMS testing performed from March to June 2013. LNA also performed a statistical analysis of 

the 2013 CEMS data to develop emission factors that it considered to be representative of 

anticipated emissions. LNA considers the hourly average emission factors plus two standard 

deviations based on the March, May, and June 2013 testing, which is approximately equal to the 

95% confidence interval, to represent anticipated emission levels based on the statistical analysis. 

LNA notes that, in general, the emission calculations using this approach are higher than the 

maximum daily emission factors, but that this approach accounts for emissions variability.

When developing baseline emissions for calculating cost effectiveness, the BART guidelines 

state that “in general, for the existing sources subject to BART, you will estimate the anticipated 

annual emissions based upon actual emissions from a baseline period.” Since the Nelson Plant 

kilns do not operate with NOX or SO2 CEMS, continuously measured actual emissions are not 

available for the period of an entire year. In the absence of such measured emissions on an 

annual basis, we consider LNA’s use of an emission factor (lb/ton) multiplied by the highest 

annual lime production (ton/year) observed over the baseline period to be an appropriate 

approach. As noted by LNA, the use of the 95% confidence interval value for emission factor 

does result in the use of values that are generally higher than the observed maximum daily 

emission factors. In the context of a BART analysis, this approach results in a conservative 

estimate (i.e., tending to overestimate rather than underestimate, in this case) of control option 

performance, since it potentially overstates baseline emissions and baseline visibility impact, 

which in turn may overstate the anticipated emission reductions and visibility benefit that result 

from a control option. Nonetheless, given the lack of measured annual emissions data, we concur 

with LNA’s use of a conservative baseline emissions estimate and we have incorporated this 

estimate into our analysis.
Page 46 of 133

The baseline daily emission rates and associated production levels, and the baseline annual 

emission rates and associated production levels are shown in the following table.

Table III.C-2: Summary of Daily and Annual Baseline Emissions

Kiln Lime Production NOX SO2

Max 

Daily2

Max 

Annual3 Year

Emission 

Factor1 Emissions

Emission 

Factor1 Emissions

(tpd) (tpy) (lb/ton lime) (lb/day) (tpy) (lb/ton lime) (lb/day) (tpy)

Kiln 1 866 258,508 2010 7.59 6,573 981 12.15 10,522 1,570

Kiln 2 1,246 378,296 2012 5.21 6,492 985 12.69 15,812 2,400

1

Factors from March, May and June 2013 CEMS testing.

2 Maximum daily rates representing maximum rates that occurred during the March 2013 CEMS testing.

3 The annual lime production represents the highest annual production rate for each kiln from2001 to 2012.

Factor 2: Energy and Non-air Environmental Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common 

elements relating to this factor discussed here. Pollutant-specific discussions of these issues are 

included in the following sections. 

Factor 3: Pollution Equipment in Use at the Source

The presence of existing pollution control technology at each source is reflected in our BART 

analysis in two ways: first, in the consideration of available control technologies, and second, in 

the development of baseline emission rates for use in cost calculations and visibility modeling.

Pollutant-specific discussions of these issues are included in the following sections. 

Factor 4: Remaining Useful Life of the Source

We are considering each source's “remaining useful life” as one element of the overall cost 

analysis as allowed by the BART Guidelines.63 Since we are not aware of any enforceable shutdown date for the Nelson Plant, we have used a 20-year amortization period, as noted in the EPA 

Cost Control Manual, as the remaining useful life of the facilities considered in this proposed 

action.

Factor 5: Anticipated Degree of Visibility Improvement

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. Note that Lhoist North 

America’s contractor, Trinity Consultants, performed the modeling for the Nelson Lime Plant.

Lhoist’s BART Five Factor Analysis, Lhoist North America Nelson Lime Plant, cited above, 

 

63 40 CFR Part 51, Appendix Y, section IV.D.4.k.
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mainly presented visibility results using visibility method 8a, and focused on the highest 98th 

percentile impact from among 2001, 2002, and 2003. To put Nelson Lime on a footing 

comparable to the other facilities, EPA post-processed LNA’s modeling results in CALPOST 

using visibility methods 8a and 8b, and found the 98th percentile for the merged 2001-2003 

period. Full Nelson Lime modeling results, including for the 98th percentile in individual years, 

and for alternative visibility method 8a, can be found in the tables and bar graphs in TSD 

Appendix B and in the spreadsheet Nelson_Trinity_visibility_results.xlsx.

LNA performed dispersion modeling using the CALPUFF modeling system, which consists of 

the CALPUFF dispersion model, the CALMET meteorological data processor, and the 

CALPOST post-processing program. The specific program versions that were relied upon in the 

analysis match the program versions relied upon by our contractors in the BART analyses that 

they prepared for select sources, including the Nelson Plant.64 For CALMET, LNA’s analysis 

used meteorological data files provided to them by EPA. We have reviewed the CALPUFF and 

CALPOST input parameters, and have confirmed that the data and parameter settings relied upon 

in LNA’s visibility modeling are consistent with those relied upon in the Contractor’s Report.

65

The following table provides a summary of the stack parameters that were relied upon in the 

BART analysis. The temperatures and flow rates summarized in Table III.C-3 are the average 

temperatures and flow rates determined from data collected during emissions testing on the kilns 

conducted in March 2013. (Compared to the UNC work, LNA used updated higher base case SO2 and 

NOx emissions, lower PM emissions, and lower stack exit velocities.)

Table III.C-3: Summary of Kiln 1 and Kiln 2 Stack Parameters

Kiln

Stack 

Height

(ft)

Stack 

Height

(m)

Stack 

Diameter

(ft)

Stack 

Diameter

(m)

Exhaust 

Temp

(F)

Exhaust 

Temp

(K)

Exhaust 

Velocity

(ft/s)

Exhaust 

Velocity

(m/s)

Kiln 1 140 42.67 10 3.05 405 480.37 30.33 9.25

Kiln 2 141 42.98 10 3.05 434 496.48 35.12 10.71

III.C.4 BART Analysis for NOX

Step 1 -- Identify all available technologies

NOx is generated during fuel combustion by oxidation of chemically-bound nitrogen in the fuel 

and by thermal fixation of nitrogen in the combustion air. NOx is generated in both the burning 

zone of Kiln 1 and Kiln 2. The kilns are allowed to burn coal, petroleum coke, fuel oil, or any 

combination of these fuels.

The available retrofit NOx controls technologies for Kiln 1 and Kiln 2 are as follows:

 Low-NOx burner system (LNB)

 Mixing Air Technology (MAT)

 Selective Catalytic Reduction (SCR)

 

64 2012-07-16 - UNC Task 5 Report (AZ-BART-Modeling-Protocol).docx

65 Copies of the model files submitted to EPA are too voluminous to be included in the electronic docket, but will be 

provided upon request.
Page 48 of 133

 Selective Non-Catalytic Reduction (SNCR)

Step 2 -- Eliminate technically infeasible options

Low-NOx Burners – LNBs are designed to reduce flame turbulence, delay fuel/air mixing, and 

establish fuel-rich zones for initial combustion. In 2001, LNA experimented with the installation 

of bluff body LNBs on the Nelson Lime kilns. These LNBs wore out in approximately six 

months, impacted production, caused brick damage, and resulted in unscheduled shutdowns of 

the kilns.66 We recognize that the staged combustion principle of LNB can present operational 

difficulties and potential product quality issues for lime production that are not exhibited in the 

cement industry. At this time, however, we consider LNB to be technically infeasible for the 

Nelson Plant Cement kilns, since we do not have any information to suggest otherwise at this 

time. The technical feasibility of LNB will be re-evaluated for lime kilns in subsequent 

reasonable progress planning periods.

Mixing Air Technology – MAT is the practice of injecting a high pressure air stream into the 

middle of a kiln to help mix the air flowing through the kiln. While the theory behind MAT 

suggests that the technology is effective at reducing NOx emissions, it is not clear whether this 

control technology will be effective on lime kilns. This technology has not been applied to 

similar rotary lime kilns according to EPA’s RACT/BACT/LAER Clearinghouse and other 

recent NOx control technology determinations. This control technology is eliminated as 

technically infeasible for retrofit on Kiln 1 and Kiln 2.

Selective Non-Catalytic Reduction – This control technique relies on the reduction of NOx in 

exhaust gases by injection of ammonia or urea, without using any catalyst. This approach avoids 

the problems related to catalyst fouling and poisoning, as in SCR, but requires injection of the 

reagents in the kiln at a temperature between 1600°F to 2000°F. Because no catalyst is used to 

increase the reaction rate, the temperature window is critical for conducting this reaction. A 

typical SNCR system consists of reagent storage, reagent-injection equipment, and associated 

control instrumentation. SNCR is a technically feasible option for reducing NOx emissions from 

the Nelson kilns.

Selective Catalytic Reduction – This process uses ammonia in the presence of a catalyst to 

selectively reduce NOx emissions from exhaust gases. In SCR, ammonia, usually diluted with air 

or steam, is injected through a grid system into hot flue gases which are then passed through a 

catalyst bed to carry out NOx reduction reactions. Catalysts that have been used include titanium 

dioxide, vanadium pentoxide, and zeolite-based materials. The catalyst is not consumed in the 

process but allows the reactions to occur at a lower temperature. The optimum temperature for 

the catalyst reactions depends on the specific catalyst used. According to EPA guidance, base 

metal catalysts are useful between 450°F and 800°F, and zeolite catalysts containing precious 

metals such as platinum and palladium are useful at 675°F to over 1100°F for high temperature 

operations. A typical SCR system consists of a reactor, a catalyst, an ammonia or urea storage 

and injection system, and associated control instrumentation. SCR is subject to catalyst 

poisoning in high dust kiln exhausts. SCR would have to be placed after the particulate control 

 

66 Described on Page 5-2, “BART Five Factor Analysis, Lhoist North America Nelson Lime Plant” (Public version 

dated September 27, 2013).
Page 49 of 133

systems. The Nelson Lime kilns operate with fabric filter baghouses, which typically have a 

maximum allowable temperature of 400 degrees F. This is at the very low end of the temperature 

range required for operation of an SCR system (approximately 400/450 to 800 degrees F). As a 

result, the SCR catalyst would need to be located prior to the kiln baghouses, which would result 

in poisoning or covering of the catalyst. In addition, we have not identified any SCR systems 

currently operating on lime kilns and therefore do not consider it to be a technology that is 

demonstrated in practice. This control technology is eliminated as technically infeasible for 

retrofit on Kiln 1 and Kiln 2.

Step 3 -- Evaluate control effectiveness of remaining control technology

SNCR is the only remaining technically feasible control option. The following table summarizes 

the expected effectiveness of this control technology.

Table III.C-4: SNCR Effectiveness of Feasible NOX Control Technologies

Control 

Option

Control 

Efficiency

Emission 

Factor Emission Rate

Emissions 

Removed

(%) (lb/ton lime) (lb/day) (tpy) (tpy)

Kiln 1

Baseline -- 7.59 6,573 981 --

SNCR 50% 3.80 3,286 491 491

Kiln 2

Baseline -- 5.21 6,492 985 --

SNCR 50% 2.61 3,246 493 493

LNA has not conducted any detailed design work for an SNCR system for the Nelson Plant 

kilns, but LNA anticipates that a 50% reduction is achievable based on LNA’s experience with 

operating a urea-injection system at another LNA lime plant.

Step 4 -- Evaluate impact on emissions and document the results

Factor 1: Costs of compliance

LNA’s SNCR cost estimates can be found in the public version of their five-factor BART 

analysis.67 LNA has asserted a CBI claim regarding certain annual operating costs such as 

reagent usage and auxiliary power costs. As a result, we have prepared our own 

independent estimate of annual operating costs based upon a combination of publicly 

available data and certain assumptions as described in the Contractor’s Report.68 The 

following table summarizes the estimated cost for installation and operation of SNCR.

 

67 Per Table 5-4, "Nelson BART Five Factor Analysis 09.27.13 - Public.pdf"

68 Our estimate of annual operating costs is contained in “Nelson Control Costs 2013-10-21.xlsx”
Page 50 of 133

Table III.C-5: Estimated Cost for SNCR

Kiln Capital 

Cost

Annualized 

Capital 

Cost

Annual 

Operating

Cost

Total 

Annual 

Cost

Emission 

Reduction

Cost 

Effectiveness

($) ($) ($) ($/yr) (tpy) ($/ton)

Kiln 1 450,000 42,477 358,459 400,936 491 817

Kiln 2 450,000 42,477 354,981 397,458 493 807

Factor 2: Presence of existing control technology

The presence of existing pollution control technology at the Nelson Plant is reflected in 

the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. In the case of NOX, the kilns at the Nelson plant do 

not operate with any existing control technology. This is reflected in the baseline 

emission rates, which represent uncontrolled emissions. 

Factor 3: Energy and non-air quality impacts

SNCR systems require electricity to operate the blowers and pumps, which will likely 

involve fuel combustion that will generate emissions. Overall, while the generation of the 

required electricity will result in emissions, the emissions should be low compared to the 

reduction in NOX that would be gained by operating an SNCR system.

The operation of SNCR systems on Kiln 1 and Kiln 2 would require that either urea or 

ammonia be stored on site. The storage of the chemicals does not result in a direct non-air 

quality impact. However, the potential for the urea or ammonia that would be stored to 

leak or otherwise be released from the storage vessels means there is the potential for 

both air and non-air quality related impacts. The storage of these chemicals does not 

significantly impact the BART determination.

Factor 4: Remaining useful life

We are considering the “remaining useful life” of the kilns as one element of the overall 

cost analysis as allowed by the BART Guidelines. Since we are not aware of any 

federally- or State-enforceable shut-down date for any of the affected sources, we have 

used a 20-year amortization period described in the EPA Cost Control Manual as the 

remaining useful life for the control options considered for the Nelson Plant kilns.

Factor 5: Evaluate visibility impacts

Tables III.C-6 and III.C-7 show the visibility benefits (visibility method 8, best 20% days 

background concentrations) of SNCR.
Page 51 of 133

Table III.C-6: Visibility Modeling of NOX Controls, Visibility Impacts

Class I Area

Control Scenario

base case SNCR

(ctr1)

Bryce Canyon NP 0.20 0.14

Grand Canyon NP 1.79 1.22

Joshua Tree NP 0.23 0.21

Mazatzal Wild. 0.15 0.14

Pine Mountain Wild. 0.15 0.13

Sierra Ancha Wild. 0.11 0.10

Superstition Wild. 0.13 0.13

Sycamore Canyon Wild. 0.31 0.24

Zion NP 0.28 0.20

Maximum 1.79 1.22

Cumulative (sum) 3.34 2.49

Number of areas >= 0.5 

dv 1 1

Table III.C-7: Visibility Modeling of NOX Controls, Visibility Benefits

Class I Area

Control Scenario

base case SNCR

(ctr1)

Bryce Canyon NP 0.06

Grand Canyon NP 0.58

Joshua Tree NP 0.02

Mazatzal Wild. 0.01

Pine Mountain Wild. 0.02

Sierra Ancha Wild. 0.01

Superstition Wild. 0.01

Sycamore Canyon Wild. 0.07

Zion NP 0.08

Maximum 0.58

Cumulative (sum) 0.85

Number of areas >= 0.3 

dv 1

Step 5 – Select BART

In considering the results of the five-factor analysis, we note that the remaining useful life of the 

source is reflected in the evaluation of cost of compliance through the use of a 20-year 

amortization period in control cost calculations. Since there is no existing NOx control 

technology in use in the plant, baseline emissions reflect uncontrolled NOx emissions. In 
Page 52 of 133

examining energy and non-air quality impacts, while we note certain impacts associated with 

SNCR, we do not consider these impacts sufficient to warrant its elimination as a control option.

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that the greatest visibility 

benefit SNCR is anticipated to achieve at a single Class I area is 0.58 dv at Grand Canyon 

National Park. Cumulative visibility benefit at all Class I areas within 300 km is anticipated to be 

0.85 dv. Our consideration of cost of compliance focuses primarily on the cost-effectiveness of 

each control option, as measured in cost per ton and incremental cost per ton of each control 

option. We note that SNCR has a cost effectiveness of approximately $800/ton. We consider 

SNCR to be cost effective control options for Kilns 1 and 2, at $817/ton and $807/ton, 

respectively. In addition, we consider the anticipated visibility benefit from SNCR to be 

substantial. Based on these considerations, we propose to find that BART for NOx is SNCR for 

Kiln 1 and Kiln 2.

We are proposing a BART emission limit for Kiln 1 of 3.80 lb/ton lime and for Kiln 2 of 2.61 

lb/ton lime on a rolling 30- kiln operating day basis, as demonstrated through the use of a CEMS. 

These proposed BART emission levels reflect a 50% reduction from baseline NOx emission 

levels.

We propose to require compliance with this requirement within three years after the effective 

date of the final rule. A 2006 Institute of Clean Air Companies (ICAC) study indicated that the 

installation time for a typical SNCR retrofit, from bid to startup-up, is 10-13 months.69 In relation 

to other industrial sources, such as fossil fuel boilers, there are a limited number of examples of 

SNCR installation on lime kilns. Given this relative lack of information regarding SNCR 

installation schedules on lime kilns, we consider three years to be an appropriate length of time 

to design, install, and test an ammonia injection system for a lime kiln. However, we are seeking 

comment on whether this compliance date is reasonable and whether there operational changes 

or difficulties that may warrant a different compliance schedule. If we receive information during 

the comment period that establishes that a different compliance timeframe is appropriate, we 

may finalize a different compliance date.

In addition, we are also proposing regulatory text that includes monitoring, reporting, and 

recordkeeping requirements associated with this emission limit. 

III.C.5 SO2 BART Analysis

Step 1 – Identify all available technologies

We have identified the following control technologies: semi-dry scrubbing, wet scrubbing, dry 

sorbent injection, mixing air technology, and lower sulfur fuel. We note that while a change in 

fuel supply is often a less polluting option, it can potentially involve a process change or 

redesign of the source. Since the BART Guidelines do not require a redesign of the source when 

examining control alternatives, and do not require fuel supply changes to be considered as a 

 

69 See “Typical Installation Timelines for NOx Emissions Control Technologies on Industrial Sources”, Institute of 

Clean Air Companies, December 4, 2006.
Page 53 of 133

control option, we have typically not considered this in BART analyses.70 However, because 

LNA included lower sulfur fuel in its analysis, we have retained it as a control option.

Semi-wet scrubbers are sometimes referred to as spray dryer absorbers (SDAs). This technology 

uses lime or limestone to react with SO2. This technology has been used for SO2 control on 

preheater/calciner kilns, but it can be successfully used on long kilns by adding spray nozzles 

that are made of special materials to prevent nozzle clogging. A semi-wet scrubber can achieve a 

SO2 removal efficiency of 30% to 60%. Clogging may not be an issue with semi-wet scrubbers 

that use lime due to the small size of the lime particles (3–10 microns) which allows the particles 

to dissolve in water droplets quickly and react with the gaseous SO2.

Wet scrubbing involves passing flue gas downstream from the main particulate matter control 

device through a sprayed aqueous suspension of lime or limestone that is contained in a 

scrubbing device. The SO2 reacts with the scrubbing reagent to form lime sludge that is collected. 

The sludge usually is dewatered and disposed of at an offsite landfill.

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas 

exhaust stream. The sorbent reacts with SO2 in the exhaust to form solid particles that are then 

removed by a particulate matter control device downstream of the sorbent injection. Dry sorbent 

injection systems are simple systems, and generally require a sorbent storage tank, feeding 

mechanism, transfer line and blower and an injection device.

The lower sulfur fuel switch option described by LNA involves change the proportion of coal 

and petroleum coke used as a fuel blend. LNA currently uses a blend of coal and petroleum coke

as the fuel for the kilns. Since coke has about 4 to 5 times more sulfur than coal, it is possible to 

decrease the sulfur in the fuel blend by increasing the coal portion. However, an increase in coal 

in the fuel blend will also increase the ash content of the fuel blend. Based on previous 

experience, LNA indicated that the Nelson Plant experienced disruptive operational issues in the 

form of buildup of ash rings in the kilns when using a fuel blend with ash content approaching a 

certain range. As a result, LNA believes that a 50% coal mix in the fuel mixture was the 

maximum amount of coal that could be accommodated and used a 50% coal/50% coke mixture 

in its evaluation of a fuel switch as a control option. Based upon our review of operator logs and 

other information provided by LNA, we do not consider this assumption to be unreasonable, and 

have also considered a 50% coal/50% coke mixture as a control option.

Step 2 – Eliminate technically infeasible options

LNA indicates that the Nelson Plant currently operates two groundwater wells at over 800 feet 

deep. The Primary Well that supplies the drinking and fire protection water for the plant yields 

approximately 46 gpm. The Canyon Well that supplies water for the quarry, crushing and 

screening plant, and hydrator yields approximately 60 gpm. In total, the available water supply to

the plant is 106 gpm. According to a 1998 hydrologic report, the water demand of the Nelson 

Plant is approximately 80 gpm. This demand has not increased significantly since 1998 and thus 

likely represents a good estimate of the current water demand at the facility. When the current 

 

70 40 CFR 51, Appendix Y, Section IV.D.1.5, “STEP 1: How do I identify all available retrofit emission control 

techniques?”
Page 54 of 133

water demand of 80 gpm is accounted for, only 26 gpm of water would be available for a 

scrubbing system. Based on the water demands that LNA has been provided for a semi-dry 

scrubbing (117 gpm), LNA has concluded that there is not currently sufficient water available for 

this type of system. Additionally, the 1998 hydrologic report referenced above indicates that the 

prospects for developing additional even low-yield wells on the Nelson property are poor.71

As a result, LNA concludes that the water necessary for a semi-dry scrubbing system at the 

Nelson Plant is currently unavailable and ability to reasonably access additional water is not 

probable. After a review of the hydrologic report and the vendor estimate of semi-dry scrubber 

water requirements, we agree with this assessment. As a result, this technology, as well as wet 

scrubbing, which has even larger water requirements than a semi-dry scrubber, will not be 

considered further in the BART control review for SO2.

Step 3 – Evaluate control effectiveness of remaining control technologies

The control effectiveness of a lower sulfur fuel blend was determined based upon a comparison 

of total sulfur content of the existing fuel mixture with the total fuel sulfur content of a 50% 

coal/50% coke fuel mixture. Based on a review of coal and coke properties and historical fuel 

usage provided by LNA, the use of a 50% coal/50% coke fuel mixture will result in a 23.3% 

reduction in SO2 emissions.

DSI control effectiveness was estimated at approximately 75% in the Contractor’s Report, based 

primarily on its control effectiveness as applied to cement kilns. In its own analysis, LNA 

pointed to several process differences between cement and lime kilns, and indicated that while 

control efficiencies for certain DSI systems up to 70% may be appropriate for cement kilns, it 

had received statements from vendors suggesting that only up to 50% is consistently achievable 

at lime kilns. LNA performed limited on-site testing of a DSI system at the Nelson plant and 

states that it observed short-term (<1 hour) control efficiencies ranging from 17% to 84%, 

depending upon a number of factors such as injection port placement, sorbent injection rate, kiln 

temperature, and kiln CO concentration. LNA concluded that control efficiencies in the range of 

20-40% can be achieved using high sorbent to SO2 ratios, and used 40% control efficiency in its 

cost and emission calculations.72 Given the differences in operation between lime and cement 

kilns, and the site-specific nature of the DSI testing at the Nelson Plant, we consider it 

appropriate to use 40% control efficiency for DSI.

Step 4 – Evaluate BART factors 

Factor 1: Costs of compliance 

In evaluating costs of compliance, LNA relied upon a vendor quote for purchased 

equipment provided by Noltech dated May 22, 2013, with the remainder of the capital 

costs calculated using the cost methodology contained in EPA’s Control Cost Manual.

While these capital costs are higher than those estimated by our contractor, we consider 

 

71See LNA Nelson-1998 Hydrogeologic Water Supply Study.pdf.

72 By contrast, our Contractor’s Report relied upon sorbent ratios of 2.63:1 and 4.63:1 (depending upon sorbent 

type). The sorbent injection ratios tested by LNA were substantially higher.
Page 55 of 133

the use of the Noltech vendor quote for the Nelson Plant reasonable, and have 

incorporated it into our evaluation of costs of compliance. LNA has asserted a 

confidential business information (CBI) claim regarding certain annual operating costs 

such as reagent usage. As a result, we have prepared our own independent estimate of 

annual operating costs based upon a combination of publicly available data and certain 

assumptions as described in the Contractor’s Report.73 

A summary of SO2 control emission rates and control costs are included in Tables 

III.C-8 and Table III.C-9 below. 

