# 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 , 201 3Page 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 94105Page 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 NO X BART Analysis

................................ ................................ ................................ 23

III.B.6 SO 2 BART Analysis

................................ ................................ ................................ .. 31

III.B.7 BART Alternative

................................ ................................ ................................ ..... 39

III.C. L hoist 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 NO X

................................ ................................ ........................... 47

III.C.5 SO 2 BART Analysis

................................ ................................ ................................ .. 52

III.C.6 PM BART Analysis

................................ ................................ ................................ .. 58

III.D. ASARCO Smelter

................................ ................................ ................................ ........... 59

III.D.1. S ummary

................................ ................................ ................................ .................. 59

III.D.2. Facility Description

................................ ................................ ................................ .. 60

III.D.3. General Approach to Five

- Factor BART Analysis

................................ .................. 62Page 4 of 133

III.D.4. SO 2 BART Analysis

................................ ................................ ................................ . 63

III.D.5. BART Analysis for NO

x ................................ ................................ .......................... 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 SO 2

................................ ................................ ........................... 78

III.E.5 BART Analysis for NO

x ................................ ................................ ............................ 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 NO X

................................ ................................ ............................... 90

IV.C. Phoenix Cement

................................ ................................ ................................ ............ 100

IV.C.1. Summary

................................ ................................ ................................ ................ 100

IV.C.2. Facility Description

................................ ................................ ................................ 101

IV.C.3. RP Analysis for NO X

................................ ................................ ............................. 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 NO X

................................ ................................ ............................. 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 NO X

................................ ................................ .............................. 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 NO X

................................ ................................ .............................. 125

IV.G. Area Sources of NO X and SO 2

................................ ................................ ...................... 130

IV.G.1. Source Identification and Emissions Estimates

................................ ..................... 131

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

.. 133Page 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 i s not intended to be a stand

- alone document. It is a compilation of detailed technical information intended to support EPA’s 201 4 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 detail s.



### II. Visibility Modeling Approach

To estimate th e degree of visibility improvement expected to result from various BART control options, EPA follow ed the modeling approach recommended in the BART Guidelines

. We developed a modeling protocol, used maximu m 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 improvem ent 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. 1 EPA 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 Mi ami 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 d istances are from the facility to the nearest modeli n g receptor in each are a. The accompanying map in Appendix A shows the facilities and areas.

A FIP modeling protocol 2 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 Nor th 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 E nvironment, 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 andPage 6 of 133

during 2005

- 2006 by various States, EPA Regions, an d Federal Land Managers (FLMs). However, there are several differences between our protocol and that of the WRAP, in meteorological i nput 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 parameter s 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 use s 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 simp ler table showing just the stack parameters (latitude and longitude, stack hei ght, stack exit velocity, etc.).

Visibility results are provided in tables below in the sections for individual facilities; a spreadsheet with more comprehensive visibility resu lts 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 ref

l ected 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”.

T he actual model input and output files created by UNC and EPA and are too voluminous t o 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 bas ed on the Mesoscale Model version 5 (MM5) prognostic meteorological fields. However, EPA meteorological inputs differed

from the WRAP’s in that the y used CALMET inputs developed by the AECOM C orporation (formerly ENSR) for modeling of emissions at the Nava jo 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

, w hen blending in meteorological station wind observations, AECO M 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 Corpor ation, 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 D efault 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 F LM 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 p er 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 55Page 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 5.8 5 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: Lam bert 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 Arizo na 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 Set tings

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 SO 2 , SO 4 , NO 3 , HNO 3 , 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, Appendi x 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 070 623, 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 incorporate d 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 Model ing” 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

- de fault 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 t hat in some cases updated parameters were provided by the facilities at EPA’s request

.

Baseline NO

x and SO 2 emissions used in modeling the facilities were generally based on data

from Continuous Emissions Monitoring (CEMS) in place at the facilities , wher e 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 CE MS 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

approve d 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/h our 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 model ing was generally the value

used in the WRAP ’s BART modeling

. However, for all sources except the two smelters, EPA

used procedures devel oped by the National Park Service 8 to 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 ”

,

“ Springer ville_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 PM 2.5 (also called “PMF” or fine par ticulate within the model input )

. Variations on these emissions baseline c hoices 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 NO

x BART alternatives were evaluated, SO 2 and PM 10 emissions were still also included in the modeling . Modeling al l 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 t he fact that deciview benefits from

controls on individual units are n ot 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 provide d by the National Park Service, 9 and 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 Chiraca hua 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 an d to adjust the partitioning of NO 3 between HNO 3 and nitrate NO 3 - . 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 in put preparation was straightforward for HNO 3 /NO 3 - 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 fo rm 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

Mo deling 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 backg round 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

C oncentrations are converted to deciviews by the CALPOST post

- processor in two steps. First,

the IMPROVE 12 equation is used to estimate extinction b ext from the predicted concentrations of various pollutants. Extinction, b ext , is the percent of light scatter ed 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 converte d to deciviews, using the defining equation for deciviews: deciviews = 10 ln(b ext / 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 follo wed 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 v ersus best 20 percent of days) , and 3) which “98th percentile” from the model to use.

Visibility Calculation Method: Visibility impacts may be computed with CALP OST using either

the old or the revise d 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, establ ished 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:

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

+ 10

The bracketed quantities are concentrations in  g/m 3 , 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

, with out pollutants

. The f(RH) is a water growth factor for sulfate and nitrate ; i ts value depends on relative humidity (RH) , ranging from 1 at low humidi ty to 18 at 98% humidity.

The revised IMPROVE equation 13 , Method 8 in CALPOST, is:

b ext = 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 * [NO 2 (ppb)]

In the revised equation, s ulfate is assumed to be all “large sulfate” if total sulfate is over 20 μg/m 3

, 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

factor s (fs(RH), etc.) for large and small sulfate and nitrate , and for sea salt, and a Class I area

specific 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. Metho d 8 is currently preferred by the Federal Land Managers; since the revised IMPROVE equation performs better at estimating visibility. 14 B aseline impacts using method 6 are about 10 percent higher than those using method 8.

13 Revised IMPROVE Algorithm for Estimating Lig ht 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 fo r 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: An other CALP OST 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

concentr ations 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 s maller 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 re lied 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, f or most of the facilities in this proposal, EPA used all four

c ombinations 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 consist ent 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 NO 2 (LVNO2=T), which is supposed to be included only for method 8.

EPA corrected this fo r 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 C hiracahua 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 t he 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 Sun dt 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 B est 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 pe rcent 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 P ercentile F rom M

odel: As recommended in the BART Guidelines, the 98th percentile daily impact in deciviews i s 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 the se 365 maximum daily values, the 98th percentile is chosen .) For a single complete year of meteorology

, the 8th high est value would represent the 98th perc entile (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 per centile; 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. 98 th