Table III.C-8: SO2 Control Option Emission Estimates

SO2 Control Technology Ctrl Eff Emission Factor Emission Rate Removed

% (lb/ton lime) (lb/day) (tpy) (tpy)

Kiln 1

Baseline -- 12.15 10,526 1,571 --

Lower Sulfur Fuel Blend 23.30% 9.32 8,073 1,205 366

Dry Sorbent Injection (SBC) 40% 7.29 6,316 943 628

Kiln 2

Baseline -- 12.69 15,808 2,400 --

Lower Sulfur Fuel Blend 23.30% 9.73 12,125 1,841 559

Dry Sorbent Injection (SBC) 40% 7.61 9,485 1,440 960

A summary of these cost calculations is presented below. Detailed cost calculations can 

be found in the docket.74

Table III.C-9: SO2 Control Option Cost Effectiveness

SO2 Control Technology

Capital 

Cost

Annual 

Direct 

Costs

Annual 

Indirect 

Costs

Total 

Annual 

Cost

Emission 

Reduction Cost Effectiveness 

($/ton)

($) ($/yr) ($/yr) ($/yr) (tpy) Average Incremental

Kiln 1

Lower Sulfur Fuel Blend -- -- -- 313,096 366 856 --

Dry Sorbent Injection (SBC) 2,497,559 371,174 2,621,832 2,621,832 628 4,174 8,803

Kiln 2

Lower Sulfur Fuel Blend -- -- -- 458,179 559 819 --

Dry Sorbent Injection (SBC) 2,497,559 371,174 3,895,774 3,895,774 960 4,058 8,576

Factor 2: Presence of existing control technology

The presence of existing pollution control technology at the Nelson Plant is reflected in 

the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

 

73 Our estimate of annual operating costs is contained in “Nelson Control Costs 2013-10-21.xlsx”

74 See spreadsheet titled “LNA Nelson Control Costs (final for NPRM docket).xlsx”.
Page 56 of 133

calculations and visibility modeling. In the case of SO2, the kilns at the Nelson plant do 

not operate with any existing control technology. This is reflected in the baseline 

emission rates, which represent uncontrolled emissions. 

Factor 3: Remaining useful life of the source

We are considering the “remaining useful life” of the kilns as one element of the overall 

cost analysis as allowed by the BART Guidelines. Since we are not aware of any 

federally- or State-enforceable shut-down date for any of the affected sources, we have 

used a 20-year amortization period described in the EPA Cost Control Manual as the 

remaining useful life for the control options considered for the Nelson Plant kilns.

Since there are no capital costs associated with using a lower sulfur fuel blend, the 

remaining useful life of the kilns is not a factor in the evaluation of this technology.

Factor 4: Energy and non-air quality environmental impacts

DSI systems require electricity for operation. The generation of the electricity needed to 

operate a DSI system will most likely involve fuel combustion. The combustion of fuel 

will generate emissions. There will also be emissions associated with the transport, 

handling, and storage of sorbent. Overall, while the use of DSI will cause emissions 

from select activities, the emissions should be low compared to the reduction in SO2

that would be gained by operating a DSI system.

Using a lower sulfur fuel blend means LNA will obtain more of the energy for lime 

production from coal and less of the energy from coke. Since the heating value of coke 

is slightly higher than the heating value of coal, it is likely that LNA will burn more 

total mass of fuel as a result of substituting some coal for coke. While burning a lower 

sulfur fuel blend will likely result in a reduction in SO2 emissions, the impact of 

burning a lower sulfur fuel blend on other pollutants such as NOx and CO is unknown.

Factor 5: Visibility improvement

The overall visibility modeling approach is described in Section III (factor five). 

Baseline emission rates and control option emission rates used in SO2 control scenario 

modeling are summarized below.

Table III.C-10: SO2 Control Model Emission Rates

SO2 Control Technology Ctrl Eff

Emission 

Factor

Maximum 24-hr 

Model Emission Rate

% (lb/ton lime) (lb/day) (lb/hr) (g/s)

Kiln 1

Baseline -- 12.15 10,526 439 55

Lower Sulfur Fuel Blend 23.30% 9.32 8,073 336 42

Dry Sorbent Injection (SBC) 40% 7.29 6,313 263 33

Kiln 2
Page 57 of 133

Baseline -- 12.69 15,808 659 83

Lower Sulfur Fuel Blend 23.30% 9.73 12,125 505 64

Dry Sorbent Injection (SBC) 40% 7.61 9,482 395 50

Table III.C-11 and III.C.12 show the visibility benefits (visibility method 8, best 20% 

days background concentrations) of the two control methods.

Table III.C-11: Visibility Modeling of SO2 Control Options, Visibility Impacts

Class I Area

Control Scenario

base case DSI (ctr2) Low-S 

fuel (ctr3)

Bryce Canyon NP 0.20 0.17 0.18

Grand Canyon NP 1.79 1.58 1.70

Joshua Tree NP 0.23 0.15 0.19

Mazatzal Wild. 0.15 0.11 0.13

Pine Mountain Wild. 0.15 0.11 0.13

Sierra Ancha Wild. 0.11 0.07 0.09

Superstition Wild. 0.13 0.09 0.11

Sycamore Canyon Wild. 0.31 0.25 0.27

Zion NP 0.28 0.24 0.26

Maximum 1.79 1.58 1.70

Cumulative (sum) 3.34 2.77 3.05

Number of areas >= 0.5 

dv 1 1 1

Table III.C-12: Visibility Modeling of SO2 Control Options, Visibility Benefits

Class I Area

Control Scenario

base case DSI (ctr2) Low-S 

fuel (ctr3)

Bryce Canyon NP 0.03 0.02

Grand Canyon NP 0.21 0.10

Joshua Tree NP 0.07 0.04

Mazatzal Wild. 0.04 0.02

Pine Mountain Wild. 0.04 0.02

Sierra Ancha Wild. 0.04 0.02

Superstition Wild. 0.04 0.02

Sycamore Canyon Wild. 0.06 0.04

Zion NP 0.04 0.02

Maximum 0.21 0.10

Cumulative (sum) 0.57 0.29

Number of areas >= 0.3 

dv 0 0
Page 58 of 133

Step 5 – Select BART

In considering the results of the five-factor analysis, we note that the remaining useful life of the 

source is reflected in the evaluation of cost of compliance through the use of a 20-year 

amortization period in control cost calculations. Since there is no existing SO2 control 

technology in use in the plant, baseline emissions reflect uncontrolled SO2 emissions. In 

examining energy and non-air quality impacts, we note that there may be certain collateral 

increases in emissions, but that these increases are outweighed by the emission reductions 

achieved by implementing the control technology and do not warrant their elimination.

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that each of the available 

SO2 control options achieves some degree of visibility improvement, although in neither case is 

the anticipated benefit greater than 0.20 dv at any single Class I area.

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option. 

Use of the lower sulfur fuel is the most cost effective option at approximately $1,100/ton. DSI is 

considerably less cost effective, with average cost effectiveness values of approximately

$4,000/ton and incremental cost effectiveness values, relative to lower sulfur fuel, of greater than 

$11,000/ton.

While DSI is anticipated to achieve the greatest visibility improvement, we note that this amount 

of visibility improvement is not large, and is achieved at a very high incremental cost relative to 

the next most stringent control option. Use of a lower sulfur fuel blend, by comparison, is also 

not anticipated to achieve a large degree of visibility improvement, but is very cost effective.

Based on this information, we propose to find that BART for SO2 is use of lower sulfur fuel 

blend for Kiln 1 and 2. We are proposing with an emission limits of 9.32 lb/ton and 9.73 lb/ton, 

for Kilns 1 and 2 respectively, on a rolling 30-day basis.

We propose to require compliance with this requirement by within six months after the effective 

date of the final rule. However, we are seeking comment on whether this compliance date is 

reasonable. We are specifically seeking comment on whether there are operational changes or 

difficulties that maybe necessary to accommodate the new fuel mixture. If we receive 

information during the comment period that establishes that a different compliance timeframe is 

appropriate, we may finalize a different compliance date.

In addition, we are also proposing regulatory text that includes monitoring, reporting, and 

recordkeeping requirements associated with this emission limit. 

III.C.6 PM BART Analysis

Step 1 – Identify all available technologies
Page 59 of 133

Both kilns currently have existing baghouses for particulate matter control, which is the most 

efficient device for controlling particulate matter from this type of source. The BART Guidelines 

provide that, in instances where a source already has the most stringent controls available in 

place (including all possible improvements), it is not necessary to comprehensively complete 

each following step of the BART analysis in this section. As long these most stringent controls 

available are made federally enforceable for the purpose of implementing BART for that source, 

you may skip the remainder of the analysis, including the visibility analysis.75

It is unclear to us what degree additional improvements, such as better performing filter media, 

can be made to the existing fabric filters, and we are therefore seeking comment regarding 

whether additional upgrades or improvements are possible. However, we note that the Nelson 

Plant, as a major source of HAPs, is subject to the Maximum Achievable Control Technology 

(MACT) Standard for Lime Manufacturing Plants, and is required to meet an emission limit of 

0.12 lbs PM/TSF (ton of stone feed).76 The BART Guidelines provide that unless there are new 

technologies subsequent to the MACT standards that would lead to cost effective increases in the 

level of control, you may rely on the MACT standards for purposes of BART.77 Based on 

information developed as part of the Lime MACT, we estimate that existing fabric filter 

upgrades would result in annual costs of $94,500.78 As noted in LNA’s BART analysis, baseline 

PM emissions for the kilns, as based on PM filterable stack test data and annual lime production, 

are approximately 8 tpy and 15 tpy.79 This would result in an average cost effectiveness of 

approximately $6,300 to $12,000/ton, which is not in a range that we consider cost effective.

As a result, since the kilns at the Nelson Plant operate with a fabric filter baghouse, and we have 

not identified any cost-effective upgrades or improvements, we proposing a particulate matter 

BART emission limit of 0.12 lb /TSF based on the use of the existing fabric filter baghouses.

III.D. ASARCO Smelter

III.D.1. Summary

This five factor analysis documents the basis for determination of the Best Available Retrofit 

Technology (BART) for control of sulfur dioxide (SO2) and nitrogen oxides (NOx), emissions at 

the ASARCO Hayden Smelter.

EPA conducted a five step analysis, with step four incorporating the five factor analysis, in 

accordance with BART guidelines.80 This analysis consists of the following steps:

Step 1 -- Identify all available technologies

Step 2 -- Eliminate technically infeasible options

 

75 40 CFR Part 51, Appendix Y, Section IV.D.9

76 40 CFR 63, Subpart AAAAA, Table 1, Item 1 for existing lime kilns with no wet scrubber prior to 2005.

77 40 CFR Part 51, Appendix Y, Section IV.C

78 Annual costs as described in the Economic Impact Analysis for the Lime Manufacturing MACT Standard (EPA452/R-03-013), Table 3-2, Model Kiln F. Adjusted from 1997 to 2013 dollars using the consumer price index, 

available at ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt.

79 As described in the LNA Nelson BART Analysis, Table 4-5.

80 See July 6, 2005 BART guidelines, 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations.
Page 60 of 133

Step 3 -- Evaluate control effectiveness of remaining control technology

Step 4 -- Evaluate impact on emissions and document the results

Factor 1: Cost of compliance

Factor 2: Energy impacts

Factor 3: Non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5: Evaluate visibility impacts

Step 5 – Select BART

As described in the following sections, we are proposing the following BART limits for 

the ASARCO Hayden Smelter:

Table III.D-1: Summary of Proposed BART determinations

Pollutant Emission Limit Control Technology1

Pierce-Smith Converters

NOX NA No additional controls

SO2 99.8% Double contact acid plant control of gases 

collected by primary and secondary capture 

systems

Anode Furnaces

NOX NA No additional controls

SO2 NA No additional controls

1

These control technologies are only listed for reference, as the facility is not required to install the 

listed technology to meet the BART limit.

III.D.2. Facility Description

The ASARCO Hayden Smelter is located on the east side of the town of Hayden in Gila County, 

Arizona, approximately 55 miles north of Tucson and 80 miles east-southeast of Phoenix. The 

facility processes copper sulfide ore from the Ray Mine, about 18 miles to the west, to produce 

anode copper that is further refined at the Amarillo Refinery in Amarillo, Texas.

Ore, which typically contains less than 1 percent copper, is delivered by truck or rail to the 

facility from the Ray Mines or elsewhere, where it is processed into concentrates before being 

melted. Concentrates are produced in the concentrator that is adjacent to the smelter, and 

screened before being dried and fed to the oxygen flash furnace. In the flash furnace, a molten 

bath separates into a heavy matte layer and a lighter slag layer. Ladles then transport the copperrich (approximately 50-60% copper) matte to the converters where oxygen-enriched air oxidizes 

sulfur to sulfur dioxide (SO2) and iron to iron(II) oxide (ferrous oxide). The output of the 
Page 61 of 133

converters, called blister copper, is fed to the anode furnaces where it is refined electrolytically 

to a product that is about 99% pure copper.

The Arizona Regional Haze State Implementation Plan (SIP) identified anode furnaces 1 and 2 

and converters 1, 2, and 4 at ASARCO’s Hayden Smelter as subject to BART for one or more 

pollutants, based on information provided by ASARCO indicating that these units were in 

existence on August 7, 1977 and began operation after August 7, 1962. Table III.D-2 lists the 

converters and anode furnaces at ASARCO Hayden and whether they are BART eligible.

Table III.D-2: Converters and Anode Furnaces at ASARCO Hayden

Unit Description Date 

Installed

BART 

Eligible

Converter #1 Pierce Smith Converter, 13’ x 35’

Approx. 100 tons copper per cycle

1965 Yes

Converter #2 Pierce Smith Converter, 13’ x 30’

Approx. 100 tons copper per cycle

1950 No

Converter #3 Pierce Smith Converter, 13’ x 33’

Approx. 100 tons copper per cycle

1965-1975 Yes

Converter #4 Pierce Smith Converter, 13’ x 33’

Approx. 100 tons copper per cycle

1965-1975 Yes

Converter #5 Pierce Smith Converter, 13’ x 33’

Approx. 100 tons copper per cycle

1965-1975 Yes

Anode Furnace #1 Fuller Co., natural gas fired, 330 ton 

copper

1971 Yes

Anode Furnace #2 Fuller Co., natural gas fired, 330 ton 

copper

1971 Yes

Anode Furnace #0 Fuller Co., natural gas fired, 330 ton 

copper (described as a “spare” unit)

2001 No

Converters

Each of the five converters is fitted with primary and secondary capture systems. The primary 

capture system is designed to capture emissions during blowing operations. The secondary 

system is designed to capture emissions that escape the primary system or that are emitted during 

ladling and skimming. Emissions from the primary capture systems are controlled by a gas 

cleaning plant to remove PM and a double contact sulfuric acid plant that converts SO2 to 

sulfuric acid. The outlet of the acid plant is ducted through the facility’s 305 meter stack. 

Emissions from the secondary capture systems are ducted to a baghouse that controls PM and, to 

a limited extent through lime injection, SO2, and then emitted through an annulus of the facility’s 

305 meter stack. Uncaptured emissions are released from the converter building without passing 

through a stack or duct.
Page 62 of 133

Because emissions from all five converters are combined before being controlled and emitted, it 

is not possible to treat emissions from the units separately, including the one converter that is not 

BART eligible. 81

Because the converters are heated by the combustion of natural gas they are also sources of NOx

emissions.

Anode Furnaces

Emissions from the anode furnaces include SO2 resulting from oxidation of residual sulfur 

remaining in the blister copper and products of natural gas combustion, including NOx. In 2011 

ASARCO installed a baghouse to control particulate emissions from the anode furnaces, but SO2

and NOx emissions are uncontrolled.

Baseline Emissions

Neither ASARCO nor ADEQ identified baseline emissions for ASARCO Hayden. Therefore, as 

a preliminary step, we calculated baseline emissions for both NOX and SO2. For SO2, we are 

considering the average of the two highest emitting years from the last five years that ASARCO 

reported to ADEQ as the baseline. For NOX, we determined the potential to emit NOx based on 

maximum natural gas consumption rates found in the facility’s title V permit for equipment 

subject to BART. Baseline emissions are summarized in Table III.D-3.

Table III.D-3: BART Baseline Emissions in TPY

Converters Anode Furnaces

Acid Plant Secondary Capture Uncaptured

SO2 1,034 20,341 1,209 38

NOx 31 19

III.D.3. General Approach to Five-Factor BART Analysis

This section contains a general description of our approach to the five-factor analysis, and 

discusses certain elements of our approach that are common to each of the pollutant-specific 

analyses performed for the ASARCO Hayden Smelter.

Factor 1: Cost of Compliance

Whenever possible, we used cost information provided by ASARCO to estimate the capital and 

operating costs for control equipment. When cost information from ASARCO was not available, 

we used the best, published data available as documented in the BART analyses that follow.

 

81 See BART Guidelines, 40 CFR section IV.D.1: “There may be situations where a specific set of units within a 

fenceline constitutes the logical set to which controls would apply and that set of units may or may not all be BARTeligible. (For example, some units in that set may not have been constructed between 1962 and 1977.)”
Page 63 of 133

Factor 2: Energy Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common 

elements relating to this factor discussed here. Pollutant-specific discussions of these issues are 

included in the following sections. 

Factor 3: Non-air Quality Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common 

elements relating to this factor discussed here. Pollutant-specific discussions of these issues are 

included in the following sections. 

Factor 4: Remaining Useful Life

Because we are not aware of any regulatory requirements to shut down any of the BART-eligible 

units or any plans to remove them from service, we have used a 20-year amortization period, as 

noted in the EPA Cost Control Manual, as the remaining useful life of the facilities considered in 

this proposed action.

Factor 5: Visibility Impacts

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full ASARCO Hayden modeling results, 

including for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, 

and 8a, can be found in the tables and bar graphs in TSD Appendix B and in the spreadsheet

Hayden_visibility_results.xlsx.

III.D.4. SO2 BART Analysis

Converters

Step 1 – Identify all available technologies

We identified two possible control technologies for controlling SO2 emissions from the 

converters:

1. Double contact acid plant

2. Wet scrubbing

Because SO2 emissions captured by the primary capture system are already controlled by a 

double contact acid plant, we evaluated potential upgrades to the existing plant, as well as the 

possibility of adding a tailstack scrubber to the existing acid plant. For emissions from the 

secondary capture system, we evaluated the use of a double contact acid plant, as well as wet 

scrubbing. 

Double Contact Acid Plant
Page 64 of 133

A double contact acid plant uses a solid state catalyst to convert SO2 to SO3, which reacts with 

water to form sulfuric acid. Sulfuric acid plants typically are designed to control feed streams 

containing several percent SO2 so the exothermic catalytic reaction can operate autothermally. 

However, acid plants can be designed to process feed streams that contain only a fraction of a 

percent of SO2, although it may be necessary to heat the inlet gas stream or the catalyst. In 1984, 

EPA reported that SO2 conversion rates of 99.8 percent and above can be achieved by double 

contact acid plants operating in steady state.82

There are two types of catalysts used in double contact acid plants. The traditional catalyst uses a 

potassium/vanadium salt mixture on a silica substrate. The other is a cesium promoted catalyst, 

where some of the potassium in a traditional catalyst is replaced with an equal molar quantity of 

cesium. According to Monsanto, the cesium promoted catalyst is more stable, less prone to 

deactivation, and active at lower temperatures. Traditional and cesium promoted catalysts can be 

used in combination, typically in the first and fourth passes of a double contact acid plant.83

As noted above, ASARCO Hayden currently uses a double contact acid plant to control SO2

emissions captured by primary capture system. ASARCO reports that approximately 30 percent 

of the catalyst used in the first and fourth passes is cesium promoted.84

Wet Scrubbing

Wet scrubbing involves the reaction of SO2 with liquid phase absorbents to yield sulfur 

compounds that can be sold, reprocessed, or discarded. The absorbent can be based on calcium 

oxide (CaO), magnesium oxide (MgO), or sodium hydroxide (NaOH). Wet scrubbing is 

commonly used in many industries for control of SO2.

Step 2 – Eliminate technically infeasible options

Both double contact acid plants and wet scrubbing are technically feasible.

Step 3 – Evaluate control effectiveness of remaining control technologies

In its July 11, 2013 response to EPA’s June 27, 2013 information request, ASARCO indicated 

that its double contact acid plant, which controls emissions from the primary capture system, was 

capable of recovering 99.81 percent of the SO2 vented to it.85 The expected control effectiveness 

of wet scrubbing was provided by ASARCO in the same letter.

Control Technology SO2-Reduction Effectiveness

Double Contact Acid Plant 99.81%

Wet Scrubber 85%

 

82 “Review of New Source Performance Standards for Primary Copper Smelters,” US EPA, Office of Air Quality 

Planning and Standards, March 1984, EPA 450/3-83-018a .

83 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, Item #9 (January 25, 2013).

84 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, Item #8 (January 25, 2013).

85 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA (July 11, 2013).
Page 65 of 133

Step 4 – Evaluate Impacts

Factor 1: Cost of Compliance

We calculated the cost to control SO2 collected by the secondary capture system with an acid 

plant and with a wet scrubber. We also calculated the addition of a tailstack scrubber to the 

existing acid plant that controls SO2 collected by the primary capture system.

Double Contact Acid Plant to Control Secondary Capture System

EPA calculated the cost of construction for an acid plant for the secondary capture system using 

an equation published in the1984 review of the NSPS for primary copper smelters, page 8-1386:

ln(cost) = 0.1325 + 0.378(%SO2)

0.177 + 0.783(%SO2)-0.104 [ln(Q-3.418)]

where:

cost = cost in millions of 1981 dollars,

Q = the gas flow rate in scfm (1 atm. And 70°F), and

%SO2 is expressed as a percent (i.e. 1% = 1.0).

We performed the calculation in a conservative manner more likely to overestimate than 

underestimate costs. We used the highest flow rate measured in the secondary hood during the 

most recent (September 2012) continuous emissions monitoring system CEMS relative accuracy 

test audit (RATA) and SO2 emissions test multiplied by a factor of 1.5 for “Q” and the second 

lowest SO2 concentration measured during the test. The result of the equation was multiplied by 

a factor of 2.57 to convert from 1981 to 2013 dollars.

87 We further applied a factor of 2.5. We 

annualized capital costs assuming a 20 year lifespan and a 7 percent interest rate. 

We obtained the costs of the standard and cesium promoted catalyst from a 2011 sales proposal 

provided by ASARCO and assumed 100 percent cesium catalyst use in the first and fourth 

passes.

We applied a control efficiency of 99.81 percent, which the existing acid plant is currently 

achieving with limited cesium catalyst use. The emission reduction was applied to the secondary 

capture system baseline emissions.

Control 

Effectiveness

Tons SO2

Reduced

Capital Cost Annualized 

Capital 

Cost

Annual 

Variable 

Cost

Total 

Annual 

Cost

$/ton SO2

Removed

99.81% 20,341 $81,621,297 $7,704,573 $10,006,010 $17,710,483 $872

The cost analysis above does not include the offsetting value of any sulfuric acid produced and 

 

86 Review of the New Source Performance Standards for Primary Copper Smelters. U.S. EPA, Office of Air Quality, 

Planning, and Standards. March, 1984. EPA 450/3-83-018a.

87 From the Bureau of Labor Statistics CPI Calculator: http://www.bls.gov/data/inflation_calculator.htm.
Page 66 of 133

sold. It does assume full catalyst replacement every other year and air preheating with natural gas 

for 8760 hours per year.

We believe that this cost analysis is very conservative (i.e. tending to overstate rather than 

understate costs) because: 

1. We applied a multiplier of 2.5 to the capital cost estimate of the secondary acid plant, due 

to the age of the cost estimate and to account for uncertainty;

2. Catalyst may need to be replaced less frequently that biennially and the first and fourth 

passes may not need to be 100 percent cesium promoted;

3. We did not consider the offsetting costs of usable or salable sulfuric acid;

4. Some of the emissions captured by the secondary capture system could be ducted to the 

existing acid plant thus reducing the capacity needed for a new acid plant; and 

5. We expect that there are existing sources of unused heat at the smelter that can be used to 

preheat gases entering the secondary acid plant.

Wet Scrubber to Control Secondary Capture System

EPA calculated costs of constructing and operating a wet scrubber to control SO2 from the 

secondary based on information included in Jack Garrity’s July 11, 2013 letter to Thomas Webb. 

We used the more conservative high-end estimate of operating costs. We also included a sludge 

hauling fee of $60 per ton and assumed one ton of SO2 controlled would result in five tons of 

sludge.

Control 

Effectiveness

Tons SO2

Reduced

Capital Cost Annualized 

Capital 

Cost

Annual 

Variable 

Cost

Total 

Annual 

Cost

$/ton SO2

Removed

85% 17,290 $28,000,000 $2,643,002 $14,186,965 $16,829,967 $972

According to ASARCO, these costs do not include the cost of a booster fan or a modified stack 

that may be needed. Although the calculation includes the cost hauling sludge off site, it does not 

include the cost of treating or landfilling the sludge, which may be classified as hazardous waste 

depending on the metals content.

Wet Scrubber to Control Acid Plant Tailstack

EPA calculated costs of constructing and operating a wet scrubber to control SO2 from the 

existing acid plant tailstack based on information included in Jack Garrity’s July 11, 2013 letter 

to Thomas Webb. In this case we used the low-end estimate of operating costs. We also included 

a sludge hauling fee of $60 per ton and assumed one ton of SO2 controlled would result in five 

tons of sludge.

Control 

Effectiveness

Tons SO2

Reduced

Capital Cost Annualized 

Capital 

Cost

Annual 

Variable 

Cost

Total 

Annual 

Cost

$/ton SO2

Removed

85% 879 $28,000,000 $2,643,002 $9,274,521 $11,917,523 $13,564
Page 67 of 133

Again, these costs do not include the cost of a booster fan or a modified stack that may be 

needed. Although the calculation includes the cost hauling sludge off site, it does not include the 

cost of treating or landfilling the sludge, which may be classified as hazardous waste depending 

on the metals content. In addition, we note that some of the SO2 that passes through the acid 

plant was emitted by the flash furnace which is not BART eligible.

Factor 2: Energy Impacts

Operation of a sulfuric acid plant at the ASARCO Hayden smelter would require energy to heat 

inlet air from approximately 177° F to 735° F. This would require a heat input of approximately 

114 MMBtu/hr and could require 1,200 MMscf of natural gas per year, resulting in up to 30 tpy 

NOx emissions.88 This assumes 100 percent of the needed heat resulted from natural gas 

combustion.

Operation of a wet scrubber on either the primary or secondary system would likely require 

operation of a booster fan and a gas reheater to force emissions through the 305 meter stack.

Factor 3: Non-air Quality Impacts

Non-air quality impacts from a second acid plant are not expected to be significant given that 

ASARCO already has the capacity to handle and store the much larger quantities of sulfuric acid 

produced by the primary acid plant.

The addition of a wet scrubber to either the primary or secondary capture system could result in a 

detached visible plume as water vapor emitted from the scrubber condenses. Addition of a 

scrubber would result in sludge which would have to be shipped off site to be treated or 

landfilled. Because of metals in the sludge, it may need to be treated as hazardous waste.

Factor 4: Remaining Useful Life

The BART-eligible converters have each been in place for approximately 40 years or longer and 

ASARCO has not indicated that any of them would be replaced during the 20 year capital cost 

recovery period.

Step 5: Visibility Impacts

Controlling SO2 emissions through a second double contact acid plant results in visibility 

improvement in 12 Class I areas in Arizona and New Mexico as indicated in Tables III.D-4 and 

III.D-5.

We did not conduct visibility modeling for the addition of a scrubber. Because the addition of a 

scrubber to the secondary capture system is less efficient at removing SO2 than a second acid 

plant, the emission rates would be higher and there would be less visibility improvement from a 

scrubber compared to an acid plant.

 

88 Based on the AP 42 factor for low NOx burners.
Page 68 of 133

Similarly, we did not conduct visibility modeling for the addition of a tailstack scrubber because 

of the much higher cost per ton of SO2 removed and the relatively low quantity of SO2 reduced.

Table III.D-4: Visibility Modeling of SO2 Control Options, Visibility Impacts

Class I Area

Control Scenario

Base case

(base)

new acid 

plant (ctrl2)

Chiricahua NM 1.05 0.16

Chiricahua Wild. 1.01 0.15

Galiuro Wild. 1.73 0.28

Gila Wild. 0.69 0.09

Mazatzal Wild. 0.88 0.13

Mount Baldy Wild. 0.66 0.09

Petrified Forest NP 0.70 0.10

Pine Mountain Wild. 0.67 0.10

Saguaro NP 1.38 0.20

Sierra Ancha Wild. 1.09 0.15

Superstition Wild. 1.74 0.27

Sycamore Canyon Wild. 0.51 0.07

Maximum 1.74 0.28

Cumulative (sum) 12.10 1.78

Number of areas >= 0.5 dv 12 0

Table III.D-5: Visibility Modeling of SO2 Control Options, Visibility Benefits

Class I Area

Control Scenario

Base case

(base)

new acid 

plant (ctrl2)

Chiricahua NM 0.89

Chiricahua Wild. 0.87

Galiuro Wild. 1.45

Gila Wild. 0.60

Mazatzal Wild. 0.75

Mount Baldy Wild. 0.56

Petrified Forest NP 0.61

Pine Mountain Wild. 0.57

Saguaro NP 1.18

Sierra Ancha Wild. 0.93

Superstition Wild. 1.47

Sycamore Canyon Wild. 0.44
Page 69 of 133

Maximum 1.47

Cumulative (sum) 10.32

Number of areas >= 0.3 dv 12

As discussed in the Federal Register notice, EPA relied on stack parameters provided in the July 

2013 ASARCO letter to EPA. However, EPA also had stack exit temperatures and velocities 

available from a 2012 stack test.89 The following table includes results from the corresponding 

one in the notice, but adds results using the alternative stack parameters. The results show higher 

impacts, and also a larger benefit from controls, compared to the 2013 stack parameters. These 

results affirm that EPA’s proposed BART control is reasonable even with alternative stack 

assumptions.

Table III.D-6: Stack Parameter Sensitivity Analysis

Stack parameters from 

ASARCO July 2013

Stack parameters from 2012 

stack test

Impact

Improvement 

from Control Impact

Improvement 

from Control

Class I Area

Distance, 

km

Base case, 

parms1 (base)

new acid plant, 

parms1 (ctrl2)

Base case, 

parms2 

(baset)

new acid plant, 

parms2 (ctrl2t)

Chiricahua NM 170 1.05 0.89 1.12 0.95

Chiricahua Wild. 174 1.01 0.87 1.08 0.92

Galiuro Wild. 48 1.73 1.45 2.05 1.70

Gila Wild. 186 0.69 0.60 0.70 0.60

Mazatzal Wild. 121 0.88 0.75 1.05 0.90

Mount Baldy Wild. 151 0.66 0.56 0.70 0.59

Petrified Forest NP 215 0.70 0.61 0.67 0.57

Pine Mountain 

Wild. 168 0.67 0.57 0.73 0.61

Saguaro NP 82 1.38 1.18 1.64 1.40

Sierra Ancha Wild. 84 1.09 0.93 1.27 1.08

Superstition Wild. 50 1.74 1.47 2.11 1.74

Sycamore Canyon 

Wild. 239 0.51 0.44 0.54 0.45

Cumulative (sum) 12.10 10.32 13.66 11.50

Maximum 1.74 1.47 2.11 1.74

# CIAs >= 0.5 dv 12 11 12 11

million $/dv 

(cumul. dv) $1.7 $1.7

million $/dv (max. 

dv) $12.1 $12.1

 

89 CEMS Test Report for Secondary Hood, Furnace Vent and Acid Plant at ASARCO Hayden, by Energy and 

Environmental Measurement Corporation, September, 2012.
Page 70 of 133

Step 5 – Select BART

We identified three possible control strategies to reduce SO2 emissions from the converters :

1. Control of the secondary capture system by a double contact acid plant.

2. Control of the secondary capture system by a wet scrubber.

3. Control of acid tailstack emissions by a wet scrubber.

Option #3 is ruled out because of cost (> $13,000/ton SO2). Option #2 is less effective than 

option #1 at a higher annual cost per ton of pollutant controlled and with greater non-air impacts. 

Therefore, we have determined that it is feasible and cost effective to control gases collected by 

the secondary capture system with a double contact acid plant. 

We propose as BART for SO2 for the converters:

1. An SO2 control efficiency of 99.8 percent, 30-day rolling average, on all SO2 captured by 

the primary and secondary control systems. The control efficiency may be averaged 

between the two capture systems on a mass basis. (For every 30-day period the total mass 

of SO2 exiting the two control systems must be no greater than 0.0019 percent of the SO2

entering the control systems.)

2. Compliance with the SO2 BART limit may be verified either through the use of SO2

CEMS before and after controls in each system or by using post-control CEMS and acid 

production rates. A limit of 2.49 lbs SO2 emissions per tons of sulfuric acid production is 

equivalent to 99.8 percent control.

3. Operation and maintenance of primary and secondary capture systems meeting the 

requirements of 40 CFR 63, subpart QQQ, as it applies to Peirce Smith converters. 

Anode Furnaces

Step 1 – Identify all available technologies

We identified the same two control technologies for the anode furnaces: a new double contact 

acid plant and a wet scrubber.

Step 2 – Eliminate technically infeasible options

Both technologies are technically feasible for the reduction of SO2.

Step 3 – Evaluate control effectiveness of remaining control technologies

We assumed the same control efficiencies for the two identified control technologies for the 

anode furnaces as supplied by ASARCO for the converters.

Step 4 – Evaluate Impacts
Page 71 of 133

Factor 1: Cost of Compliance

We performed a calculation of the cost to control SO2 from the anode furnaces using the same 

equation used for the converters and estimated the cost to control SO2 from the anode furnaces 

by construction to a new acid plant to be over $28,000 per ton, not including the cost of inlet 

preheating. We found operation of a wet scrubber to be even more expensive at over $80,000 per 

ton. 

Table III.D-7: Hayden Smelter: New Acid Plant for the Anode Furnaces

Capital Cost Annualized 

Capital Cost

Annual 

Variable Cost

Total Annual 

Cost

Tons SO2

Reduced

Control 

Efficiency

$/ton SO2

Removed

$8,583,190 $810,192 $261,827 $1,071,920 37 99.81% $28,616

Table III.D-8: Hayden Smelter: New Wet Scrubber for the Anode Furnaces

Capital Cost Annualized 

Capital Cost

Annual 

Variable Cost

Total Annual 

Cost

Tons SO2

Reduced

Control 

Efficiency

$/ton SO2

Removed

$7,000,000 $660,750 $2,009,570 $2,670,320 32 85% $83,708

Factor 2: Energy Impacts

Given the high cost of control we did not consider energy impacts.

Factor 3: Non-air Quality Impacts

Given the high cost of control we did not consider non-air quality impacts.

Factor 4: Remaining Useful Life

We are not aware of any limits on the useful life of the anode furnaces.

Factor 5: Visibility Impacts

We did not conduct visibility modeling for the anode furnace emissions. However, since the 

emissions from these units are a small fraction of those from the converters, the expected 

visibility improvement would be far less than for any of the controls considered for the 

converters.

Step 5 – Select BART

Given the high cost and small potential for visibility improvement, we propose that controlling 

SO2 emissions from the anode furnaces is not warranted for purposes of BART. 

In order to ensure that emissions from anode furnaces do not increase substantially in the future, 

we are proposing to establish a work practice standard for these units. While BART 

determinations are generally promulgated in the form of numeric emission limitations, the RHR 

allows for use of equipment requirements or work practice standards in lieu of a numeric limit 
Page 72 of 133

where “technological or economic limitations on the applicability of measurement methodology 

to a particular source would make the imposition of an emission standard infeasible.”90 In this 

case, we find that a numerical emission limitation for the anode furnaces would be infeasible 

because of the relatively small amount of emissions from these units, compared with the 

converters. Therefore, we are proposing to establish a work practice standard in the form of a 

requirement that the anode furnaces be charged with blister copper or higher purity copper. 

Because blister copper is generally 98 to 99 percent pure copper, this requirement will ensure 

that sulfur emission from the anode furnaces are minimized.

III.D.5. BART Analysis for NOx

Step 1 – Identify all available technologies

We identified low-NOx burners (LNB) as an available control technology

Step 2 – Eliminate technically infeasible options

LNB are technically feasible for natural gas combustion.

Step 3 – Evaluate control effectiveness of remaining control technologies

According to the Documentation Report accompanying AirControlNET, LNB retrofits can 

reduce NOx emissions by 50 percent.91

Step 4 – Evaluate Impacts

Factor 1: Cost of Compliance

According to the Documentation Report accompanying AirControlNET, the cost to retrofit 

process heaters with LNB is $2,200 per ton of NOx controlled. 

Factor 2: Energy Impacts

We expect energy impacts to be minimal.

Factor 3: Non-air Quality Impacts

We expect non-air quality impacts to be minimal.

Factor 4: Remaining Useful Life

We are not aware of any limits on the useful life of the project.

 

90 40 CFR 51.308(e)(1)(iii). See also 40 CFR 51.100(z)(defining “emission limitation” and “emission standard” to 

include “any requirements which . . . prescribe equipment . . . for a source to assure continuous emission reduction.”

91 AirControlNet, Version 4.1, Documentation Report by E.H. Pechan and Associates, Inc. for U.S. EPA, Office of 

Air Quality, Planning, and Standards, May 2006. Page III-445.
Page 73 of 133

Factor 5: Visibility Impacts

The maximum modeled 98th percentile visibility impact resulting from baseline NOx emissions 

from the Hayden Smelter is 0.01 dv.92 Thus, the maximum visibility benefit of controls is less 

than 0.01 dv.

Step 5 – Select BART

Given the small potential for visibility improvement, we propose that controlling these NOx

emissions is not warranted for purposes of BART. However, in order to ensure that NOx

emissions do not increase in the future, we propose to set a 12-month rolling limit of 40 tons of 

NOx from the subject-to-BART units, which is equivalent to the de minimis level of emissions 

set out in the RHR.93 This emission limit is slightly lower than the annual 50 tpy baseline 

emissions noted above. Nonetheless, we consider it to be a reasonable limit because the 50 tpy 

estimate assumes that all of the converters are all operating simultaneously, which is not how 

they typically operate. Therefore, we expect actual emissions to be well below 40 tpy, which is 

consistent with ASARCO’s own estimate.94 

III.E. Freeport McMoRan Smelter

III.E.1. Summary

This five factor analysis documents the basis for determination of the Best Available Retrofit 

Technology (BART) for control of sulfur dioxide (SO2) and nitrogen oxides (NOx), emissions at 

the Freeport McMoRan Smelter.

EPA conducted a five step analysis, with step four incorporating the five factor analysis, in 

accordance with BART guidelines.95 This analysis consists of the following steps:

Step 1 -- Identify all available technologies

Step 2 -- Eliminate technically infeasible options

Step 3 -- Evaluate control effectiveness of remaining control technology

Step 4 -- Evaluate impact on emissions and document the results

Factor 1: Cost of compliance

Factor 2: Energy impacts

Factor 3: Non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5: Evaluate visibility impacts

 

92 Summary of WRAP RMC BART Modeling for Arizona, Draft Number 5, May 25, 2007. Also, ASARCO 

response letter, July 11, 2013, ENVIRON memo attachment, March 4, 2012, ("H-09 2013-03-04 ENVIRON reportAsarco-Hayden-BART.pdf".

93 40 CFR 51.308(e)(1)(ii)(C).

94 Letter from Krishna Parameswaran, ASARCO, to Gregory Nudd, EPA dated March 6, 2013, page 15.

95 See July 6, 2005 BART guidelines, 40 CFR 51, Regional Haze Regulations and Guidelines for Best Available 

Retrofit Technology Determinations.
Page 74 of 133

Step 5 – Select BART

As described in the following sections, we are proposing the following BART limits for 

the ASARCO Hayden Smelter:

Table III.E-1: Summary of Proposed BART determinations

Pollutant Emission Limit Control Technology1

Hoboken Converters

NOX NA No additional controls

SO2 99.7% Double contact acid plant control of gases 

collected by primary and secondary capture 

systems

Electric Furnace

SO2 NA No additional controls

1

These control technologies are only listed for reference, as the facility is not required to install the

listed technology to meet the BART limit

III.E.2. Facility Description

The Freeport-McMoRan Miami, Inc. (FMMI) Smelter is located in Miami, Arizona, in Gila 

County approximately 120 miles north of Tucson and 80 miles east of Phoenix. The smelter and 

adjacent open pit copper mine are owned and operated by Freeport McMoRan Copper and Gold.

Smelting at FMMI is a four step process. Copper concentrates are melted in the IsaSmeltTM 

furnace with oxygen enriched air, where the concentrate forms a copper rich matte layer and an 

iron rich slag layer. The mix is transferred to the electric furnace where the two layers are 

allowed to separate. The matte, which is approximately 55 percent copper, is then transferred to 

the converters.

FMMI is the only smelter in the country that uses the Hoboken converter (converters 2-5). 

Hoboken converters are similar to the more common Peirce-Smith converters except that they 

are fitted with an inverted U-shaped side flue to siphon off gases directly to a collection system. 

The output of the converters, called blister copper, is fed to the anode furnaces where it is refined 

electrolytically to a product that is over 99% pure copper.

FMMI also operates a remelt/mold pouring furnace where scrap copper is melted in a reducing 

atmosphere containing natural gas and steam. The remelt/mold pouring vessel is sometimes used 

to hold molten blister copper when an anode furnace is not available.

The Arizona Regional Haze State Implementation Plan (SIP) identified the Hoboken converters 

(converters 2-5), the electric furnace, and the remelt/mold pouring furnace were installed in 1974 

and are subject to BART for sulfur dioxide (SO2), nitrogen oxides (NOx), and particulate matter 
Page 75 of 133

(PM10). FMMI later provided documentation that the pour/remelt furnace was in operation 

before 1962 and appeared in facility diagrams as early as 1956. Thus, the pour/remelt furnace is 

not BART-eligible.96 Table III.E-2 lists the converters and other equipment subject to BART at 

FMMI.

Table III.E-2: Converters and Other Potentially BART-Eligible Equipment at FMMI

Unit Description Date 

Installed

BART 

Eligible

Converter #1 Inspiration, 200 tons per cycle 1965 No

Converter #2 Hoboken, 130 tons per cycle 1974 Yes

Converter #3 Hoboken, 130 tons per cycle 1974 Yes

Converter #4 Hoboken, 130 tons per cycle 1974 Yes

Converter #5 Hoboken, 130 tons per cycle 1974 Yes

IsaSmelt Furnace Mt. Isa 1.1 MMTPY primary furnace 

aerated by oxygen-enriched air

1991 No

Electric Furnace Elkem, 3100 tons capacity, unaerated, 

heated by electricity with natural gas as 

a backup fuel

1974 Yes

Pour/Remelt Furnace Pierce Smith, 250 ton capacity 1956 (or 

earlier)

No

Converters

The Hoboken converters are fitted with an inverted U-shaped side flue to siphon off gases 

directly to a collection system. Collected gases are ducted to a gas cleaning plant to remove PM 

and a double contact sulfuric acid plant that converts SO2 to sulfuric acid. Some of the gases 

leaving the sulfuric acid plant may be ducted to a magnesium oxide scrubber if needed to further 

control SO2 emissions. There is no secondary collection system. Any gases that escape the 

primary collection system are emitted through what FMMI calls the “roofline monitors,” which 

appear to be a large opening in the roof of the building.

Because the converters are heated by the combustion of natural gas they are also sources of NOx

emissions.

Electric Furnace

The electric furnace is a 3,100 ton capacity electrically heated vessel where the liquid output of 

the IsaSmelt is allowed to separate into an iron rich slag layer and a copper rich matte layer. 

Before the installation of the IsaSmelt, FMMI used the electric furnace as the primary furnace in 

which oxygen enriched air was introduced to the melt. Today FMMI does not actively oxygenate 

the melt in the electric furnace. 

 

96 Letter from Todd Weaver, FMMI to Mr. Gregory Nudd, EPA. (March 6, 2013).
Page 76 of 133

SO2 emissions from the electric furnace are collected and controlled by the sulfuric acid plant 

system. In addition, there is a secondary capture system that collects emissions that evade the 

primary collection system and ducts emissions to be controlled by the vent fume scrubber. 

Because the electric furnace is electrically heated it does not emit measurable quantities of NOx.

Baseline Emissions

Neither FMMI nor ADEQ identified baseline emissions for FMMI. We are considering 2010 

emissions as the baseline because ADEQ provided the most detailed emissions information from 

this year with their BART SIP submittal and because FMMI uses 2010 as a basis for calculating 

2011 and 2012 SO2 fugitives through their sulfur balance method.

FMMI reports point source SO2 emissions to ADEQ by stack and performs a mass-balance 

equation to determine uncollected emissions. Table III.E-3 contains SO2 emissions in tons per 

year reported by FMMI to ADEQ for the acid plant duct, acid plant bypass duct, and the vent 

fume duct.97

The BART-eligible emissions from the acid plant were determined based on FMMI and ADEQ’s 

estimate that 35 percent of SO2 sent to the acid plant is emitted by the converters and 65 percent 

by the IsaSmelt and electric furnace. Because it is not possible to differentiate which converter 

emissions are from the one converter that is not BART-eligible, we are treating all converter 

emissions as subject to BART. BART-eligible emissions from the vent fume duct were set at

seven tons per year based on our estimate of the share of emissions originating from the electric 

furnace. BART-eligible emissions that are currently uncollected were determined based on 

EPA’s mass balance method.

Total uncollected emissions were calculated by a mass balance method by EPA. This mass 

balance method agrees within one ton with the “fugitive” emissions total calculated by FMMI 

and reported to ADEQ. FMMI calculates fugitive SO2 emissions using a sulfur balance method 

defined in their Title V permit. Because the sulfur balance method does not differentiate between 

emissions from BART eligible and non-BART eligible units, EPA estimated the magnitude of 

BART-eligible uncollected SO2 emissions by assuming a range of collection efficiencies of the 

existing capture system associated with the Hoboken converters from 95 to 98 percent.

Table III.E-3: FMMI 2010 Baseline SO2 Emissions in TPY

Acid Plant Duct Acid Plant 

Bypass

Vent Fume Duct Uncollected

SO2 1,415 93 331 8,472

BART-Eligible 495 33 7 3,231 – 8,078

FMMI reports potentially BART-eligible NOx emissions from the acid plant duct and from 

“natural gas combustion.” FMMI estimates that 15 percent of NOx emitted from the acid plant 

 

97 The vent fume duct is the stack for a wet scrubber used to control emissions collected by the IsaSmelt secondary 

collection system, other collection systems associated with conveyors that are not BART-eligible, and emissions 

collected by the BART-eligible electric furnace secondary collection system.
Page 77 of 133

duct originate from the BART-eligible converters. “Natural gas emissions” includes emissions 

from the converter burners, but it is not possible to separate the BART eligible emissions from 

ineligible emissions, so we are conservatively assuming that all these emissions are BART 

eligible.

Table III.E-4: FMMI 2010 Baseline NOx Emissions in TPY

Acid Plant Duct Natural Gas Combustion

NOx 154 15

BART-Eligible 23 15

III.E.3. General Approach to Five-Factor Analysis

This section contains a general description of our approach to the five-factor analysis, and 

discusses certain elements of our approach that are common to each of the pollutant-specific 

analyses performed for the Freeport McMoRan Smelter.

Factor 1: Cost of Compliance

FMMI did not provide publicly available control cost information. When necessary, we used cost 

information provided by ASARCO for similar projects to estimate the capital and operating costs 

for control equipment. When cost information from ASARCO was not available, we used the 

best, published data available as documented in the BART analyses that follow.

Factor 2: Energy Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common 

elements relating to this factor discussed here. Pollutant-specific discussions of these issues are 

included in the following sections. 

Factor 3: Non-air Quality Impacts

Given the differences in the technologies for NOX and SO2 control, there are no common 

elements relating to this factor discussed here. Pollutant-specific discussions of these issues are 

included in the following sections. 

Factor 4: Remaining Useful Life

Because we are not aware of any regulatory requirements to shut down any of the BART-eligible 

units or any plans to remove them from service, we have used a 20-year amortization period, as 

noted in the EPA Cost Control Manual, as the remaining useful life of the facilities considered in 

this proposed action.

Factor 5: Visibility Impacts

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full FMMI Miami modeling results, including 
Page 78 of 133

for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, and 8a, 

can be found in the tables and bar graphs in TSD Appendix B and in the spreadsheet

FMMI_visibility_results.xlsx.

A large part of FMMI's emissions are fugitive, not vented through a stack but rather through a 

large opening the building roof. This could be modeled as a point source stack, but the buoyant 

line source algorithm seems better suited to these emissions. On the other hand, that algorithm in 

CALPUFF has considerably longer run times than the point source algorithm, so if the two 

approaches yield similar results, there would be a time savings if point source algorithm were 

used. To investigate this, EPA ran the CALPUFF model both ways; these runs were done in 

August 2013, using an older estimate of the emissions. EPA found that the two algorithms gave 

different results; which gave higher impacts depended on the Class I area examined. For 

Superstition Wilderness, which had much the highest impacts of any area, impacts ranged from 3 

to 13% lower when the fugitives were modeled as a point source. EPA chose to use the buoyant 

line source algorithm, since it better characterized the actual source configuration, and differing 

results from the point source algorithm meant it could not be used as quicker substitute. The 

results are presented more fully in the spreadsheets FMMI_cpf_inputs_experiment.xlsx, 

FMMI_vis_buoyant_line_experiment.xlsx, and FMMI_vis_point_experiment.xlsx

III.E.4. BART Analysis for SO2

Converters

Step 1 – Identify all available technologies

We identified two possible control technologies for controlling SO2 emissions from the 

converters:

1. Double contact acid plant

2. Wet scrubbing

Because FMMI already uses the two available control technologies in series to control SO2

emissions currently captured from the converters, we are not considering the addition of 

additional controls as BART, but are considering applying the existing system to emissions that 

remain uncaptured in the current configuration.

Double Contact Acid Plant

A double contact acid plant uses a solid state catalyst to convert SO2 to SO3 which reacts with 

water to form sulfuric acid. Sulfuric acid plants typically are designed to control feed streams 

containing several percent SO2 so the exothermic catalytic reaction can operate autothermally. 

However, acid plants can be designed to process feed streams that contain only a fraction of a 

percent of SO2, although it may be necessary to heat the inlet gas stream or the catalyst. In 1984, 

EPA reported that SO2 conversion rates of 99.8 percent and above can be achieved by double 

contact acid plants operating in steady state.98

 

98 “Review of New Source Performance Standards for Primary Copper Smelters,” US EPA, Office of Air Quality 

Planning and Standards, March 1984, EPA 450/3-83-018a.
Page 79 of 133

There are two types of catalysts used in double contact acid plants. The traditional catalyst uses a 

potassium/vanadium salt mixture on a silica substrate. The other is a cesium promoted catalyst, 

where some of the potassium in a traditional catalyst is replaced with an equal molar quantity of 

cesium. According to Monsanto, the cesium promoted catalyst is more stable, less prone to 

deactivation, and active at lower temperatures. Traditional and cesium promoted catalysts can be 

used in combination, typically in the first and fourth passes of a double contact acid plant.99

As noted above, FMMI currently uses a double contact acid plant to control SO2 emissions 

captured from the Isasmelt and converters. FMMI reports that approximately 10 percent of the 

catalyst used in the fourth pass is cesium promoted.100

Wet Scrubbing

Wet scrubbing involves the reaction of SO2 with liquid phase absorbents to yield sulfur 

compounds that can be sold, reprocessed, or discarded. The absorbent can be based on calcium 

oxide (CaO), magnesium oxide (MgO), or sodium hydroxide (NaOH). Wet scrubbing is 

commonly used in many industries for control of SO2. FMMI uses magnesium oxide scrubbers 

to control acid plant tailstack emissions “when necessary.”

Step 2 – Eliminate technically infeasible options

Both double contact acid plants and wet scrubbing are technically feasible and are being used at 

FMMI.

Step 3 – Evaluate control effectiveness of remaining control technologies

Based on SO2 acid plant emissions and sulfuric acid production data provided to EPA by FMMI, 

we calculate that the existing acid plant and tailgas scrubber system is controlling at least 99.69 

percent of the SO2 ducted to the acid plant.101

Step 4 – Evaluate Impacts

Factor 1: Cost of Compliance

In a rule issued on June 22, 2012, EPA established a one-hour SO2 standard of 75 ppb.102 As a 

result of the new standard, a nonattainment area based on FMMI was established by EPA and the 

State of Arizona is required to prepare a SIP to bring the area into attainment. On June 27, 2013, 

EPA requested from FMMI any plans it may have developed as a result of the nonattainment 

determination.

In response to this data request by EPA, FMMI reported that it planned to comply with the onehour SO2 standard by improving the converter mouth covers, reconfiguring the roofline capture 

 

99 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, Item #9 (January 25, 2013).

100 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Appendix J (January 25, 2013).

101 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Appendices A and C (January 25, 2013).

102 75 FR 35520
Page 80 of 133

system and routing the captured emissions to the existing acid plant.103 Because FMMI indicated 

that there was capacity at the existing acid plant for these emissions we are not considering the 

more expensive options of constructing a new acid plant or wet scrubber.

FMMI did not provide cost information that could be made publicly available for the projects 

presented in the July 2013 letter. However, in a separate response, ASARCO estimated that 

replacing the five existing converters, improving the primary and secondary capture systems, 

adding a tertiary capture system, installing a common ESP, and additional improvements would 

cost $95,700,000.104 We assumed that a similar project that did not require replacement of the 

converters, would be more modestly priced and estimated costs using a capital cost of 

$47,850,000. We annualized capital costs assuming a 20 year lifespan and a 7 percent interest 

rate and assumed an operation and maintenance cost of 50 percent of the capital cost.

We applied a control efficiency of 99.69 percent, which the existing acid plant and tailstack 

scrubber system is currently achieving with very limited cesium catalyst use. The emission 

reduction was applied to 85 percent of the currently uncaptured SO2 emissions from the 

converters.

Control 

Effectiveness

Tons SO2

Reduced

Capital Cost Annualized 

Capital 

Cost

Annual 

Variable 

Cost

Total 

Annual 

Cost

$/ton SO2

Removed

99.69% 2,379 –

6,845

$47,850,000 $4,516,701 $2,258,351 $6,775,052 $990 -

$2,474

Factor 2: Energy Impacts

We do not anticipate significant energy impacts resulting from capturing and ducting additional 

emissions to the existing SO2 control system.

Factor 3: Non-air Quality Impacts

Non-air quality impacts from venting additional captured emissions to the existing acid plant are 

not expected to be significant given that FMMI already has the capacity to handle and store the 

much larger quantities of sulfuric acid produced by emissions captured from the IsaSmelt and 

converter primary capture systems.

Factor 4: Remaining Useful Life

The BART-eligible converters have each been in place for approximately 40 years and FMMI 

has not indicated that any of them would be replaced during the 20 year capital cost recovery 

period.

Factor 5: Visibility Impacts

 

103 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Item 2 (July 12, 2013).

104 Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 11, 2013.
Page 81 of 133

As shown in Table III.E-5, installing a secondary capture system to collect and direct SO2

emissions from the converters to the acid plant, the maximum 98th percentile baseline 

improvement ranges from a low of 0.41 dv to a high of 1.06 dv at Superstition WA.

Table III.E-5: Visibility Modeling of SO2 Control Scenarios, Visibility Impacts

Class I Area

Control Scenario

High Base 

case

(basehi)

High Base 

converter 85% 

capture (opt1hi)

Low Base

case

(baselo)

Low Base

converter 85% 

capture (opt1lo)

Bosque del Apache Wild. 0.15 0.04 0.07 0.02

Chiricahua NM 0.36 0.09 0.16 0.06

Chiricahua Wild. 0.35 0.09 0.16 0.06

Galiuro Wild. 0.56 0.16 0.28 0.12

Gila Wild. 0.34 0.08 0.16 0.05

Mazatzal Wild. 0.64 0.19 0.32 0.15

Mount Baldy Wild. 0.27 0.07 0.13 0.04

Petrified Forest NP 0.33 0.08 0.16 0.06

Pine Mountain Wild. 0.43 0.11 0.20 0.08

Saguaro NP 0.45 0.11 0.21 0.08

Sierra Ancha Wild. 0.70 0.30 0.42 0.25

Superstition Wild. 3.61 2.55 2.86 2.45

Maximum 3.61 2.55 2.86 2.45

Cumulative (sum) 8.18 3.85 5.12 3.42

Number of areas >= 0.5 

dv 4 1 1 1

Table III.E-6: Visibility Modeling of SO2 Control Scenarios, Visibility Benefits

Control Scenario

Class I Area

High Base 

case

(basehi)

High Base 

converter 85% 

capture (opt1hi)

Low Base 

case

(baselo)

Low Base

converter 85% 

capture (opt1lo)

Bosque del Apache Wild. 0.12 0.05

Chiricahua NM 0.27 0.10

Chiricahua Wild. 0.27 0.10

Galiuro Wild. 0.40 0.17

Gila Wild. 0.26 0.10

Mazatzal Wild. 0.44 0.17

Mount Baldy Wild. 0.20 0.08

Petrified Forest NP 0.25 0.10

Pine Mountain Wild. 0.32 0.12
Page 82 of 133

Saguaro NP 0.34 0.13

Sierra Ancha Wild. 0.40 0.17

Superstition Wild. 1.06 0.41

Maximum 1.06 0.41

Cumulative (sum) 4.33 1.70

Number of areas >= 0.3 

dv 6 0 1

Step 5 – Select BART

We have determined that improvements to the primary capture system and construction of 

hooding and ventilation systems to capture SO2 emissions that escape the converter primary 

capture system and ducting the emissions to existing controls is feasible, cost effective, and will 

not result in significant adverse impacts. As noted above, the RHR allows for use of equipment 

requirements or work practice standards in lieu of a numeric limit where “technological or 

economic limitations on the applicability of measurement methodology to a particular source 

would make the imposition of an emission standard infeasible.”105 In this instance, we propose to 

find that technological limitations on the source’s ability to measure accurately uncaptured SO2

emissions make numeric capture efficiency infeasible. Therefore, we are proposing to prescribe 

specific equipment for capture of SO2 emissions, in addition to numeric control efficiency and 

related compliance requirements. Specifically, we are proposing the following as BART for SO2

from the converters:

1. Improvements to the primary capture system and construction of a secondary capture 

system and application of the MACT QQQ standards to the capture systems.

2. An SO2 control efficiency of 99.69 percent, 30-day rolling average, on all SO2 captured 

by the primary and secondary control systems.

3. Compliance with the SO2 BART limit may be verified either through the use of SO2

CEMS before and after controls or by using post-control CEMS and acid production 

rates. A limit of 4.06 lbs SO2 emissions per tons of sulfuric acid production is equivalent 

to 99.69 percent control.

Electric Furnace

Step 1 – Identify all available technologies

We identified the same two control technologies for the electric furnace: a new double contact 

acid plant and a wet scrubber.

Step 2 – Eliminate technically infeasible options

 

105 40 CFR 51.308(e)(1)(iii). See also 40 CFR 51.100(z)(defining “emission limitation” and “emission standard” to 

include “any requirements which . . . prescribe equipment . . . for a source to assure continuous emission reduction.”
Page 83 of 133

Both technologies are technically feasible for the reduction of SO2.

Step 3 – Evaluate control effectiveness of remaining control technologies

Based on SO2 acid plant emissions and sulfuric acid production data provided to EPA by FMMI, 

we calculate that the existing acid plant and tailgas scrubber system is controlling at least 99.69 

percent of the SO2 ducted to the acid plant.106 In a recent application for a significant permit 

revision, FMMI provided control efficiencies of 62-71 percent for scrubbers using magnesium 

oxide, but claimed that 98 percent reduction would be possible using sodium hydroxide.107

Existing acid plant system: 99.69%

Existing wet scrubber: 62-71%

Improved wet scrubber: 98%

Step 4 – Evaluate Impacts

Factor 1: Cost of Compliance

We estimated the emissions from the electric furnace by multiplying the AP 42 emission factors 

for a cleaning furnace (table 12.3-3) and conveyor return (table 12.3-12) times the 2010 

concentrate throughput provided by FMMI. This results in uncontrolled SO2 emissions from the 

electric furnace of 379 tons per year. 

FMMI has indicated to EPA that emissions from the electric furnace are controlled by the acid 

plant system. In addition, a secondary control system ducts gases not captured by the primary 

capture system to the vent fume scrubber. The one improvement to controls identified was 

upgrading the scrubber, which currently uses magnesium oxide, to use sodium hydroxide, which 

could increase the control efficiency to 98 percent. Because the scrubber is a secondary control 

device, however, this would likely result in an emissions decrease of no more than 5 to 10 tons 

per year. We use a range of values because of the uncertainty over how much SO2 from the 

electric furnace is captured and ducted to the acid plant as opposed to the wet scrubber.

Considering only the cost difference between magnesium, we project an increase in operating 

costs of at least $2,000,000 per year. Because most of the SO2 controlled by the vent fume 

scrubber is emitted from the IsaSmelt, which is not BART-eligible, this results in control costs of 

$200,000 - $400,000 per year.

Control 

Effectiveness

Tons SO2

Reduced

Capital 

Cost

Annualized 

Capital 

Cost

Annual 

Variable 

Cost

Total 

Annual 

Cost

$/ton SO2

Removed

98% 5-10 - - $2,000,000 $2,000,000 $200,000 -

$400,000

Factor 2: Energy Impacts

 

106 Letter from Derek Cooke, FMMI to Thomas Webb, EPA, Appendices A and C (January 25, 2013).

107 Application for a Significant Permit Revisions, FMMI to ADEQ, July 2013.
Page 84 of 133

We do not anticipate significant energy impacts resulting from capturing and ducting additional 

emissions to the existing SO2 control system.

Factor 3: Non-air Quality Impacts

Non-air quality impacts from venting additional captured emissions to the existing scrubber are 

not expected to be significant given that FMMI is already controlling much larger quantities of 

SO2 in the existing scrubber and managing the wastewater and sludge that result.

Factor 4: Remaining Useful Life

We are not aware of any limits on the useful life of the electric furnace.

Factor 5: Visibility Impacts

Our modeling results did not demonstrate even modest visibility improvements at any Class I 

areas from this option. Improvements were 0.004 dv or less at each Class I area, and only 0.008 

dv for the cumulative sum over all areas. These are negligible visibility improvements over the 

baseline levels, as expected from the small emission reductions associated with this option.

Step 5 – Select BART

Based on the cost of compliance, we propose as BART existing controls for SO2 for the electric 

furnace. While we would prefer to set a numeric emission limit in order to ensure that SO2

emissions from the electric furnace do not increase in the future, such a limit is impracticable 

because emissions from the electric furnace are commingled with emissions from non-BART 

eligible units in the vent fume stack. Therefore, consistent with 40 CFR 51.308(e)(1)(iii), we 

propose a work practice standard prohibiting active aeration of the electric furnace.

III.E.5 BART Analysis for NOx

Step 1 – Identify all available technologies

We identified low-NOx burners (LNB) as an available control technology

Step 2 – Eliminate technically infeasible options

LNB are technically feasible for natural gas combustion.

Step 3 – Evaluate control effectiveness of remaining control technologies

According to the Documentation Report accompanying AirControlNET, LNB retrofits can 

reduce NOx emissions by 50 percent.108

 

108 AirControlNet, Version 4.1, Documentation Report by E.H. Pechan and Associates, Inc. for U.S. EPA, Office of 

Air Quality, Planning, and Standards, May 2006. Page III-445.
Page 85 of 133

Step 4 – Evaluate Impacts

Factor 1: Cost of Compliance

According to the Documentation Report accompanying AirControlNET, the cost to retrofit 

process heaters with LNB is $2,200 per ton of NOx controlled. 

Factor 2: Energy Impacts

We expect energy impacts to be minimal.

Factor 3: Non-air Quality Impacts

We expect non-air quality impacts to be minimal.

Factor 4: Remaining Useful Life

We are not aware of any limits on the useful life of the project.

Factor 5: Visibility Impacts

The maximum modeled 98th percentile visibility impact resulting from baseline NOx emissions 

from the Miami Smelter is 0.11 dv.109 Thus, the maximum visibility benefit of controls is less 

than 0.11 dv.

Step 5 – Select BART

Given the small potential for visibility improvement, we propose that controlling these NOx

emissions is not warranted for purposes of BART. However, in order to ensure that NOx 

emissions do not increase in the future, we propose to set a 12-month rolling cap of 40 tons of 

NOx from the subject-to-BART units, which is equivalent to the de minimis level of emissions 

set out in the RHR and is roughly equivalent to current annual emissions from these units.

IV. Reasonable Progress Goals and Controls

IV.A. Introduction and Background

Reasonable Progress Goals are the target visibility levels for Class I areas at the end of the 

planning period in 2018. The Regional Haze Rule requires the State, or EPA in the case of a FIP, 

to set RPGs by considering four factors: “the costs of compliance, the time necessary for 

compliance, the energy and non-air quality environmental impacts of compliance, and the 

 

109 Summary of WRAP RMC BART Modeling for Arizona, Draft Number 5, May 25, 2007. Also, ASARCO 

response letter, July 11, 2013, ENVIRON memo attachment, March 4, 2012, ("H-09 2013-03-04 ENVIRON reportAsarco-Hayden-BART.pdf".
Page 86 of 133

remaining useful life of any potentially affected sources.”

110 The RPGs must provide for an 

improvement in visibility on the worst days and ensure no degradation in visibility on the best 

days during the planning period. Furthermore, if the projected progress RPGs for the worst days 

are is less than the Uniform Rate of Progress (URP)111, then the State or EPA must demonstrate, 

based on the factors above, that it is not reasonable to provide for a rate of progress consistent 

with the URP.112

In our final rule on the Arizona RH SIP published on July 30, 2013113, we partially approved and 

partially disapproved certain elements of the State's reasonable progress (RP) analysis. In 

particular, we approved the State's decision to focus on NOX and SO2 sources and not to require 

additional controls on point sources of SO2 for this planning period. However, we disapproved 

the State’s RPGs for the worst days and best days as well as its RP analyses and determinations 

for area sources of SO2 and NOX and point sources of NOX. Our proposed FIP must address

these issues. 

The Federal Register notice for our proposed action contains a complete and comprehensive 

discussion of this topic. This TSD provides additional details on the Point Source NOX analyses 

and Area Source NOX and SO2 analyses.

IV.B. CalPortland Cement Company Rillito Plant

IV.B.1. Summary

This analysis documents the basis for the determination of Reasonable Progress (RP) control 

options for control of nitrogen oxide (NOX) emissions at the Rillito Cement Plant, operated by

CalPortland Cement Company (CPCC or CalPortland), previously Arizona Portland Cement 

Company. The facility lies about 10 miles northwest of the city of Tucson, Arizona.

Pursuant to 40 CFR 51.308(d)(1), an RP analysis must address four factors: the costs of 

compliance, the time necessary for compliance, the energy and non-air quality environmental 

impacts of compliance, and the remaining useful life of any potentially affected sources. In 

addition, EPA Guidance allows for the consideration of “other relevant factors” as part of an RP 

analysis.114 In this case, we have determined that the “degree of improvement in visibility” is 

another relevant factor because the purpose of the four-factor analysis is to determine what 

degree of progress toward natural visibility conditions is reasonable.

The analysis consists of the following steps:

Step 1 – Identify All Available Technologies

 

110 40 CFR 51.308(d)(1)(i)(A).

111 For a more detailed discussion of the rule requirements and an explanation of the URP, please see our December 

21, 2012 proposed action on the Arizona Regional Haze SIP (77 FR 75710).

112 40 CFR 51.308(d)(1)(ii).

113 78 FR 46142

114 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program at 2-3 and 2-4 (June 1, 

2007) ("RP Guidance").
Page 87 of 133

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Step 4 – Evaluate Impacts and Document Results:

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5 (Optional): Degree of improvement in visibility

Step 5 – Select Reasonable Progress Controls

Our analysis is based primarily on the following documents:

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor RP 

Analyses for TEP Springerville, APS Cholla, TEP Sundt, CalPortland Cement and 

Phoenix Cement Plants; Prepared for EPA Region 9 by University of North Carolina at 

Chapel Hill, ICF International, and Andover Technology Partners (October 3, 2012) 

(“Contractor’s Report”)

 Reasonable Progress Analysis for CalPortland Company Rillito Cement Plant Kiln, 

prepared by CalPortland Company ("CalPortland's RP Analysis"). Submitted to EPA 

May 9, 2013.

 Comments from CalPortland Company on EPA’s proposed partial approval/partial 

disapproval of the Arizona Regional Haze SIP (“CalPortland's comments”). Submitted 

June 18, 2013.

 Cost calculation spreadsheets developed by EPA, “CalPortland Cement K1-3 Cost 

Estimates (final for NPRM docket).xlsx” and " CalPortland Cement K4 Cost Estimates 

(final for NPRM docket).xlsx"

 Emission Calculation spreadsheets developed by EPA, "Cement Plant Emission 

Calculations (final for NPRM docket).xlsx"

IV.B.2. Facility Description

Overview

CPCC operates a Portland cement plant, a limestone quarry, and a rock and stone aggregate 

plant115. Figure 1 shows an aerial photo of the facility.

The facility produces Portland cement, a fine gray powder that binds sand and aggregate into 

concrete. At the Rillito Plant, cement is produced from various types of rock, including 

limestone, and calcium, silica, alumina, and iron. These materials are ground to a fine powder, 

blended in specific proportions needed for the final cement product, and heated until partially 

molten at temperatures of approximately 2,700°F in a precalciner cement kiln to produce a 

pellet-shaped, glass-hard material called clinker. The clinker is then ground with gypsum to an 

extremely fine powder, Portland cement.

The Rillito Plant currently consists of four dry process rotary kilns (Kilns 1, 2, 3, and 4) and 

clinker coolers.

 

115 The rock and stone aggregate plant is called the Twin Peaks Rock and Stone Aggregate Plant.
Page 88 of 133

Figure 1 - Aerial View of CalPortland Cement Company Rillito Plant Kilns

According to CalPortland’s Title V operating permit issued by the Arizona Department of 

Environmental Quality (ADEQ), existing Kilns 1, 2, 3, and 4 are capable of using a variety of 

fuels, including solid fuels (coal and petroleum coke), fuel oils, and natural gas. Kiln 4 is also 

designed to use and has historically used supplemental fuels such as shredded tires and wood 

chips. Kilns 1-3 have not been operated since early 2008. Table IV.B-1 shows information about 

the operation of these kilns.

Table IV.B-1: CalPortland Kiln Data

Equipment Primary Fuel Year on Line Rotary Kiln Type Capacity

(tons per day)

Kiln 1 Coal 1949 Long Dry Kiln 415

Kiln 2 Coal 1951 Long Dry Kiln 415

Kiln 3 Coal 1955 Long Dry Kiln 415

Kiln 4 Coal 1972 Preheater/Precalciner 3233

Baseline Emissions

Emissions that result from the manufacturing of Portland cement at the Rillito Plant include 

particulates, nitrogen oxides (NOX), and sulfur dioxide (SO2), and volatile organic compounds 

(VOC).

Table IV.B-2 shows the facility-wide actual emissions for the period 2005 to 2010. Table IV.B-3 

shows the actual emissions for the kiln systems for the same years. This information is based 

emissions data that CPCC reported to the ADEQ. Based on the information in these tables, 

virtually all of the NOX and SO2 emissions, as well as the majority of the particulate emissions, 

are generated from the kiln systems. A negligible amount of NOX and SO2 are generated from 
Page 89 of 133

ancillary combustion equipment at the facility. Also, the tables show that the facility-wide SO2

emissions are minimal. CPCC does not have SO2 emissions controls.

Table IV.B-2: CalPortland Facility-wide Pollutant Emissions

Year NOx

(as NO2)

SO2 PM PM10 VOC

2005 3650.0 4.8 240.2 248.0 6.8

2006 3795.2 6.6 265.1 231.2 7.1

2007 3482.5 47.5 320.3 239.8 6.9

2008 2080.0 5.4 180.0 138.5 5.2

2009 1077.0 3.4 64.7 69.1 2.3

2010 1944.0 9.7 86.8 99.6 3.5

Table IV.B-3: CalPortland Kiln Systems Pollutant Emissions

Year Equipment NOx

(as NO2)

SO2 PM PM10 VOC

2005

Kiln 1, 2, and 3 1938.6 4.02 58.9 62.5 1.7

Kiln 4 & Preheater 1711.3 0.8 22.3 48.2 5.0

Total Kiln System Emissions 3649.9 4.82 81.2 110.7 6.7

2006

Kiln 1, 2, and 3 1933.0 2.6 15.6 62.1 1.8

Kiln 4 & Preheater 1862.0 4.0 106.3 46.3 5.2

Total Kiln System Emissions 3795.0 6.6 121.9 108.44 7.0

2007

Kiln 1, 2, and 3 1737.5 42.6 27.9 57.8 1.7

Kiln 4 & Preheater 1744.8 4.9 135.6 46.5 5.1

Total Kiln System Emissions 3482.3 47.5 163.5 104.3 6.8

2008

Kiln 1, 2, and 3 148.0 1.5 8.8 8.0 0.1

Kiln 4 & Preheater 1932.0 4.0 72.8 46.5 5.0

Total Kiln System Emissions 2080.0 5.5 81.6 54.5 5.1

2009

Kiln 1, 2, and 3 0.0 0.0 0.0 0.0 0.0

Kiln 4 & Preheater 1077.0 3.4 12.8 25.5 2.3

Total Kiln System Emissions 1077.0 3.4 12.8 25.5 2.3

2010

Kiln 1, 2, and 3 0.0 0.0 0.0 0.0 0.0

Kiln 4 & Preheater 1944.0 9.7 23.5 46.7 3.5

Total Kiln System Emissions 1944.0 9.7 23.5 46.7 3.5

Particulate emissions are generated throughout the facility from numerous stationary and mobile 

operations. Particulate emissions also result from fugitive dust generated by activities such as 

material handling, rock crushing, paved and unpaved road traffic, and quarry drilling and 

blasting. CPCC uses baghouses and dust collectors throughout its facility, including on Kilns 1-

4, to control particulate emissions. Baghouses and dust collectors are forms of fabric filters used 

for controlling particulate emissions at efficiencies greater than 98 percent.116 Since the facility is 

already well-controlled for particulate emissions, particulate emissions are not being analyzed in 

this RP analysis. Therefore, this RP analysis only focuses on the control of NOX emissions from 

the kiln systems.

 

116 See EPA Air Pollution Control Cost Manual - Sixth Edition, Section 6: Particulate Matter Controls, EPA/452/B02-001, January 2002.
Page 90 of 133

Kilns 1, 2 and 3 are long kilns, and currently rely on good combustion practices to control NOX

emissions. Kiln 4 is a preheater/precalciner kiln. Preheater/precalciner kilns generally use 

inherent low NOX design features. NOX emissions from Kiln 4 are controlled by low NOx 

burners with indirect firing and preheater riser duct firing. Preheater riser duct firing is applicable 

to preheater/precalciner kilns. Table IV.B-4 summarizes the NOX emissions for Kilns 1-4.

Table IV.B-4: Kilns 1-4 NOx Emissions

Year

Kilns 1-3 NOx Emissions Kiln 4 NOx Emissions

Clinker 

Produced

Clinker/day 

Average

NOx 

Produced

NOx/ton 

Clinker

Clinker 

Produced

Clinker/day 

Average

NOx 

Produced

NOx/ton 

Clinker

2003 199,443 978 956 9.65 585,813 2,914 1,311 4.51

2004 356,464 977 1,836 10.36 1,062,124 3,009 2,128 3.99

2005 342,999 945 1,939 11.35 991,769 2,875 1,714 3.47

2006 368,314 1,009 1,933 10.58 1,025,652 3,034 1,862 3.65

2007 357,871 994 1,758 10.04 1,033,261 3,021 1,748 3.57

2008 30,521 649 148 9.54 1,031,530 3,043 1,932 3.76

2009 -- -- -- -- 466,445 2,549 1,085 4.73

2010 -- -- -- -- 681,963 2,024 1,947 5.75

2011 -- -- -- -- 606,935 2,003 1,630 5.44

2012 -- -- -- -- 652,774 2,382 1,586 5.86

IV.B.3. RP Analysis for NOX

Step 1 - Identify All Available Retrofit Control Technologies for NOX

NOX is generated during fuel combustion by oxidation of chemically-bound nitrogen in the fuel 

and by thermal fixation of nitrogen in the combustion air. In the cement manufacturing process, 

NOX is generated in both the burning zone of the kiln and the burning zone of a precalciner.

Generally, coal generates less NOX than does oil or gas.117

NOX control approaches applicable to the cement industry may be grouped into three categories: 

 Process control modifications - usually done to reduce heat consumption, to improve 

clinker quality, and to increase the lifetime of the equipment (such as the refractory 

lining) by stabilizing process parameters. The emphasis is on increased energy efficiency 

and productivity.

 Combustion modifications - focus on staging the combustion to minimize the amount of 

combustion that must occur at the maximum temperatures. The emphasis is on reducing 

NOX formation.

 Post-combustion or add-on controls - remove NOX that is formed in the combustion 

process.

Process control modifications can minimize NOX emissions through improved fuel efficiency.

These practices may be considered standard operating procedures. Combustion modifications 

and add-on controls actually reduce NOX formation. The available NOX controls technologies for 

cement kilns are listed in Table IV.B-5.

 

117 See AP-42, Chapter 11.6, Portland Cement Manufacturing, January 1995.
Page 91 of 133

Table IV.B-5: NOx Control Options for Cement Kilns

Category Control Options

Combustion Modifications

 Low NOX burner system (LNB)

 Low NOXx Calciner (LNC)

 Mid-kiln Firing (MKF)

 Mixing Air Technology (MAT)

Add-On Controls

 Selective Catalytic Reduction (SCR)

 Selective Non-Catalytic Reduction (SNCR)

Step 2 - Eliminate Technically Infeasible Options

Low NOX Burners (LNB)

These burners are designed to reduce flame turbulence, delay fuel/air mixing, and establish fuelrich zones for initial combustion. Some cement kiln burners are equipped with LNBs. Many of 

these systems focus on lowering the NOX formation in the calciner by air or fuel staging, by 

reburning, or by high temperature combustion. This technology is technically feasible for Kilns 

1-3. Kiln 4 already uses LNB technology with indirect firing.

Low NOX Calciner (LNC)

Most of the major cement kiln suppliers now offer “low NOX” calciner designs for new kilns.

These designs typically inject a portion of the fuel into the feed end of the kiln, countercurrent to 

the exhaust gas flow. This reducing atmosphere inhibits the formation of fuel NOX and destroys 

a portion of the NOX formed in the kiln burning zone. This technology is not technically feasible 

for Kilns 1-3, which are long dry kilns. The application of this technology to Kiln 4 would 

require a complete rebuild of the calciner due in part to the height requirement of this technology 

and local seismic requirements that would be equivalent to redesigning the source. Therefore, 

this technology is not an available technology for Kiln 4.

Mid-Kiln Firing (MKF)

This control method consists of the injection of a solid fuel into the calcining zone of a rotating 

long kiln using a specially designed feed injection mechanism. This is a form of staged 

combustion of fuels. To maintain continuity in the heat input, solid and slow burning fuels (such 

as whole tires) are most amenable for MKF. By adding fuel in the main flame at mid-kiln, MKF 

changes both the flame temperature and flame length. These changes may reduce thermal NOX

formation by burning part of the fuel at a lower temperature and by creating reducing conditions 

at the solid waste injection point which may destroy some of the NOX formed upstream in the 

kiln burning zone. MKF may also produce additional fuel NOX depending upon the nitrogen 

content of the fuel. This technology is technically feasible for Kilns 1-3, which are long dry 

kilns. This specific technology cannot be applied to Kiln 4 because it already uses a form of midkiln firing by adding supplemental fuel to the calciner.

Mixing Air Technology (MAT)
Page 92 of 133

Mixing air is the practice of injecting a high pressure air stream into a kiln to break up and mix 

stratified layers of gases within the kiln. Mixing the air improves the combustion efficiency. In 

long dry kilns, higher temperature oxygen-rich gases tend to travel along the top of the kiln while 

cooler, carbon dioxide-rich gases tend to travel along the bottom. When Mixing Air Technology 

is added, stratified kiln gases begin to rotate and mix. This technology is technically feasible for 

Kilns 1-3. CPCC has tried this technology on the Kiln 4, and it was found ineffective at reducing 

emissions from Kiln 4. Therefore, this technology is not technically feasible for Kiln 4.

Selective Catalytic Reduction

This process uses ammonia in the presence of a catalyst to selectively reduce NOX emissions 

from exhaust gases. In SCR, ammonia, usually diluted with air or steam, is injected through a 

grid system into hot flue gases which are then passed through a catalyst bed to carry out NOX

reduction reactions. Catalysts that have been used include titanium dioxide, vanadium pentoxide, 

and zeolite-based materials. The catalyst is not consumed in the process but allows the reactions 

to occur at a lower temperature. The optimum temperature for the catalyst reactions depends on 

the specific catalyst used. According to EPA guidance, base metal catalysts are useful between 

450°F and 800°F, and zeolite catalysts containing precious metals such as platinum and 

palladium are useful at 675°F to over 1100°F for high temperature operations.118

The appropriate temperature window must be maintained to assure that ammonia slip does not 

result in a visible plume. In the cement industry, basically two SCR systems are being 

considered: low dust exhaust gas and high dust exhaust gas treatment. Low dust exhaust gas 

systems require adding the SCR system after the particulate matter control device. High dust 

systems require adding the SCR system after the last cyclone without ducting. SCR is subject to 

catalyst poisoning in high dust, corrosive environments such as cement kiln exhausts. SCR 

would have to be placed after the particulate control systems. If placed after the particulate 

control systems, the exhaust gases may need to be reheated for optimum SCR performance 

unless a low temperature catalyst is used. 

While SCR has not been commercially applied to a cement plant of any type in the United States, 

SCR was tested at one cement kiln in the United States (US) in 1976, and has been installed on 

kilns at three cement plants in Europe.119 The first plant that installed SCR is Solnhofer 

Zementwerkes in Solnhofen, Germany. The facility had a pilot-scale demonstration was 

conducted in 1997–1999, and commercial installation of a high dust SCR unit in 2000. NOX

removal efficiency was typically in the range of 59–67 percent, and NOX removals of more than 

80 percent have been observed. This facility achieved NOX reductions by using a combination of 

a low NOX burner, alternative/waste fuels and either SNCR or SCR, in which the SNCR and 

SCR systems did not operate simultaneously. The facility ceased operation of its SCR system in 

January 2006, and has operated an SNCR system for NOX control since that time. The second 

plant, called Cementeria di Monselice in Bergamo, Italy, began operation of a full-scale SCR 

system in June 2006 at Cementeria di Monselice in Bergamo, Italy. The third, plant, called 

Italcementi Sarche di Calavino, also in Italy, installed an SCR unit in early 2007. However, little 

is known about the operation of SCR on the cement plants in Italy.

 

118 "Alternative Control Techniques Document Update - NOx Emissions from New Cement Kilns”, EPA-453/R-07-

006, November 2007.

119 Ibid.
Page 93 of 133

As a result, there is very little information about the effectiveness and cost of controls associated 

with SCR at cement plants.

120 Given this uncertainty, we have decided to not further evaluate

SCR for purposes of RP at this time. However, SCR for cement kilns should be re-evaluated in 

subsequent planning periods.

Selective Non-Catalytic Reduction (SNCR)

This control technique relies on the reduction of NOX in exhaust gases by ammonia or urea, 

without using any catalyst. This approach avoids the problems related to catalyst fouling and 

poisoning, as in SCR, but requires injection of the reagents in the kiln at a temperature between 

1600°F to 2000°F. Because no catalyst is used to increase the reaction rate, the temperature 

window is critical for conducting this reaction. Above 1,900°F, the amount of NH3 that oxidizes 

to NOX increases, and, in turn, the NOX reduction performance deteriorates. At temperatures at 

or below 1,600°F, unreacted NH3 emissions may rapidly increase. In PH/PC kilns, the 

temperatures at the cooler end of the rotating kiln, in the riser duct, and in the lower section of 

the cyclone preheater tower are likely to be in the temperature window appropriate for SNCR.

SNCR has been widely used for reducing NOX emissions at cement kilns. This control method is 

technically feasible for Kilns 1-4.

Table IV.B-6 summarizes the available technologies and their potential application for CPCC’s 

kilns.

Table IV.B-6: NOX Control Technologies and Potential Application121

NOx Control Option Kilns 1-3 Kiln 4

LNB Technically Feasible In Use

LNC Infeasible Infeasible

MKF Technically Feasible Infeasible

MAT Technically Feasible Infeasible

SCR Infeasible Infeasible

SNCR Technically Feasible Technically Feasible

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Low NOx Burners (LNB)

CalPortland estimated a control efficiency of 20 percent for a LNB with indirect firing. 

CalPortland’s estimate is based on the company’s experience at implementing these controls on 

the two long dry kilns at its Colton plant and site-specific details for the Rillito Plant kilns. 

Cement kiln burners specifically marketed as LNB require an indirect-fired kiln system. 

Therefore, to install a LNB in an existing direct-fired kiln, it is necessary to convert the kilnfiring system to an indirect firing system.122

 

120 See, e.g., 75 FR 54970, 54994-95 (September 9, 2010)(rejecting SCR-based performance level as best 

demonstrated technology for cement kilns, due to uncertainty over effectiveness and costs. 

121 Emissions reductions and remaining emissions based on average of annual NOX emissions for 2005 through 

2010.

122 “NOX Control Technologies for the Cement Industry”, prepared by EC/R Incorporated for the Ozone Policy and 

Strategies Group Air Quality Strategies and Standards Division, September 19, 2000.
Page 94 of 133

The NOX reduction that may be achieved with a LNB depends mainly on the operating 

parameters. With proper operation of the LNB, 15 to 40 percent reduction in NOX emissions 

should be possible.123 CalPortland’s NOX reduction estimate of 25 percent is within this range.

Thus, this is a reasonable estimate for Kilns 1, 2 and 3.

Mid Kiln Firing (MKF)

CalPortland estimated a control efficiency of 20 percent for MKF with MAT and indirect firing 

for Kilns 1, 2 and 3. CalPortland’s estimate is based on the company’s experience at 

implementing these controls on the two long dry kilns at its Colton plant and site-specific details 

for the Rillito Plant kilns. MKF can result in a 11 to 55 percent reduction in NOX emissions.

CalPortland’s NOX reduction estimate of 20 percent is within this range.124 Thus, this is a 

reasonable estimate for Kilns 1, 2 and 3.

Selective Non-Catalytic Reduction (SNCR)

CalPortland estimated a control efficiency of 25 percent for SNCR with MAT for Kilns 1, 2 and 

3. CalPortland’s estimate is based on the company’s experience at implementing these controls 

on the two long dry kilns at its plant in Colton, California (Colton Plant) and site-specific details 

for the Rillito Plant kilns. SNCR has been applied to a number of cement kilns in the U.S. 

However, nearly all of these applications have been on modern preheater/precalciner kilns and 

only limited testing has been conducted on long dry kilns such as Kilns 1, 2 and 3 at the Rillito 

Plant. The primary reason for this is the location within the kiln system where reagent injection

occurs. In a preheater/precalciner kiln, reagent injection occurs at the exit of the kiln in the lower 

part of the preheater tower. This injection location is readily accessible using conventional 

injection technology. In a conventional long kiln the appropriate temperature window is in the 

middle of the kiln. Thus, injection must occur mid-kiln because this is where the gas temperature 

is in the proper range for the NOX reduction reactions to occur. Because of the rotating nature of 

a long kiln, continuous injection of ammonia- or urea-based reagents is presently not possible. 

Specialized injection systems are required to allow reagent injection in a mid-kiln location.125

Due to these technical challenges, there is little control efficiency data regarding the use of 

SNCR on long dry kilns. CalPortland estimated a control efficiency of 25 percent for SNCR with 

MAT for Kilns 1, 2 and 3 based on the company’s experience at implementing these controls on 

the two long dry kilns at its Colton Plant. Based on emissions data for the Colton Plant kilns, we 

consider this estimate to be overly conservative and we find the use of a 30% control efficiency 

for SNCR appropriate for Kilns 1-3.

CalPortland based its emission and cost estimates for Kiln 4 (the preheater/precalciner) upon an 

SNCR control efficiency of 30%, citing its experience with its SNCR optimization on a kiln at 

another CalPortland facility, the Mohave Plant. In an SNCR optimization report for the Mohave 

Plant submitted on August 30, 2013, CalPortland provided emission data from the first seven 

months of 2013 in which adjustments were made to multiple control technology operating 

parameters. Emission data provided in this report indicates a range of SNCR control efficiency 

of 30-60% at the Mohave Plant, depending upon operating parameters. CalPortland’s use of 30% 

SNCR control efficiency would correspond to the low end of this estimate. However, we note 

 

123 Ibid 10.

124 Ibid 10.

125 Ibid 10.
Page 95 of 133

that the emission data from the Mohave optimization period is highly variable (due to the 

operational variability that is part of the optimization), and that CalPortland has not determined 

what control efficiency or emission rate is appropriate to use as the basis for an emission limit.

CalPortland will soon start a 270-day demonstration phase at Mohave, at the conclusion of which 

it will propose a rolling 30-day limit for the kiln. 

We note that the effectiveness of SNCR in preheater/precalciner cement kilns can vary 

depending upon factors such as temperature, residence time, ammonia injection rates and 

patterns, and inlet NOx concentrations. Emission data and feasibility studies from the following 

control technology determinations, each involving a preheater/precalciner kiln operating with 

existing combustion controls, indicate the following control efficiencies.

Table IV.B-7: Preheater/precalciner Kiln SNCR Control Efficiency

Company Plant State

SNCR 

Ctrl 

Efficiency

Reference

St. Mary's Cement Charlevoix MI 50% EPA Docket No. EPA-R05-OAR-2010-0954

Holcim Florence Plant CO 45% http://www.colorado.gov/cs/Satellite/CDPHEAP/CBON/1251595092457

Holcim Trident Plant MT 50% EPA Docket No. EPA-R08-OAR-2011-0851-

0037, -0235, and the final rule at -0212

Ash Grove Montana City Plant MT 50% EPA Docket No. EPA-R08-OAR-2011-0851-

0038, -0160

Based on this information, and given the range of SNCR performance indicated from the first six 

months of Mohave Plant optimization protocol collection, we consider the use of a 50% control 

efficiency for SNCR appropriate for Kiln 4. However, we are seeking comment on whether this 

control efficiency is appropriate. If we receive additional information or data providing more 

site-specific information that justifies a different control efficiency at the Rillito Plant, we will 

revise our analysis accordingly.

The following tables summarize emission estimates for the Rillito Plant kilns as based on the 

control efficiencies described above. Baseline emissions for Kilns 1-4 can be found in our 

contractor's report, and detailed emission calculations can be found in our docket.126 In general, 

our estimates of baseline emissions do not differ substantially from those contained in 

CalPortland's RP Analysis. The primary differences in control scenario emission estimates is the 

result of the different assumptions regarding SNCR control efficiency used in our calculations 

(30 and 50%) and in CalPortland's RP Analysis (25 and 30%).

 

126 "Cement Plant Emission Calculations (final for NPRM docket)."
Page 96 of 133

Table IV.B-8: Kiln 1-3 NOx Control Effectiveness127

NOx Control Option Ctrl Efficiency

(%)

NOX Reduction

(tpy)

Remaining NOX Emissions

(tpy)

Baseline (No Control) -- -- 626

LNB 20 125 501

MKF w/ MAT 20 125 501

SNCR w/ MAT 30 188 438

Table IV.B-9: Kiln 4 NOx Control Effectiveness

NOx Control Option Ctrl Efficiency

(%)

NOX Reduction

(tons/year)

Remaining NOX Emissions

(tons/year)

Baseline (No Control) -- -- 2082

SNCR 50 1041 1041

Step 4 – Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Tables IV.B-10 and IV.B-11 show the cost estimates for Kilns 1-4 for the remaining NOX control 

options. In general, we have relied primarily upon the cost information submitted in 

CalPortland's RP Analysis. However, we have revised the values of certain line items downward 

from CalPortland's RP analysis in instances where CalPortland's estimates were unsupported or 

not allowed by EPA's Control Cost Manual. Detailed cost calculation spreadsheets are contained 

in our docket.128

Table IV.B-10: Kilns 1-3 Cost Estimates129

Control Option Ctrl Efficiency

(%)

NOX

Reduction

(tpy)

NOX Emissions Annual 

Cost

($/yr)

Cost 

Effectiveness

($/ton) (lb/ton) (tpy)

Baseline 

(No Control) -- -- 10.54 626 -- --

LNB 20% 125 8.43 501 $907,237 $7,246

MKF 20% 125 8.43 501 $1,055,313 $8,429

SNCR+MAT 30% 188 7.38 438 $1,051,107 $5,603

 

127 Data for kilns 1-3 is per kiln, not total.

128 “CalPortland Cement K1-3 Cost Estimates (final for NPRM docket).xlsx” and “ CalPortland Cement K4 Cost 

Estimates (final for NPRM docket).xlsx”

129 Data for kilns 1-3 is per kiln, not total.
Page 97 of 133

Table IV.B-11: Kiln 4 Cost Estimates

Control Option Ctrl Efficiency

(%)

NOX Reduction

(tpy)

NOX Emissions Annual 

Cost

($/yr)

Cost 

Effectiveness

($/ton) (lb/ton) (tpy)

Baseline -- -- 4.10 2,082 -- --

SNCR 50% 1,041 2.05 1,041 $1,020,088 $1,047

Factor 2: Time necessary for compliance

CPCC also estimates that several years would be required to design, fabricate, construct, and 

operate any control equipment. Including the time needed to obtain the appropriate 

preconstruction approvals, CPCC estimates that the time needed to install the control equipment 

is approximately 3 years. Therefore, we expect that any controls could be installed within this 

planning period, i.e. by December 31, 2018. 

Factor 3: Energy and non-air quality environmental impacts of compliance

The installation and operation of SNCR would require increased energy usage. According to 

CPCC, increased energy use for Kilns 1, 2, and 3 would be approximately 2,838 MWh per year 

per kiln at a 90 percent capacity factor, and 118 MWh per year at a 90 percent capacity factor for 

Kiln 4. The cost of this additional energy usage is included in the cost analysis.

Non-air quality environmental impacts associated with SNCR also include the hazards of 

transporting and storing urea or ammonia.

Factor 4: Remaining useful life

CPCC concluded that remaining useful life of the kilns is unknown and unknowable at this time.

EPA is not aware of any near-term limitations on the useful life of the current cement kiln 

system, so it can be assumed that it will remain in service for a 20-year amortization period. 

Factor 5 (Optional): Evaluate Visibility Results 

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full CalPortland modeling results, including for 

the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, and 8a, can 

be found in the tables and bar graphs in TSD Appendix B and in the spreadsheet

CalPortland_visibility_results.xlsx.

Corrections and additions to UNC modeling

In addition to the receptor problems discussed above for the two Chiracahua areas, UNC misspecified receptors for the Galiuro and Gila Wilderness Areas. For these four areas, each area 

was modeled with its own receptor and also with the receptors of the preceding ones. EPA reran 

CALPOST to correct these errors. EPA also updated the Saguaro NP modeling with the 2008 
Page 98 of 133

NPS receptors, so that both parts of the park were included, though this was done only for 

visibility method 8b.

An error in the modeling that was not corrected was the overestimate of PM emissions for kilns 

1-3. The mistake occurred in the EPA spreadsheet “Cement Plant Emission Calculations 2014-

01-24.xlsx” provided to UNC for use in modeling. Emissions are equal to the permitted PM10 

emission factor multiplied by a flow rate that represented the output of all three kilns together, 

but then these emissions were treated as if each kiln emitted that much. Since the overly large 

PM only causes about 5% of the visibility extinction due to CalPortland, correcting this mistake 

would make little difference, especially since PM is held constant in the base case and control 

model runs used to assess the effect of NOx controls.

Sensitivity analyses

Because CalPortland is only 8 km from the western part of Saguaro NP, it is possible that NOx 

emissions do not fully convert to NO2 by the time they reach there, as is assumed by CALPUFF. 

To explore this, EPA used daily extinction values from CALPOST, and reduced the NO2 and 

NO3 extinction by fractions ranging from 10% to 75%, and then recomputed delta deciview 

impacts from the facility, using visibility method 8b only. This assumes that extinction scales 

linearly with concentration, which is not strictly true for method 8, the new IMPROVE equation. 

However, EPA found that the two approaches yielded virtually the same results when applied to 

Phoenix Cement, and so for CalPortland applied only the simpler, linear approach. This was 

done for the base case and for SNCR on kiln 4, EPA’s proposed BART. EPA found that the 

benefit of SNCR was very small for the lower conversion assumptions. Therefore EPA relied on 

results only for the western portion of Saguaro NP. The full results of this analysis are in the 

spreadsheet CalPortlandCement_vis_NO2conv.xlsx.

Table IV.B-12: Visibility Modeling of NOX Control Options, Visibility Impacts

Class I Area

Control Scenario

base case

(c0)

LNB on 

kilns 1,2,3

(c21)

SNCR on 

kilns 1,2,3

(c22)

SNCR on 

kiln 4

(c24)

Chiricahua NM 0.25 0.22 0.20 0.19

Chiricahua Wild. 0.23 0.20 0.18 0.18

Galiuro Wild. 1.02 0.91 0.84 0.83

Gila Wild. 0.12 0.10 0.10 0.09

Mazatzal Wild. 0.13 0.11 0.11 0.10

Mount Baldy Wild. 0.11 0.09 0.08 0.08

Petrified Forest NP 0.11 0.09 0.08 0.08

Pine Mountain Wild. 0.11 0.10 0.09 0.09

Saguaro NP 1.26 1.12 1.04 1.02

Sierra Ancha Wild. 0.13 0.12 0.11 0.10

Superstition Wild. 0.30 0.27 0.24 0.24

Sycamore Canyon Wild. 0.09 0.08 0.08 0.07

Maximum 1.26 1.12 1.04 1.02
Page 99 of 133

Cumulative (sum) 3.85 3.41 3.15 3.07

Number of areas >= 0.5 

dv 2 2 2 2

Table IV.B-13: Visibility Modeling of NOX Control Options, Visibility Benefits

Class I Area

Control Scenario

base case

(c0)

LNB on 

kilns 1,2,3

(c21)

SNCR on 

kilns 1,2,3

(c22)

SNCR on 

kiln 4

(c24)

Chiricahua NM 0.03 0.05 0.06

Chiricahua Wild. 0.03 0.05 0.05

Galiuro Wild. 0.11 0.18 0.19

Gila Wild. 0.02 0.02 0.03

Mazatzal Wild. 0.01 0.02 0.03

Mount Baldy Wild. 0.02 0.03 0.03

Petrified Forest NP 0.01 0.02 0.03

Pine Mountain Wild. 0.01 0.02 0.02

Saguaro NP 0.15 0.22 0.24

Sierra Ancha Wild. 0.01 0.02 0.03

Superstition Wild. 0.04 0.06 0.06

Sycamore Canyon Wild. 0.01 0.02 0.02

Maximum 0.15 0.22 0.24

Cumulative (sum) 0.44 0.70 0.78

Number of areas >= 0.3 

dv 0 0 0

Step 5 – Select Reasonable Progress Controls

Given the lack of emissions from Kilns 1-3 over the last five years and the relatively high cost 

effectiveness of any controls, EPA proposes to find that requiring controls for these units would 

not be reasonable at this time. However, EPA finds that SNCR is cost effective for Kiln 4 at 

$1,047/ton (based on an economic life of at least 20 years) and feasible to install by 2018. We 

also find that it would not result in undue non-air environmental impacts and would result in 

modest visibility benefits. Therefore, we propose to determine that it is reasonable to require 

SNCR at Kiln 4.

When establishing a rolling 30-day emission limit that is based upon an annual average design 

value, we consider it appropriate to provide an upward revision to the annual average value in 

order to accommodate periods of startup and shutdown. In order to determine what magnitude of 

upward revision is appropriate, we examined the highest annual average emission factors (lb/ton) 

and the highest rolling 30-day emission factors (lb/ton) over 2008-11 for other preheater/ 

precalciner kilns. Based on our review, we consider a 30% upward revision appropriate. As a 

result, we propose an emission limit of 2.67 lb/ton based on a 30-day rolling average, which is 
Page 100 of 133

based on a 30% upward revision from an annual average design value of 2.05 lb/ton. We propose 

to require compliance with this limit by the end of the first planning period (i.e. December 31, 

2018). 

Finally, we are also seeking comment on the possibility of requiring a rolling 12-month cap on 

NOX emissions in lieu of a lb/ton emission limit. Such a cap would provide additional flexibility 

by allowing CPCC to comply either by installing controls or by maintaining production at 

current levels. In order to avoid a shift in production from Kiln 4 to Kilns 1-3, we are proposing 

that the cap would apply to all four kilns. Specifically, we are proposing a rolling 12-month cap 

for Kilns 1-4 of 2,082 tpy, and are proposing to require compliance with this cap by December 

31, 2018.

IV.C. Phoenix Cement

IV.C.1. Summary

This analysis documents the basis for determination of Reasonable Progress (RP) control options 

for control of nitrogen oxide (NOX) emissions at the Phoenix Cement Plant, located in Clarkdale, 

Yavapai County, Arizona. Pursuant to 40 CFR 51.308(d)(1), such an analysis must address four 

factors: the costs of compliance, the time necessary for compliance, the energy and non-air 

quality environmental impacts of compliance, and the remaining useful life of any potentially 

affected sources. In addition, EPA Guidance notes that “other relevant factors” may be 

considered as part of an RP analysis.130 In this case, we have determined that the “degree of 

improvement in visibility” is another relevant factor because the purpose of the four-factor 

analysis is to determine what degree of progress toward natural visibility conditions is 

reasonable.

Our analysis consists of the following steps:

Step 1 – Identify All Available Technologies

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Step 4 – Evaluate Impacts and Document Results:

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5 (Optional): Degree of improvement in visibility

Step 5 – Select Reasonable Progress Controls

Our analysis is based primarily on the following documents:

 

130 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program at 2-3 and 2-4 (June 1, 

2007) ("RP Guidance").
Page 101 of 133

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor RP 

Analyses for TEP Springerville, APS Cholla, TEP Sundt, CalPortland Cement and 

Phoenix Cement Plants; Prepared for EPA Region 9 by University of North Carolina at 

Chapel Hill, ICF International, and Andover Technology Partners (October 3, 2012) 

(“Contractor’s Report”)

 Comments from Phoenix Cement Company on EPA’s proposed partial approval/partial 

disapproval of the Arizona Regional Haze SIP (March 6, 2013), including:

o Attachment 3 - Trinity Consultants’ Report

o Attachment 4 - Summary of SNCR Costs for PCC

 Cost calculation spreadsheet developed by EPA, “Phoenix Cement Cost Estimates (final 

for NPRM docket).xlsx”

 Emission Calculation spreadsheets developed by EPA, "CalPortland Cement K4 Cost 

Estimates (final for NPRM docket).xlsx"

IV.C.2. Facility Description

Overview

Phoenix Cement Company (PCC), a division of SRMPIC, operates a Portland cement plant and a 

limestone quarry. The plant produces Portland cement, a fine gray powder that binds sand and 

aggregate into concrete. The facility is located in Clarkdale, Arizona. PCC operates one cement 

kiln, Kiln 4. Figure IV.C-1 shows an aerial photo of the facility.

Figure IV.C-1: Aerial View of Phoenix Cement Plant, Clarkdale, AZ

Baseline Emissions

Emissions that result from the manufacturing of Portland cement at PCC are particulates, NOX, 

sulfur dioxide (SO2), and volatile organic compounds (VOC).
Page 102 of 133

Particulate emissions are generated throughout the facility from numerous stationary and mobile 

operations. Particulate emissions also result from fugitive particulate emissions generated by 

activities such as material handling, rock crushing, paved and unpaved road traffic, and quarry 

drilling and blasting.

NOX and SO2 emissions are generated from fossil fuel combustion in the kiln, quarry blasting, 

and natural gas combustion in the dryers. VOC emissions are generated in the kiln and 

pyroprocessing system, and from natural gas combustion in the material dryers. 

Table IV.C-1 shows the facility-wide actual emissions for the period 2005 to 2010. Table IV.C-2 

shows the Kiln 4 actual emissions for the same years. This information is based emissions data 

that PCC reported to the Arizona Department of Environmental Quality (ADEQ). PCC has 

continuous emissions monitoring systems (CEMS) for measuring NOX and SO2 concentrations 

and emissions. PCC uses actual source test data and AP-42 emissions factors for determining 

PM, PM10, and VOC emissions.

Table IV.C-1: Facility-wide Actual Emissions

Year NOx

(tpy)

SO2

(tpy)

2010 611 4.6

2009 779 3.4

2008 1371 10.4

2007 1390 7.4

2006 1469 6.6

2005 1524 6.6

Table IV.C-2: Kiln 4 Actual Emissions

Year NOx

(tpy)

SO2

(tpy)

2010 607 4.3

2009 771 2.7

2008 1,361 9.7

2007 1,377 6.5

2006 1,455 5.8

2005 1,513 6.0

Based on the information in the above tables, virtually all of the NOX and SO2 emissions are 

generated from Kiln 4. A negligible amount of NOX and SO2 are generated from ancillary 

combustion equipment at the facility. Also, the above tables show that the facility-wide SO2

emissions are very small. SO2 emissions are minimal due to the small amount of sulfur contained 

within the plant’s fuels and raw materials and because of the scrubbing effect of the limestone in 

combination with the preheater/precalciner kiln design.

PCC uses baghouses and dust collectors throughout its facility, including on Kiln 4, to control 

particulate emissions. Baghouses and dust collectors are forms of fabric filters used for 
Page 103 of 133

controlling particulate emissions at efficiencies greater than 98 percent.131 The plant also 

operates under a dust control plan for controlling fugitive particulate emissions.

Since the facility is already well-controlled for particulate emissions and SO2 emissions are 

negligible, these pollutants are not being analyzed in this RP analysis. Therefore, this RP 

analysis only focuses on the control of NOX emissions from Kiln 4. Table IV.C-3 shows the 

actual NOX emissions and production rates for Kiln 4 for 2005 to 2010. 

Table IV.C-3: NOX Emissions and Production Rates for Kiln 4

Year NOX Emissions

(tpy)

Kiln Operation

(hrs/yr)

Clinker 

Production (tpy)

NOX Emission 

Factor (lb/ton)

2010 607 2,960 348,304 3.48

2009 771 3,524 426,669 3.61

2008 1,361 5,857 737,789 3.69

2007 1,377 7,010 908,552 3.03

2006 1,455 7,839 1,019,700 2.85

2005 1,513 7,687 1,060,513 2.85

IV.C.3. RP Analysis for NOX

Step 1 - Identify Available Retrofit Control Technologies for NOX

NOX is generated during fuel combustion by oxidation of chemically-bound nitrogen in the fuel 

and by thermal fixation of nitrogen in the combustion air. In the cement manufacturing process, 

NOX is generated in both the burning zone of the kiln and the burning zone of a precalciner.

NOX control approaches applicable to the cement industry may be grouped into three categories: 

 Process control modifications - usually done to reduce heat consumption, to improve clinker quality, 

and to increase the lifetime of the equipment (such as the refractory lining) by stabilizing process 

parameters. The emphasis is on increased energy efficiency and productivity.

 Combustion modifications - focus on staging the combustion to minimize the amount of combustion 

that must occur at the maximum temperatures. The emphasis is on reducing NOX formation.

 Post-combustion or add-on controls - remove NOX that is formed in the combustion process.

Process control modifications can minimize NOX emissions through improved fuel efficiency.

These practices may be considered standard operating procedures. Combustion modifications 

and add-on controls actually reduce NOX formation. The available NOX controls technologies for 

cement kilns are listed in Table IV.C-4.

 

131 See EPA Air Pollution Control Cost Manual - Sixth Edition, Section 6: Particulate Matter Controls, EPA/452/B02-001, January 2002.
Page 104 of 133

Table IV.C-4: NOX Control Options for Cement Kilns

Category Control Options

Combustion Modifications  Low NOX burner system (LNB)

 Low NOX Calciner/Precalciner 

 Mid-kiln Firing (MKF)

 Mixing Air Technology (MAT)

Add-On Controls  Selective Catalytic Reduction (SCR)

 Selective Non-Catalytic Reduction (SNCR)

Kiln 4 is a preheater/precalciner kiln type. It includes staged combustion through the use of a 

LNB with an indirect firing system, and low NOX precalciner to minimize NOX emissions.

Staged combustion allows the initial combustion to be conducted in a fuel-rich, oxygen-poor 

flame zone to minimize the formation of thermal and fuel NOX, while the secondary combustion 

takes place in an oxygen-rich, lower temperature zone for minimized thermal NOX formation.

The low NOX precalciner introduces the calciner fuel into an oxygen-lean environment where 

initial combustion takes place and a significant amount of NOX is destroyed. The fuel is then 

conveyed upwards into the calciner body where it is exposed to tertiary air and continues to 

complete combustion within the calciner loop. Thus, Kiln 4 already incorporates several 

combustion modification control options. Our RP analysis focuses on the use of add-on controls 

for additional NOX reductions.

Step 2 - Eliminate Technically Infeasible Options

Combustion Modifications

Low NOX Burners (LNB)

These burners are designed to reduce flame turbulence, delay fuel/air mixing, and establish fuelrich zones for initial combustion. Some cement kiln burners are equipped with LNBs. Many of 

these systems focus on lowering the NOX formation in the calciner by air or fuel staging, by 

reburning, or by high temperature combustion. Kiln 4 includes use of a LNB with an indirect 

firing system.

Low NOx Calciner/Precalciner (LNC)

Most of the major cement kiln suppliers now offer “low NOX” calciner designs for new kilns.

These designs typically inject a portion of the fuel into the feed end of the kiln, countercurrent to 

the exhaust gas flow. This reducing atmosphere inhibits the formation of fuel NOX and destroys 

a portion of the NOX formed in the kiln burning zone. Kiln 4 includes use of a low NOX

precalciner which minimizes NOX emissions.

Mid-Kiln Firing

This control method consists of the injection of a solid fuel into the calcining zone of a rotating 

long kiln using a specially designed feed injection mechanism. This is a form of staged 

combustion of fuels. To maintain continuity in the heat input, solid and slow burning fuels (such 

as tires) are most amenable for MKF. By adding fuel in the main flame at mid-kiln, MKF 
Page 105 of 133

changes both the flame temperature and flame length. These changes may reduce thermal NOX

formation by burning part of the fuel at a lower temperature and by creating reducing conditions 

at the solid waste injection point which may destroy some of the NOX formed upstream in the 

kiln burning zone. MKF may also produce additional fuel NOX depending upon the nitrogen 

content of the fuel. This specific technology cannot be applied to Kiln 4, because Kiln 4, like all 

preheater/precalciner kilns, uses a form of mid-kiln firing by adding supplemental fuel to the 

calciner. Therefore, this control method is not technically feasible for Kiln 4.

Mixing Air Technology (MAT)

Mixing air is the practice of injecting a high pressure air stream into a kiln to break up and mix 

stratified layers of gases within the kiln. Mixing the air improves the combustion efficiency.

MAT or LNC provides similar levels of NOX reductions. Kiln 4 includes use of a LNB with an 

indirect firing system, as well as a low NOX precalciner which minimizes NOX emissions.

Therefore, use of MAT is not likely to result in significant additional NOX reductions.

Add-On Controls

Selective Catalytic Reduction (SCR)

This process uses ammonia in the presence of a catalyst to selectively reduce NOX emissions 

from exhaust gases. In SCR, ammonia, usually diluted with air or steam, is injected through a 

grid system into hot flue gases which are then passed through a catalyst bed to carry out NOX

reduction reactions. Catalysts that have been used include titanium dioxide, vanadium pentoxide, 

and zeolite-based materials. The catalyst is not consumed in the process but allows the reactions 

to occur at a lower temperature. The optimum temperature for the catalyst reactions depends on 

the specific catalyst used. According to EPA guidance, base metal catalysts are useful between 

450°F and 800°F, and zeolite catalysts containing precious metals such as platinum and 

palladium are useful at 675°F to over 1100°F for high temperature operations.132

The appropriate temperature window must be maintained to assure that ammonia slip does not 

result in a visible plume. In the cement industry, basically two SCR systems are being 

considered: low dust exhaust gas and high dust exhaust gas treatment. Low dust exhaust gas 

systems require adding the SCR system after the particulate matter control device. High dust 

systems require adding the SCR system after the last cyclone without ducting. SCR is subject to 

catalyst poisoning in high dust, corrosive environments such as cement kiln exhausts. SCR 

would have to be placed after the particulate control systems. If placed after the particulate 

control systems, the exhaust gases may need to be reheated for optimum SCR performance 

unless a low temperature catalyst is used. 

While SCR has not been commercially applied to a cement plant of any type in the United States, 

SCR was tested at one cement kiln in the United States (US) in 1976, and has been installed on 

kilns at three cement plants in Europe.133 The first plant that installed SCR is Solnhofer 

Zementwerkes in Solnhofen, Germany. The facility had a pilot-scale demonstration that was 

conducted in 1997–1999, and commercial installation of a high dust SCR unit in 2000. NOX

 

132 "Alternative Control Techniques Document Update - NOx Emissions from New Cement Kilns”, EPA-453/R-07-

006, November 2007.

133 Ibid.
Page 106 of 133

removal efficiency was typically in the range of 59–67 percent, and NOX removals of more than 

80 percent have been observed. This facility achieved NOX reductions by using a combination of 

a low NOX burner, alternative/waste fuels and either SNCR or SCR, in which the SNCR and 

SCR systems did not operate simultaneously. The facility ceased operation of its SCR system in 

January 2006, and has operated an SNCR system for NOX control since that time. The second 

plant, called Cementeria di Monselice in Bergamo, Italy, began operation of a full-scale SCR 

system in June 2006 at Cementeria di Monselice in Bergamo, Italy. The third, plant, called 

Italcementi Sarche di Calavino, also in Italy, installed an SCR unit in early 2007. However, little 

is known about the operation of SCR on the cement plants in Italy.

As a result, there is very little information about the effectiveness and cost of controls associated 

with SCR at cement plants. Given this uncertainty, we have decided not to further evaluate SCR 

for purposes of RP at this time. However, SCR for cement kilns should be re-evaluated in 

subsequent planning periods.

Selective Non-Catalytic Reduction (SNCR)

This control technique relies on the reduction of NOX in exhaust gases by ammonia or urea, 

without using any catalyst. This approach avoids the problems related to catalyst fouling and 

poisoning, as in SCR, but requires injection of the reagents in the kiln at a temperature between 

1600°F to 2000°F. Because no catalyst is used to increase the reaction rate, the temperature 

window is critical for conducting this reaction. In preheater/precalciner type cement kilns, the 

temperatures at the cooler end of the rotating kiln, in the riser duct, and in the lower section of 

the cyclone preheater tower are likely to be in the temperature window appropriate for SNCR.

SNCR has been widely used for reducing NOX emissions at cement kilns. This control method is 

technically feasible.

Table IV.C-5 summarizes the available technologies and their potential application for Kiln 4.

Table IV.C-5: NOX Control Technologies and Potential Application

NOX Control Option Kiln 4

LNB In Use

Low NOx Calciner/Precalciner In Use

MKF Infeasible

MAT In Use (i.e., comparable controls)

SCR Infeasible

SNCR Technically Feasible

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Selective Non-Catalytic Reduction (SNCR)

We note that the effectiveness of SNCR in preheater/precalciner cement kilns can vary 

depending upon factors such as temperature, residence time, ammonia injection rates and 

patterns, and inlet NOx concentrations. However, emission data and feasibility studies from the 

following control technology determinations, each involving a preheater/precalciner kiln 

operating with existing combustion controls, indicate the following control efficiencies.
Page 107 of 133

Table IV.C-6: Preheater/precalciner Kiln SNCR Control Efficiency

Company Plant State

SNCR 

Ctrl 

Efficiency

Reference

St. Mary's Cement Charlevoix MI 50% EPA Docket No. EPA-R05-OAR-2010-0954

Holcim Florence Plant CO 45% http://www.colorado.gov/cs/Satellite/CDPHEAP/CBON/1251595092457

Holcim Trident Plant MT 50% EPA Docket No. EPA-R08-OAR-2011-0851-

0037, -0235, and the final rule at -0212

Ash Grove Montana City Plant MT 50% EPA Docket No. EPA-R08-OAR-2011-0851-

0038, -0160

Based on this information we consider the use of a 50% control efficiency for SNCR appropriate 

for Kiln 4. However, we are seeking comment on whether this control efficiency is appropriate. 

If we receive additional information or data providing more site-specific information that 

justifies a different control efficiency at the plant, we will revise our analysis accordingly.

Step 4 – Evaluate Impacts and Document Results

Factor 1 - Cost of compliance 

In evaluating the costs of compliance for SNCR, we calculated the control costs ($) and emission 

reductions (tons/year of pollutant), and developed average cost effectiveness ($/ton) value. 

Baseline emissions and control scenario emissions are summarized in Table IV.C-7 below. A 

more detailed version of emission calculations can be found in our docket.134 Annual baseline 

emissions summarized below were calculated using the average of the lb/ton NOx emission 

factors (as summarized in Table IV.C-3) observed over a 2005-10 timeframe. These lb/ton 

values are lower over 2005-07, which represent high capacity years, and higher over 2008-10, 

which are lower capacity years. As noted in PCC’s March 6, 2013 comment letter, this variation 

in emission factors is a result of the fact that the kiln operates more efficiently (i.e., low lb/ton 

values) during periods of high capacity utilization. In situations in which RP controls are 

determined to be necessary, the lb/ton baseline emission factor can often serve as the basis for an 

enforceable emission limit. As a result, use of an emission factor based solely on 2005-07 values 

would potentially result in a lb/ton emission limit that would be unachievable during periods of 

sustained low capacity, such as 2008-10. By contrast, use of an emission factor based solely on 

2008-10 values would result in a lb/ton value that greatly overestimates NOx emissions during 

periods of high capacity. This would have the effect of potentially exaggerating baseline 

emissions, and overstating the potential for NOx reductions. As a result, the average lb/ton value 

of the entire 2005-10 period was used as a compromise solution to reconcile these two issues.

Although the baseline emission estimate of 1,620 tpy is greater than actual emissions observed

during the 2005-10 period, we consider the calculation methodology to be reasonable, as it 

provides an estimate of anticipated annual emissions that accounts for capacity variations 

observed over the 2005-10 period.

 

134 “Cement Plant Emission Calculations (final for NPRM docket).xlsx”
Page 108 of 133

Table IV.C-7: Expected NOX Control Effectiveness for Kiln 4

NOx Control Option Ctrl Efficiency

(%)

Emissions Reductions

(tons/year)

Remaining 

Emissions

(tons/year)

Baseline -- -- 1,620

SNCR 50 810 810

Table IV.C-8 provides NOX control technologies and cost estimates for Kiln 4. In general, we 

have relied primarily upon the cost information submitted by PCC in its March 6, 2013 comment 

letter. However, we have revised the values of certain line items downward from the estimate 

provided by PCC in instances where we considered PCC’s estimates to be unsupported or not 

allowed by EPA's Control Cost Manual. Detailed cost calculation spreadsheets are contained in 

our docket.135

Table IV.C-8: Cost Estimates for NOX Control Options

Control 

Option

Ctrl 

Efficiency

(%)

NOX

Reduction

(tpy)

NOX Emissions Annual 

Cost

($/yr)

Cost 

Effectiveness

($/ton) (lb/ton) (tpy)

Baseline

(No Control) -- -- 3.25 1,620 -- --

SNCR 50 810 1.63 810 $940,903 $1,162

Factor 2 - Time necessary for compliance 

PCC has not identified the time needed to design, fabricate, and install SNCR. We expect that 

SNCR could be installed within this planning period, i.e. by December 31, 2018.

Factor 3 - Energy and non-air quality environmental impacts of compliance

The installation and operation of SNCR at the plant would require a small increase in energy 

usage. The cost of this additional energy usage is included in the cost analysis. Non-air quality 

environmental impacts associated with SNCR include the hazards of transporting and storing 

urea or ammonia, especially if anhydrous ammonia is used. However, since the handling of 

anhydrous ammonia will involve the development of a risk management plan (RMP), we 

consider the associated safety issues to be manageable as long as established safety procedures 

are followed. Therefore, we find that these impacts are not sufficient to warrant eliminating 

SNCR as a control option.

Factor 4: Remaining useful life of the source

PCC believes Kiln 4 has a remaining useful life of roughly 50 years. PCC stated that this belief is 

based on design information provided by the manufacturer of Kiln 4, the fact that Kiln 4 has been 

in operation for only 10 years, and lifetime projections of the Clarkdale facility’s quarry and raw 

 

135 “Phoenix Cement Cost Estimates (final for NPRM docket).xlsx”
Page 109 of 133

materials. For purposes of this analysis, EPA is assuming that the remaining useful life of Kiln 4 

will be at least as long as the 20-year amortization period for the SNCR.

Factor 5 (Optional): Degree of improvement in visibility

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full Phoenix Cement modeling results, 

including for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, 

and 8a, can be found in the tables and bar graphs in TSD Appendix B and in the spreadsheet

PhoenixCement_visibility_results.xlsx.

Sensitivity analyses

Because Phoenix Cement is only 11 km from the Sycamore Canyon Wilderness Area, it is 

possible that NOx emissions do not fully convert to NO2 by the time they reach there, as is 

assumed by CALPUFF. To explore this, EPA used daily extinction values from CALPOST, and 

which EPA scaled by fractions ranging from 10% to 75%. For NO2 and NO3, EPA inverted the 

quadratic equation for daily extinction bext as a function of concentration in the new IMPROVE 

equation to find the concentration. EPA then scaled the concentrations, assuming that NO2 and 

NO3 concentrations reduce in proportion to the the NO2, Finally, EPA recomputed extinction 

and delta deciview impacts from the facility, using visibility method 8b only. This was done for 

the base case and for SNCR on kiln 4, EPA’s proposed BART. EPA found that the benefit of 

SNCR remained substantial even for the lowest conversion assumption. This tends to support 

EPA’s proposed control. The full results of this analysis are in the spreadsheet 

PhoenixCement_vis_NO2conv.xlsx.

Table IV.C-9: Visibility Modeling of NOX Control Options, Visibility Impacts

Class I Area

Control Scenario

Base case SNCR (ctrl2)

Bryce Canyon NP 0.09 0.04

Galiuro Wild. 0.03 0.01

Grand Canyon NP 0.51 0.27

Mazatzal Wild. 0.51 0.27

Mount Baldy Wild. 0.05 0.02

Petrified Forest NP 0.21 0.10

Pine Mountain Wild. 0.66 0.35

Saguaro NP 0.03 0.01

Sierra Ancha Wild. 0.09 0.04

Superstition Wild. 0.10 0.05

Sycamore Canyon Wild. 5.15 3.30

Zion NP 0.09 0.04

Maximum 5.15 3.30

Cumulative (sum) 7.49 4.51
Page 110 of 133

Number of areas >= 0.5 dv 4 1

Table IV.C-10: Visibility Modeling of NOX Control Options, Visibility Benefits

Class I Area

Control Scenario

Base case SNCR (ctrl2)

Bryce Canyon NP 0.04

Galiuro Wild. 0.01

Grand Canyon NP 0.25

Mazatzal Wild. 0.24

Mount Baldy Wild. 0.02

Petrified Forest NP 0.10

Pine Mountain Wild. 0.32

Saguaro NP 0.01

Sierra Ancha Wild. 0.04

Superstition Wild. 0.05

Sycamore Canyon Wild. 1.85

Zion NP 0.05

Maximum 1.85

Cumulative (sum) 2.98

Number of areas >= 0.3 dv 2

Step 5 – Select Reasonable Progress Controls

Based on our analysis and information provided by PCC, EPA finds that SNCR is cost effective 

(based on an economic life of at least 20 years) and feasible to install by 2018. We also find that 

it would not result in undue non-air environmental impacts and would result in significant 

visibility benefits at Sycamore Canyon Wilderness Area. Therefore, we propose to determine 

that it is reasonable to require SNCR at Kiln 4 at the Phoenix Cement facility.

When establishing a rolling 30-day emission limit that is based upon an annual average design 

value, we consider it appropriate to provide an upward revision to the annual average value in 

order to accommodate periods of startup and shutdown. In order to determine what magnitude of 

upward revision is appropriate, we examined the highest annual average emission factors (lb/ton) 

and the highest rolling 30-day emission factors (lb/ton) over 2008-11 for other preheater/ 

precalciner kilns. Based on our review, we consider a 30% upward revision appropriate. As a 

result, we propose an emission limit of 2.12 lb/ton based on a 30-day rolling average, which is 

based on a 30% upward revision from an annual average design value of 1.63 lb/ton. We propose 

to require compliance with this limit by the end of the first planning period (i.e. December 31, 

2018).
Page 111 of 133

Finally, we are seeking comment on the possibility of requiring a rolling 12-month cap on NOX

emissions from Kiln 4 in lieu of a lb/ton emission limit. Such a cap would provide additional 

flexibility to PCC and SRPMIC by allowing them to comply either by installing controls or by 

limiting production. As explained above, we used a baseline emission rate of 1,620 tpy for NOX. 

However, as illustrated in Table IV.C-3 above, NOX emissions from the facility have been well 

below this level over the last several years, due to a significant decrease in clinker production. 

Given the uncertainty of economic forecasts, it is difficult to predict the extent to which clinker 

production and NOX emissions from Kiln 4 may vary over the next several years in the absence 

of any control requirements. 

Specifically, we are seeking comment on a rolling 12-month cap of 810 tpy, which corresponds 

to the installation of SNCR. If production remains at current levels, PCC could potentially meet 

this cap without installing any additional controls. However, if production increases, we expect 

that PCC would need to install SNCR on Kiln 4 to meet the cap. We are proposing to require 

compliance with this cap by December 31, 2018.

IV.D. APS Cholla, Unit 1

IV.D.1. Summary

This analysis documents the basis for determination of Reasonable Progress (RP) control options 

for control of nitrogen oxide (NOX) emissions from Cholla Power Plant, Unit 1. The Cholla 

Power Plant is located near Joseph City, AZ and operated by Arizona Public Service (APS). The 

Cholla Power Plant consists primarily of four coal-fired boilers, and has a facility-wide gross 

generating capacity of approximately 1,036 MW. Units 2-4 were identified as BART sources, 

and we have finalized control requirements in a separate rulemaking. We consider those control 

requirements sufficient for the purposes of achieving reasonable progress. Unit 1, a 110 MW 

unit, is not subject to BART, and is the focus of this analysis. We performed this analysis based

on the following steps:

Step 1 – Identify All Available Technologies

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Step 4 – Evaluate Impacts and Document Results:

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5 (Optional): Evaluate Visibility Results

Step 5 – Select Reasonable Progress Controls

We relied primarily upon the information contained in the following documents:

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor 

RP Analyses for TEP Springerville, APS Cholla, TEP Sundt, CalPortland Cement and 
Page 112 of 133

Phoenix Cement Plants; Prepared for EPA Region 9 by University of North Carolina 

at Chapel Hill, ICF International, and Andover Technology Partners (October 3, 

2012) (“Contractor’s Report”)

 EGU Costs_Ch5.xlsx (Contractor's cost calculations)

 EGU Costs_Ch5 (EPA revisions).xlsx (Contractor's cost calculations, but with certain 

formatting revisions made by EPA staff)

IV.D.2. Facility Description

At present, Cholla 1 operates with the following pollution control equipment summarized in 

Table IV.D-1 below.

Table IV.D-1: Current emission control technology

Pollutant Control Device

NOX Low NOX burners (LNB) with Overfire 

Air (OFA)

PM Fabric filter/baghouse

SO2 Wet Lime Flue Gas Desulfurization 

(FGD)

A summary of historical data for a period of time extending from 2008-11, based on information 

reported to EPA's Clean Air Markets Division (CAMD), is included in Table IV.D-2 below.

Table IV.D-2: Cholla Unit 1, Historical Emissions (2008-11)

Year Heat Duty NOX SO2

(MMBtu/yr) (tpy) (lb/MMBtu) (tpy) (lb/MMBtu)

2011 10,372,954 1,135 0.220 1,047 0.202

2010 11,280,558 1,110 0.200 831 0.147

2009 9,336,204 893 0.195 494 0.106

2008 10,521,214 870 0.169 526 0.100

As noted in a previous rulemaking that addressed the BART requirements for Cholla Units 2-4, 

APS historically burned coal from the McKinley mine located on the Navajo Reservation at the 

Cholla plant. Following the closure of this mine, APS obtained coal from various sources until 

the company signed a long-term contract for coal from the El Segundo and Lee Ranch mines in 

New Mexico. This sulfur content of coal from these two mines is substantially higher than PRB 

coal and also much higher than coal from the former source, the McKinley mine. The current 

coal contract for these units indicates that the typical sulfur content of this coal is equivalent to 

2.4 lb/MMBtu SO2 and can be as high as 3.0 lb/MMBtu. Given that the transition to this coal has 

already occurred and that company has entered into a contract to continue purchasing this coal 

until 2024, we consider emissions based on this coal supply to “represent a realistic depiction of 

anticipated annual emissions for the source.”

As a result, we have used 2011 as the baseline period for calculating baseline emissions.

Although this represents only a single year of emission data, we consider this to be a more 
Page 113 of 133

reasonable depiction of anticipated future operations because it reflects the use of the existing 

wet lime FGD, and is the first full year of coal use following the new coal contract.

IV.D.3. RP Analysis for NOX

Step 1 – Identify all available technologies

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOX to nitrogen and water. A NOX reducing 

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through 

injection nozzles at the cyclone inlets. Because catalyst is not used to drive the reaction, 

temperatures of 1600-2100 degrees F are required. Flue gas temperature at the point of reagent 

injection can greatly affect NOX removal efficiencies and the quantity of ammonia or urea that 

will pass through the SNCR unreacted (referred to as ammonia slip). At temperatures below the 

desired operating range, the NOX reduction reactions diminish and unreacted ammonia emissions 

increase. Above the desired temperature range, ammonia is oxidized to NOX resulting in low 

NOX reduction efficiencies.

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses either ammonia or urea in the 

presence of a metal-based catalyst to selectively reduce NO and NO2 to molecular nitrogen, 

water, and oxygen. The catalyst lowers the temperature required for the chemical reaction 

between NOX and the reducing agent. Technical factors that impact the effectiveness of this 

technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur 

content of the fuel, design of the ammonia injection system, and the potential for catalyst 

poisoning.

Step 2 – Eliminate technically infeasible options

Both SNCR and SCR have been demonstrated as technically feasible on coal-fired boilers. At 

this time, we have not identified any design considerations of the Cholla 1 unit that would 

warrant eliminating either option as technically infeasible.

Step 3 – Evaluate control effectiveness of remaining control technologies

Selective Non-Catalytic Reduction (SNCR)

Typical NOX control efficiencies range from 40% to 60%, depending on inlet NOX 

concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous 

reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of 

interfering chemical substances in the gas stream. Guaranteed NOX reduction rates are in the 

50% range to limit ammonia slip to 10 ppm. Because Cholla Unit 1 already operates with NOX

combustion controls, we have used an SNCR control efficiency of 30% from a LNB with OFA 

baseline. Considering that typical combustion control technologies can achieve control 

efficiencies of approximately 25-30%, this results in a total control efficiency from an 

uncontrolled baseline of approximately 50%, which is in the mid-range of SNCR control 

efficiencies. 
Page 114 of 133

Selective Catalytic Reduction (SCR)

Existing vendor literature and technical studies indicate that SCR systems are capable of 

achieving approximately 80-90% control efficiency, and that this emission rate can be achieved 

on a retrofit basis, particularly when combined with combustion control technology such as 

LNB.136 Our contractor used a design emission rate of 0.050 lb/MMBtu (annual average). In the 

case of Cholla 1, this corresponds to a control efficiency of 86%, which is in the mid-range of 

SCR control efficiency. 

Step 4 – Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Our evaluation of this factor is based primarily on the cost effectiveness of each control option, 

as measured in dollars per ton of pollutant removed ($/ton). Annual emission estimates used in 

evaluating costs of compliance are summarized below. These emission estimates are based upon 

the control effectiveness described in Step 3 above, and on an annual capacity factor of 86%, as 

reported to EPA's CAMD.

Table IV.D-3: NOX Emission Estimates

Control Option NOX Emissions

Emission 

Reduction

(lb/MMBtu) (lb/hr) (tpy) (tpy)

Baseline 

(LNB+OFA) 0.22 274 1,032 --

SNCR 0.15 192 723 310

SCR 0.05 62 235 798

An estimate of control costs is summarized in the tables below, and is based primarily upon the 

cost estimation module for SNCR and SCR systems developed as part of the Integrated Planning 

Model. Detailed cost and emission calculations can be found in our contractor's report and its 

associated cost calculation spreadsheet. 

Table IV.D-4: NOX Control Cost Estimates

Control Option

Total 

Capital Cost

Annualized 

Capital Cost

Annual 

O&M 

Costs

Total 

Annual 

Cost

Cost 

effectiveness 

($/ton)

($) ($) ($) ($) Ave Incr

Baseline 

(LNB+OFA) -- -- -- -- -- --

SNCR $2,272,000 $241,725 $918,875 $1,160,599 $3,748 --

SCR $26,437,190 $2,812,730 $1,425,137 $4,237,867 $5,313 $6,307 

 

136 See “Emissions Control: Cost-Effective Layered Technology for Ultra-Low NOx Control” (2007), “What’s New 

in SCRs” (2006), and “Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers” (2005).
Page 115 of 133

Factor 2: Time necessary for compliance

In the case of SNCR we estimate that implementation could be completed within 2-3 years of the 

final rule. For SCR, we estimate that implementation could be completed within 4-5 years of the 

final rule. In both cases, we estimate that installation of either control option can be completed 

prior to the end of the first planning period (December 31, 2018). 

Factor 3: Energy and non-air quality environmental impacts of compliance

With respect to the potential energy impacts of the control options, we note that SCR incurs a 

draft loss that will increase parasitic loads, and that other emissions controls may also have 

modest energy impacts. The costs for direct energy impacts, i.e., power consumption from the 

control equipment and additional draft system fans from each control technology, are included in 

the cost analyses and are not considered further in this section. Indirect energy impacts, such as 

the energy to produce raw materials, are not considered, consistent with the BART guidelines.

Ammonia adsorption (resulting from ammonia injection from SCR or SNCR) to fly ash is 

generally not desirable due to odor but does not impact the integrity of the use of fly ash in 

concrete. However, other NOX control technologies, including LNB, also 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. Commercial scale 

technologies exist to remove ammonia and LOI from fly ash. Moreover, the impact of SCR on 

fly ash is smaller than the impact of LNB on fly ash, and in both cases, the adverse effects can be 

mitigated.137 We conclude that the ability of the relevant facilities to sell fly ash is unlikely to be 

affected by the installation of SCR and SNCR technologies.

SCR and SNCR may involve potential safety hazards associated with the transportation and 

handling of anhydrous ammonia. However, since the handling of anhydrous ammonia will 

involve the development of a risk management plan (RMP), we consider the associated safety 

issues to be manageable as long as established safety procedures are followed. As a result, we do 

not consider these impacts sufficient enough to warrant eliminating either of the available control 

technologies.

Factor 4: Remaining useful life of the source

We are not aware of near-term limitations on the useful life of this boiler, and have assumed that 

it will remain in service for at least as long as the 20-year amortization period of the control 

equipment.

Factor 5 (Optional): Evaluate Visibility Results

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full Cholla unit 1 modeling results, including 

 

137 See “Impact of Ammonia in Fly Ash on its Beneficial Use,” Memorandum from Nancy Jones and Stephen 

Edgerton, EC/R Incorporated, to Anita Lee, U.S. EPA/Region 9, August 31, 2010. 
Page 116 of 133

for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, and 8a, 

can be found in the UNC spreadsheet cho_az_unit1_dollarperdv_analysis_final.xls

Table IV.D-5: Cholla unit 1 Visibility Impact and Improvement from NOx Controls

Impact

Improvement from 

Control

Class I Area

Distance, 

km

Base case 

(BART 

SCR on 

units 1,2,3)

(ctrl0 /

ctrl2_r2)

SNCR

(ctrl1/c21)

SCR

(ctrl2/c22)

Capitol Reef NP 300 0.71 0.04 0.09

Galiuro Wild. 249 0.30 0.01 0.01

Gila Wild. 222 0.48 0.01 0.01

Grand Canyon NP 179 1.14 0.05 0.12

Mazatzal Wild. 128 0.79 0.02 0.04

Mesa Verde NP 292 0.65 0.03 0.06

Mount Baldy Wild. 128 0.71 0.01 0.02

Petrified Forest NP 39 3.38 0.10 0.20

Pine Mountain Wild. 149 0.55 0.01 0.03

Saguaro NP 300 0.23 0.00 0.00

Sierra Ancha Wild. 126 0.87 0.02 0.06

Superstition Wild. 166 0.81 0.03 0.06

Sycamore Canyon 

Wild. 147 0.76 0.03 0.07

Cumulative (sum) 11.4 0.3 0.7

Maximum 3.38 0.10 0.20

# CIAs >= 0.5 dv 10 0 0

million $/dv (cumul. 

dv) $3.0 $5.7

million $/dv (max. 

dv) $10.3 $21.7

These results assume units 2, 3, and 4 have SCR in place.

Step 5 – Select Reasonable Progress Controls

We have considered the four RP factors, as well as the anticipated visibility benefits. We note 

that the remaining useful life of the source is reflected in the evaluation of cost of compliance 

through the use of a 20-year amortization period in control cost calculations. In examining 

energy and non-air quality impacts, we note certain potential impacts resulting from the use of 

ammonia injection associated with the SNCR and SCR control options, but do not consider these 

impacts sufficient to warrant eliminating any of the available control technologies. 
Page 117 of 133

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option. 

The most stringent option, SCR, also exhibits the highest average cost effectiveness at 

$5,313/ton, and has an incremental cost effectiveness relative to SNCR of $6,638/ton. The other 

control option, SNCR, has an average cost effectiveness of $3,226/ton.

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that while each of the 

available NOX control options achieves some degree of visibility improvement, neither SCR nor 

SNCR is anticipated to achieve a large visibility benefit. As a result we are proposing no 

additional controls for NOX during this planning period in light of the relatively small anticipated 

visibility benefits of the control options. However, this decision should be revisited in future 

planning periods. 

IV.E. TEP Springerville, Units 1-2

IV.E.1. Summary

This analysis documents the basis for determination of Reasonable Progress (RP) control options 

for control of nitrogen oxide (NOX) emissions from Springerville Generating Station, Units 1-2.

Springerville Generating Station is located in Apache County near Springerville, AZ and is 

operated by Tucson Electric Power. Springerville consists primarily of four coal-fired boilers, 

and has a facility-wide gross generating capacity of approximately 1,600 MW. Units 3-4 were 

recently placed in service, in 2006 and 2009 respectively, and operate with modern pollution 

controls, including Selective Catalytic Reduction (SCR). Units 1-2 are older tangentially-fired 

boilers, each with a gross capacity of 425 MW. We performed this analysis based on the 

following steps:

Step 1 – Identify All Available Technologies

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Step 4 – Evaluate Impacts and Document Results:

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5 (Optional): Evaluate Visibility Results

Step 5 – Select Reasonable Progress Controls

We relied primarily upon the information contained in the following documents:

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor 

RP Analyses for TEP Springerville, APS Cholla, TEP Sundt, CalPortland Cement and 

Phoenix Cement Plants; Prepared for EPA Region 9 by University of North Carolina 
Page 118 of 133

at Chapel Hill, ICF International, and Andover Technology Partners (October 3, 

2012) (“Contractor’s Report”)

 EGU Costs_Ch5.xlsx (Contractor's cost calculations)

 EGU Costs_Ch5 (EPA revisions).xlsx (Contractor's cost calculations, but with certain 

formatting revisions made by EPA staff)

IV.E.2. Facility Description

At present, Springerville Units 1-2 operate with the following pollution control equipment 

summarized in Table IV.E-1 below.

Table IV.E-1: Current emission control technology

Pollutant Control Device

Springerville Unit 1

NOX Low NOX burners (LNB) with Overfire Air 

(OFA)

PM Fabric filter/baghouse

SO2 Dry Flue Gas Desulfurization (DGD)

Springerville Unit 2

NOX Low NOX burners (LNB) with Overfire Air 

(OFA)

PM Fabric filter/baghouse

SO2 Dry Flue Gas Desulfurization (DGD)

A summary of historical data for a period of time extending from 2008-11, based on information 

reported to EPA's Clean Air Markets Division (CAMD), is included in Table IV.E-2 below.

Table IV.E-2: Springerville 1-2, Historical Emissions (2008-12)

Year Heat Duty NOX SO2

(MMBtu/yr) (tpy) (lb/MMBtu) (tpy) (lb/MMBtu)

Springerville 1

2011 22,956,977 2,091 0.180 2,908 0.253

2010 25,782,840 2,335 0.180 2,708 0.210

2009 24,686,814 2,273 0.183 3,149 0.255

2008 27,702,820 2,541 0.182 2,601 0.188

Springerville 2

2011 29,459,755 2,774 0.188 2,465 0.167

2010 23,286,891 2,194 0.187 1,776 0.153

2009 26,050,908 2,472 0.187 2,808 0.216

2008 28,502,445 2,835 0.197 2,659 0.187

As described in our Contractor’s Report, we have used the three year period from 2008-10 as the 

baseline period for calculating baseline emissions, as it was the most recent data available at the 
Page 119 of 133

time of the analysis. Although more recent data is presently available, recent generation and 

emission rates at Springerville do not differ significantly from the 2008-10 period. 

IV.E.3. RP Analysis for NOX

Step 1 – Identify all available technologies

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOX to nitrogen and water. A NOX reducing 

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through 

injection nozzles at the cyclone inlets. Because catalyst is not used to drive the reaction, 

temperatures of 1600-2100 degrees F are required. Flue gas temperature at the point of reagent 

injection can greatly affect NOX removal efficiencies and the quantity of ammonia or urea that 

will pass through the SNCR unreacted (referred to as ammonia slip). At temperatures below the 

desired operating range, the NOX reduction reactions diminish and unreacted ammonia emissions 

increase. Above the desired temperature range, ammonia is oxidized to NOX resulting in low 

NOX reduction efficiencies.

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses either ammonia or urea in the 

presence of a metal-based catalyst to selectively reduce NO and NO2 to molecular nitrogen, 

water, and oxygen. The catalyst lowers the temperature required for the chemical reaction 

between NOX and the reducing agent. Technical factors that impact the effectiveness of this 

technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur 

content of the fuel, design of the ammonia injection system, and the potential for catalyst 

poisoning.

Step 2 – Eliminate technically infeasible options

Both SNCR and SCR have been demonstrated as technically feasible on coal-fired boilers. At 

this time, we have not identified any design considerations at Springerville Unit 1 and 2 that 

would warrant eliminating either option as technically infeasible.

Step 3 – Evaluate control effectiveness of remaining control technologies

Selective Non-Catalytic Reduction (SNCR)

Typical NOX control efficiencies range from 40% to 60%, depending on inlet NOX 

concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous 

reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of 

interfering chemical substances in the gas stream. Guaranteed NOX reduction rates are in the 

50% range to limit ammonia slip to 10 ppm. Because Springerville 1 and 2 already operate with 

NOX combustion controls, we have used an SNCR control efficiency of 30% from a LNB with 

OFA baseline. Considering that typical combustion control technologies can achieve control 

efficiencies of approximately 25-30%, this results in a total control efficiency from an 

uncontrolled baseline of approximately 50%, which is in the mid-range of SNCR control 

efficiencies. 
Page 120 of 133

Selective Catalytic Reduction (SCR)

Existing vendor literature and technical studies indicate that SCR systems are capable of 

achieving approximately 80-90% control efficiency, and that this emission rate can be achieved 

on a retrofit basis, particularly when combined with combustion control technology such as 

LNB. Our contractor used a design emission rate of 0.050 lb/MMBtu (annual average). In the 

case of Springerville 1 and 2, this corresponds to control efficiencies of 65% and 70%, 

respectively.

Step 4 – Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Our evaluation of this factor is based primarily on the cost effectiveness of each control option, 

as measured in dollars per ton of pollutant removed ($/ton). Annual emission estimates used in 

evaluting costs of compliance are summarized below. These emission estimates are based upon 

the control effectiveness described in Step 3 above, and on an annual capacity factor of 86%, as 

reported to EPA's CAMD.

Table IV.E-3: NOX Emission Estimates

Control Option NOX Emissions

Emission 

Reduction

(lb/MMBtu) (lb/hr) (tpy) (tpy)

Springerville 1

Baseline 

(LNB+OFA) 0.18 769 2,189 --

SNCR 0.13 538 1532 657

SCR 0.05 212 605 1,584

Springerville 2

Baseline 

(LNB+OFA) 0.19 798 2,448 --

SNCR 0.13 559 1714 734

SCR 0.05 210 644 1,804

An estimate of control costs is summarized in the tables below, and is based primarily upon the 

cost estimation module for SCR and SNCR systems developed as part of the Integrated Planning 

Model. Detailed cost and emission calculations can be found in our contractor's report. 

Table IV.E-4: NOX Control Cost Estimates

Control Option

Total 

Capital 

Cost

Annualized 

Capital Cost

Annual 

O&M Costs

Total 

Annual Cost

Cost effectiveness 

($/ton)

($) ($/yr) ($/yr) ($/yr) Ave Incr

Springerville 1

Baseline 

(LNB+OFA) -- -- -- -- -- --
Page 121 of 133

SNCR $8,496,000 $903,914 $1,590,395 $2,494,309 $3,798 --

SCR $71,796,257 $7,638,614 $3,181,809 $10,820,423 $6,829 $8,975 

Springerville 2

Baseline 

(LNB+OFA) -- -- -- -- -- --

SNCR $8,496,000 $903,914 $1,758,102 $2,662,016 $3,625 --

SCR $71,402,351 $7,596,705 $3,379,514 $10,976,219 $6,085 $7,774 

Factor 2: Time necessary for compliance

In the case of SNCR we estimate that implementation could be completed within 2-3 years of the 

final rule. For SCR, we estimate that implementation could be completed within 4-5 years of the 

final rule.

Factor 3: Energy and non-air quality environmental impacts of compliance

With respect to the potential energy impacts of the control options, we note that SCR incurs a 

draft loss that will increase parasitic loads, and that other emissions controls may also have 

modest energy impacts. The costs for direct energy impacts, i.e., power consumption from the 

control equipment and additional draft system fans from each control technology, are included in 

the cost analyses and are not considered further in this section. Indirect energy impacts, such as 

the energy to produce raw materials, are not considered, consistent with the BART guidelines.

Ammonia adsorption (resulting from ammonia injection from SCR or SNCR) to fly ash is 

generally not desirable due to odor but does not impact the integrity of the use of fly ash in 

concrete. However, other NOX control technologies, including LNB, also 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. Commercial scale 

technologies exist to remove ammonia and LOI from fly ash. Moreover, the impact of SCR on 

fly ash is smaller than the impact of LNB on fly ash, and in both cases, the adverse effects can be 

mitigated.138 We conclude that the ability of the relevant facilities to sell fly ash is unlikely to be 

affected by the installation of SCR and SNCR technologies.

SCR and SNCR may involve potential safety hazards associated with the transportation and 

handling of anhydrous ammonia. However, since the handling of anhydrous ammonia will 

involve the development of a risk management plan (RMP), we consider the associated safety 

issues to be manageable as long as established safety procedures are followed. As a result, we do 

not consider these impacts sufficient enough to warrant eliminating either of the available control 

technologies.

Factor 4: Remaining useful life of the source

 

138 See “Impact of Ammonia in Fly Ash on its Beneficial Use,” Memorandum from Nancy Jones and Stephen 

Edgerton, EC/R Incorporated, to Anita Lee, U.S. EPA/Region 9, August 31, 2010.
Page 122 of 133

We are not aware of near-term limitations on the useful life of either boiler, and have assumed 

that they will remain in service for at least as long as the 20-year amortization period of the 

control equipment.

Factor 5 (Optional): Evaluate Visibility Results

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full Springerville units 1 & 2 modeling results, 

including for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, 

and 8a, can be found in the UNC spreadsheet irv_az_units1-

3_dollarperdv_analysis_final_fixed.xls

Table IV.E-5: Springerville Units 1 & 2 Visibility Impact and Improvement from NOx 

Controls

Impact

Improvement from 

Control

Class I Area

Distance, 

km

Base 

case

(base/c0)

SNCR

(ctrl1/c21)

SCR

(ctrl2/c22)

Bandelier NM 298 1.08 0.07 0.13

Chiricahua NM 253 0.85 0.07 0.14

Chiricahua Wild. 264 0.88 0.00 0.01

Galiuro Wild. 211 0.95 0.03 0.08

Gila Wild. 111 4.39 0.18 0.41

Grand Canyon NP 302 0.79 0.07 0.07

Mazatzal Wild. 209 0.86 0.01 0.01

Mount Baldy Wild. 51 3.63 0.13 0.32

Petrified Forest NP 79 2.46 0.06 0.09

Pine Mountain Wild. 236 0.67 0.02 0.06

Saguaro NP 263 0.57 0.01 0.04

San Pedro Parks 

Wild. 281 1.53 0.05 0.23

Sierra Ancha Wild. 165 1.01 0.02 0.05

Superstition Wild. 194 0.52 0.03 0.06

Sycamore Canyon 

Wild. 263 0.65 0.02 0.04

Cumulative (sum) 20.8 0.8 1.7

Maximum 4.39 0.18 0.41

# CIAs >= 0.5 dv 15 0 0

million $/dv (cumul. 

dv) $6.5 $12.6

million $/dv (max. $28.2 $53.4
Page 123 of 133

dv)

Step 5 – Select Reasonable Progress Controls

We have considered the four RP factors and anticipated visibility benefits. We note that the 

remaining useful life of the source is reflected in the evaluation of cost of compliance through 

the use of a 20-year amortization period in control cost calculations. In examining energy and 

non-air quality impacts, we note certain potential impacts resulting from the use of ammonia 

injection associated with the SNCR and SCR control options, but do not consider these impacts 

sufficient enough to warrant eliminating any of the available control technologies. 

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option. 

The most stringent option, SCR, also exhibits the highest average cost effectiveness at 

approximately $6,000 to $6,800/ton. The other control option, SNCR, has an average cost 

effectiveness of approximately $3,600/ton.

Our consideration of degree of visibility improvement focuses primarily on the improvement 

from base case impacts associated with each control option. We note that the most stringent 

option, SCR, achieves the largest visibility benefit at 0.41 dv. The visibility benefit anticipated 

for the next control option, SNCR, is smaller at 0.18 dv.

While we consider SNCR to be cost effective at $3,600/ton, we note that it is not anticipated to 

achieve a large visibility benefit. Although the visibility benefit anticipated for SCR is larger, we 

do not consider it sufficient to warrant the relatively high cost of controls for purposes of RP in 

this planning period. Therefore, we are proposing no additional controls for NOX during this 

planning period. 

IV.F. TEP Sundt, Units 1-3

IV.F.1. Summary

This analysis documents the basis for determination of Reasonable Progress (RP) control options 

for control of nitrogen oxide (NOX) emissions from H. Wilson Sundt Generating Station, Units 

I1-3. The Sundt Generating Station is an electric utility power plant located in Tucson, AZ, 

operated by Tucson Electric Power (TEP), and consists of four steam electric boilers (Units I1-4) 

and three stationary combustion turbines (IGT1-3) for a total net generating capacity of 

approximately 500 MW.139 We have identified Unit I4 as a BART source, and are proposing

control requirements in this rulemaking which we consider sufficient for the purposes of 

achieving reasonable progress. Units I1-3 are tangentially-fired natural gas boilers varying in 

size from 80 to 105 MW, and are not subject to BART. We performed the analysis for these units 

based on the following steps:

 

139 As described in Pima DEQ Permit No. 1052, Technical Support Document.
Page 124 of 133

Step 1 – Identify All Available Technologies

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology

Step 4 – Evaluate Impacts and Document Results:

Factor 1: Cost of compliance

Factor 2: Time necessary for compliance

Factor 3: Energy and non-air quality environmental impacts of compliance

Factor 4: Remaining useful life

Factor 5 (Optional): Evaluate Visibility Results

Step 5 – Select Reasonable Progress Controls

We relied primarily upon the information contained in the following documents:

 Technical Analysis for Arizona and Hawaii Regional Haze FIPs: Task 9: Five-Factor 

RP Analyses for TEP Springerville, APS Cholla, TEP Sundt, CalPortland Cement and 

Phoenix Cement Plants; Prepared for EPA Region 9 by University of North Carolina 

at Chapel Hill, ICF International, and Andover Technology Partners (October 3, 

2012) (“Contractor’s Report”)

 EGU Costs_Ch5.xlsx (Contractor's cost calculations)

 EGU Costs_Ch5 (EPA revisions).xlsx (Contractor's cost calculations, but with certain 

formatting revisions made by EPA staff)

IV.F.2. Facility Description

At present, Sundt Units 1-3 do not operate with any pollution control technology for NOX, SO2, 

or particulate matter. A summary of historical data for a period of time extending from 2008-11, 

based on information reported to EPA's Clean Air Markets Division (CAMD), is included in 

Table IV.F-1 below.

Table IV.F-1: Sundt I1-3, Historical Emissions (2008-12)

Year Heat Duty SO2 NOX

(MMBtu/yr) (lb/MMBtu) (tpy) (lb/MMBtu) (tpy)

Sundt 1

2011 1,103,617 0.003 1.93 0.15 90

2010 994,463 0.004 1.74 0.17 87

2009 638,779 0.004 1.15 0.16 53

2008 326,399 0.001 0.17 0.15 28

Sundt 2

2011 921,269 0.003 1.61 0.15 71

2010 668,497 0.004 1.17 0.17 64

2009 989,583 0.004 1.76 0.16 89

2008 1,172,613 0.003 2.01 0.18 117

Sundt 3
Page 125 of 133

2011 2,743,075 0.004 4.80 0.16 223

2010 1,441,562 0.004 2.52 0.15 114

2009 1,948,349 0.003 3.39 0.16 159

2008 1,147,486 0.001 0.34 0.17 101

As described in our Contractor’s Report, we have used the three year period from 2008-10 as the 

baseline period for calculating baseline emissions, as it was the most recent data available at the 

time of the analysis. Although more recent data is presently available, recent generation and 

emission rates for Sundt I1-3 do not differ significantly from the 2008-10 period. 

IV.F.3. RP Analysis for NOX

Step 1 – Identify all available technologies

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOX to nitrogen and water. A NOX reducing 

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through 

injection nozzles at the cyclone inlets. Because catalyst is not used to drive the reaction, 

temperatures of 1600-2100 degrees F are required. Flue gas temperature at the point of reagent 

injection can greatly affect NOX removal efficiencies and the quantity of ammonia or urea that 

will pass through the SNCR unreacted (referred to as ammonia slip). At temperatures below the 

desired operating range, the NOX reduction reactions diminish and unreacted ammonia emissions 

increase. Above the desired temperature range, ammonia is oxidized to NOX resulting in low 

NOX reduction efficiencies.

Ultra Low NOx Burners (ULNB)

Low NOx burners (LNB) limit NOx formation by controlling both the stoichiometric and

temperature profiles of the combustion flame in each burner flame envelope. This control is 

achieved with design features that regulate the aerodynamic distribution and mixing of

the fuel and air, yielding reduced oxygen in the primary combustion zone, reduced

flame temperature and reduced residence time at peak combustion temperatures. Ultra Low-NOx 

burners (ULNB) are a type of innovative LNB that achieves low emissions while maintaining 

flame stability and heat transfer characteristics.

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses either ammonia or urea in the 

presence of a metal-based catalyst to selectively reduce NO and NO2 to molecular nitrogen, 

water, and oxygen. The catalyst lowers the temperature required for the chemical reaction 

between NOX and the reducing agent. Technical factors that impact the effectiveness of this 

technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur 

content of the fuel, design of the ammonia injection system, and the potential for catalyst 

poisoning.

Step 2 – Eliminate technically infeasible options
Page 126 of 133

ULNB, SNCR and SCR have been demonstrated as technically feasible on natural gas-fired 

boilers. At this time, we have not identified any design considerations at Sundt Units I1-3 that 

would warrant eliminating either option as technically infeasible.

Step 3 – Evaluate control effectiveness of remaining control technologies

Selective Non-Catalytic Reduction (SNCR)

Typical NOX control efficiencies range from 40% to 60%, depending on inlet NOX 

concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous 

reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of 

interfering chemical substances in the gas stream. As natural gas-fired units, Sundt Units 1-3 

already exhibit low NOx exhaust concentrations. While SNCR can still be effective at further 

reducing NOx emissions on such inlet streams, an already low inlet concentration reduces its 

overall control efficiency. As noted in our Contractor’s Report, we have therefore used a 20% 

control efficiency for SNCR.

Ultra Low NOx Burner (ULNB)

Based on our Contractor’s Report, the expected emission performance of ULNB is 0.06 

lb/MMBtu on an annual average basis. For Sundt 1-3, this corresponds to a control efficiency of 

approximately 60%. 

Selective Catalytic Reduction (SCR)

Existing vendor literature and technical studies indicate that SCR systems are capable of 

achieving approximately 80-90% control efficiency, and that this emission rate can be achieved 

on a retrofit basis. For natural gas-fired units, our contractor used a design emission rate of 0.03

lb/MMBtu (annual average). In the case of Sundt Units I1-3, this corresponds to control 

efficiencies of approximately 80%. 

Step 4 – Evaluate Impacts and Document Results

Factor 1: Cost of compliance

Our evaluation of this factor is based primarily on the cost effectiveness of each control option, 

as measured in dollars per ton of pollutant removed ($/ton). Annual emission estimates used in 

evaluting costs of compliance are summarized below. These emission estimates are based upon 

the control effectiveness described in Step 3 above, and on annual capacity factors calculated 

from data reported to EPA's CAMD.

Table IV.F-2: NOX Emission Estimates

Control 

Option NOX Emissions

Emission 

Reduction

(lb/MMBtu) (lb/hr) (tpy) (tpy)

Sundt Unit 1

Baseline 0.16 190 75 --

SNCR 0.12 152 60 15

ULNB 0.06 74 29 46
Page 127 of 133

SCR 0.03 38 15 60

Sundt Unit 2

Baseline 0.16 197 86 --

SNCR 0.13 157 69 17

ULNB 0.06 72 32 55

SCR 0.03 39 17 69

Sundt Unit 3

Baseline 0.16 206 144 --

SNCR 0.13 165 115 29

ULNB 0.06 77 54 90

SCR 0.03 41 29 115

An estimate of control costs is summarized in the tables below, and is based primarily upon the 

cost estimation module for SCR and SNCR systems developed as part of the Integrated Planning 

Model. Detailed cost and emission calculations can be found in our contractor's report. 

Table IV.F-3: NOX Control Cost Estimates

Control 

Option

Total 

Capital 

Cost

Annualized 

Capital 

Cost

Annual 

O&M 

Costs

Total 

Annual 

Cost

Cost 

effectiveness 

($/ton)

($) ($/yr) ($/yr) ($/yr) Ave Incr

Sundt Unit 1

Baseline -- -- -- -- -- --

SNCR $2,176,000 $231,511 $125,800 $357,311 $23,806 --

ULNB $3,264,000 $347,267 $34,356 $381,622 $8,297 $785 

SCR $10,097,888 $1,074,344 $155,703 $1,230,047 $20,488 $60,425

Sundt Unit 2

Baseline -- -- -- -- -- --

SNCR $2,176,000 $231,511 $131,871 $363,382 $21,096 --

ULNB $3,264,000 $347,267 $34,546 $381,813 $6,991 $493 

SCR $10,097,888 $1,074,344 $156,847 $1,231,190 $17,869 $59,463

Sundt Unit 3

Baseline -- -- -- -- -- --

SNCR $2,272,000 $241,725 $165,063 $406,788 $14,107 --

ULNB $3,408,000 $362,587 $37,264 $399,852 $4,437 -$113

SCR $10,385,267 $1,104,919 $168,654 $1,273,573 $11,042 $34,629

Factor 2: Time necessary for compliance

In the case of SNCR we estimate that implementation could be completed within 2-3 years of the 

final rule. For SCR, we estimate that implementation could be completed within 4-5 years of the 

final rule
Page 128 of 133

Factor 3: Energy and non-air quality environmental impacts of compliance

With respect to the potential energy impacts of the control options, we note that SCR incurs a 

draft loss that will increase parasitic loads, and that other emissions controls may also have 

modest energy impacts. The costs for direct energy impacts, i.e., power consumption from the 

control equipment and additional draft system fans from each control technology, are included in 

the cost analyses and are not considered further in this section. Indirect energy impacts, such as 

the energy to produce raw materials, are not considered, consistent with the BART guidelines.

Ammonia adsorption (resulting from ammonia injection from SCR or SNCR) to fly ash is 

generally not desirable due to odor but does not impact the integrity of the use of fly ash in 

concrete. However, other NOX control technologies, including LNB, also 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. Commercial scale 

technologies exist to remove ammonia and LOI from fly ash. Moreover, the impact of SCR on 

fly ash is smaller than the impact of LNB on fly ash, and in both cases, the adverse effects can be 

mitigated.140 We conclude that the ability of the relevant facilities to sell fly ash is unlikely to be 

affected by the installation of SCR and SNCR technologies.

SCR and SNCR may involve potential safety hazards associated with the transportation and 

handling of anhydrous ammonia. However, since the handling of anhydrous ammonia will 

involve the development of a risk management plan (RMP), we consider the associated safety 

issues to be manageable as long as established safety procedures are followed. As a result, we do 

not consider these impacts sufficient enough to warrant eliminating either of the available control 

technologies.

Factor 4: Remaining useful life of the source

We are not aware of near-term limitations on the useful life of any of the boilers, and have 

assumed that they will remain in service for at least as long as the 20-year amortization period of 

the control equipment.

Factor 5 (Optional): Evaluate Visibility Results

The overall modeling approach followed for every facility is described in the modeling protocol 

prepared by UNC (cited above) and in the Federal Register notice. This section describes only 

the facility-specific differences in the modeling. Full Sundt units 1, 2, & 3 modeling results, 

including for the 98th percentile in individual years, and for alternative visibility methods 6a, 6b, 

and 8a, can be found in the UNC spreadsheet spg_az_unit1-2_dollarperdv_analysis_final.xls

 

140 “Impact of Ammonia in Fly Ash on its Beneficial Use,” Memorandum from Nancy Jones and Stephen Edgerton, 

EC/R Incorporated, to Anita Lee, U.S. EPA/Region 9, August 31, 2010.
Page 129 of 133

Table IV.F-4: Sundt unit 1,2, 3 Visibility Impact and Improvement from NOx Controls

Impact

Improvement 

from Control

Class I Area

Distance, 

km

Base case 

(SNCR on 

unit 4)

(ctrl4)

ULNB

(ctrl1/c21 and 

ctrl2/c22)

Chiricahua NM 144 0.43 0.08

Chiricahua Wild. 141 0.51 0.07

Galiuro Wild. 64 1.10 0.22

Gila Wild. 232 0.17 0.02

Mazatzal Wild. 203 0.19 0.02

Mount Baldy Wild. 232 0.15 0.02

Pine Mountain Wild. 247 0.15 0.01

Saguaro NP 17 3.40 0.40

Sierra Ancha Wild. 178 0.19 0.02

Superstition Wild. 137 0.32 0.04

Cumulative (sum) 6.6 0.9

Maximum 3.40 0.40

# CIAs >= 0.5 dv 3 0

million $/dv (cumul. 

dv) $1.3

million $/dv (max. 

dv) $2.9

These results assume unit 4 has SNCR and DSI in place. The benefits of ULNB on units 1,2,3 with unit 4 

having SNCR are interpolated between results having unit 4 at base (LNB, UNC’s Ctrl2-2 or c22, 

CALPUFF ctrl2) and unit 4 having SCR (UNC’s Ctrl2-1 or c21, CALPUFF ctrl1).

Step 5 – Select Reasonable Progress Controls

We have considered multiple factors, including cost of compliance, the time necessary for 

compliance, the energy and non-air environmental impacts, the remaining useful life of the 

source, and anticipated visibility benefits. We note that the remaining useful life of the source is 

reflected in the evaluation of cost of compliance through the use of a 20-year amortization period 

in control cost calculations. In examining energy and non-air quality impacts, we note certain 

potential impacts resulting from the use of ammonia injection associated with the SNCR and 

SCR control options, but do not consider these impacts sufficient enough to warrant eliminating 

any of the available control technologies. 

Our consideration of cost of compliance focuses primarily on the cost-effectiveness of each 

control option, as measured in cost per ton and incremental cost per ton of each control option.

Neither SCR nor SNCR are considered cost effective for any of the units at $11,000 up to 

$23,000/ton. ULNB is the most cost effective option, ranging from $4,000 to $11,000/ton. Our 

consideration of degree of visibility improvement focuses primarily on the improvement from 
Page 130 of 133

base case impacts associated with each control option. We note that the most cost effective 

option, ULNB, achieves the largest visibility benefit at 0.40 dv.

We are proposing no additional controls for NOX during this planning period. We do not 

consider either SCR or SNCR to be cost effective, and the cost effectiveness of ULNB is 

relatively high in light of the anticipated visibility benefit. However, this decision should be 

revisited in future planning periods, particularly if these units operate at a higher capacity factor, 

which would result in lower cost effectiveness values. 

IV.G. Area Sources of NOX and SO2

An area source may be defined as a collection of similar emission units within a geographic area. 

Commonly, area sources have been defined at the county level, and most area source methods 

are designed to estimate area source emissions at the county level. Area sources collectively 

represent individual sources that are small and numerous and that have not been inventoried as

specific point, mobile, or biogenic sources. Individual sources are typically grouped with other 

like sources into area source categories. These source categories are grouped in such a way that 

they can be estimated collectively using one methodology. For example, gasoline stations and 

dry cleaning establishments are often treated as area sources. 

The main reason not to treat them as point sources is that the effort required to gather data and 

estimate emissions for each individual facility is great although emissions per facility are 

generally small. For these sources, the distinction between point and area is usually defined by a 

cutoff point typically based on annual emissions. 

The main distinction between point and area sources is the methodology used to estimate 

emissions. Point sources are inventoried individually, and area sources are inventoried 

collectively. While all stationary sources could be treated as either point sources or area sources, 

for practical reasons some cutoff is usually set to distinguish between them. The end use of the 

inventory, the desired accuracy of the emissions, and the resources available for inventory 

development all affect where that cutoff is set.141

In EPA’s action on the Arizona Regional Haze SIP, we approved the State’s emissions inventory 

and its determination that it was not reasonable to control area sources of some pollutants. 

However, we did not approve Arizona’s determination that it was not reasonable to control area 

sources of NOX and SO2. These sources comprise a small, but growing portion of the overall 

emissions of these pollutants. Table IV.G-1 shows the emission trends in Arizona, omitting the 

additional emission reductions from point sources expected from EPA’s FIP. 

Table IV.G-1: Emissions Trends in Arizona 2002-2018142

Category SO2 [tpy] NOX [tpy]

2002 2018 2002 2018

 

141 These three paragraphs were adapted from “Introduction to Area Source Emissions Inventory Development” 

prepared by the Eastern Research Group for EPA’s Emissions Inventory Improvement Program, April 2001.

142 Source: Table 2, from our proposed action on the Arizona Regional Haze SIP, 78 FR 29292 at 29296.
Page 131 of 133

Point Sources 94,716 67,429 69,698 68,748

Anthropogenic Fires 190 181 725 676

Wildfire 4,369 4,369 16,493 16,494

Biogenic 0 0 27,664 27,664

Area Sources 2,677 3,408 9,049 12,783

On-road Mobile 2,715 762 178,009 53,508

Off-road Mobile 4,223 546 66,414 43,249

Total 108,890 76,695 368,322 223,122

Table IV.G-1 shows that area sources comprise a small portion of the overall inventory 

(approximately 2.5 percent for each pollutant in 2002). However, it is the only part of the 

inventory that is expected to grow. Therefore, it merits consideration for controls to ensure 

reasonable progress, especially considering the long-term nature of the regional haze program. 

IV.G.1. Source Identification and Emissions Estimates

The initial step in the reasonable progress analysis is identifying potentially affected sources. 

EPA began with the 2008 National Emissions Inventory (NEI).143 The NEI is a comprehensive 

and detailed estimate of emissions of pollutants from all sources. The NEI is prepared every 

three years by the EPA based primarily upon emission estimates and emission model inputs 

provided by State, Local, and Tribal air agencies for sources in their jurisdictions, and 

supplemented by data developed by the EPA.

EPA selected data from the nonpoint dataset in the 2008 NEI and analyzed it to determine the 

most significant area sources of SO2 and NOX in Arizona. The initial analysis produced the list of 

source categories summarized in Table IV.G-2. This table uses the acronym SCC which stands 

for the Source Classification Code. This is the code the NEI uses to identify area source 

categories.

Table IV.G-2: Initial List of Significant Area Sources from 2008 NEI

SCC Description Annual 

Emissions 

[TPY]

Percentage of 

Total Area 

Source 

Emissions

Cumulative 

Percentage of 

Area Source 

Emissions

SO2 Sources

2102004000 Distillate combustion industrial 

boilers and Internal Combustion (IC) 

engines

1652.1 47.9% 47.9%

2102002000 Coal fired industrial boilers 918.0 26.6% 74.6%

2103004000 Distillate commercial boilers and IC 

engines

483.5 14.0% 88.6%

2399000000 Industrial processes not elsewhere 

classified

110.4 3.2% 91.8%

NOX Sources

2102004000 Distillate combustion industrial 

boilers and IC engines

6,864.5 43.2% 43.2%

 

143 Information about and data from the 2008 NEI can be found at the following URL: 

http://www.epa.gov/ttnchie1/net/2008inventory.html.
Page 132 of 133

2103004000 Distillate combustion commercial 

boilers and IC engines

3,373.1 21.2%

64.4%

2104006000 Residential Natural Gas Combustion 1,645.7 10.3% 74.7%

2102006000 Industrial Natural Gas Combustion 765.4 4.8% 79.5%

2610000500 Open burning, land clearing debris 727.0 4.6% 84.1%

2103006000 Commercial Natural gas combustion 644.0 4.0% 88.2%

2399000000 Industrial process not elsewhere 

classified

340.2 2.1% 90.3%

EPA performed some additional quality assurance on these emissions estimates that resulted in 

some source categories being eliminated or having the estimated emissions modified so more 

accurate totals could be used for the reasonable progress analysis.

Coal fired industrial boilers (SCC: 2102002000) appears to be a significant SO2 source. This is 

an unusual source for Arizona, since these types of boilers are not usually found in the 

Southwest. The vast majority of the emissions from this source category were from Pima County 

which had estimated emissions of 568.2 tpy, ten times higher than any other county in Arizona. 

If this number were accurate, the state and local agencies would be knowledgeable about these 

sources. A more likely explanation is that there was an error in the database, perhaps a misplaced 

decimal point. Based on a discussion with the Arizona Department of Environmental Quality, 

EPA determined that this number was likely an error and eliminated this source category from 

further consideration.144 No other top SO2 sources required corrections.

The top two NOX area source categories also had data quality issues: distillate combustion 

industrial boilers and IC engines (SCC: 2102004000) and distillate combustion commercial

boilers and IC engines (SCC: 2103004000). The NEI showed that over 90% of the emissions 

from each of these categories were from Maricopa County. Maricopa County comprises roughly 

63% of the population of Arizona. It seems unlikely that such a large portion of the emissions 

could be coming from Maricopa County. 

The emissions inventory numbers for Maricopa County were developed by the Maricopa County 

Air Quality Department (MCAQD). EPA consulted with the MCAQD about this apparent 

discrepancy. According to the MCAQD, the issue arose from the choice of data sources for fuel 

consumption in the county. The Department reviewed their methodology and decided to use a 

different methodology for their 2011 emissions estimates for this source category.145 This new 

method is consistent with the method used in the rest of Arizona and with EPA’s standard 

approach for this source category. With this new method, estimated emissions from distillate 

combustion commercial boilers and IC engines (SCC: 2103004000) in Maricopa County 

dropped from 3,273 tpy of NOX to 3.7 tpy of NOX. Given this large change in the estimated 

emissions, this source category was no longer significant and was dropped from the list of top 

sources. Also, the estimated emissions from distillate combustion industrial boilers and IC 

engines (SCC: 2102004000) in Maricopa County dropped from 6,375 tpy to 1,899 tpy. Even 

with this drop in estimated emissions, this source continues to be significant. 

 

144 See August 1, 2013 email from Bryan Paris, ADEQ to Greg Nudd, EPA Region 9.

145 See August 21, 2013 email from Bob Downing, MCAQD to Greg Nudd, EPA Region 9 with attachment.
Page 133 of 133

EPA determined that the 2011 emissions estimate is more likely to be accurate and so substituted 

the 2011 estimated emissions for this source category from Maricopa County for the 2008 

emissions. That is why the emissions for this category are listed as 6,864 tpy in Table IV.G-2 but 

as 2,300 tpy in Table 51 of the proposed action.

These significant changes point to a weakness in using the area source inventory procedures, as 

they currently stand, for developing control strategies for regional haze. EPA will work with 

ADEQ and MCAQD for future inventories to improve the reliability of the emissions estimates 

for key area source categories in Arizona.

IV.G.2. Sources of Control Strategy Information for Identified Area Source Categories

EPA used three documents to analyze control strategies in order to determine if it is reasonable 

to require additional controls on significant area sources to ensure reasonable progress in 

visibility improvement: WRAP Four-Factor Analysis Report,146 EPA’s Control Strategy Tool,147

and the documentation for EPA’s AirControlNet tool.148 Table IV.G-3 provides details on the 

source of control strategy information for the significant area sources.

Table IV.G-3: Source of Control Strategy Information

Category Source of Control Strategy Information

Industrial, commercial and institutional 

boilers burning distillate fuel oil

WRAP Four-Factor Analysis Report, Table 6-3; 

confirmed in Control Strategy Tool*

Industrial, commercial and institutional IC 

engines burning distillate fuel oil

WRAP Four-Factor Analysis Report, Table 3-3; 

confirmed in Control Strategy Tool

Residential Natural Gas Combustion AirControlNet manual, p III-90; confirmed in Control 

Strategy Tool

Note that the WRAP report estimates for the first category were for industrial boilers. Costs may 

be higher on a $/ton basis for the smaller commercial and institutional boilers due to the 

proportionally higher capital costs of some of the controls.

 

 

146 “Supplementary Information for Four Factor Analyses by WRAP states,” EC/R Incorporated, corrected version, 

April 20, 2010.

147 See http://www.epa.gov/ttnecas1/cost.htm for more detail on the tool and the spreadsheet titled AZ FIP CoST 

Analysis_for Greg Nudd Rg 9_2013-08-13.xls.

148 AirControlNet Version 4.1 documentation report,” May 2006, E.H. Pechan and Associates.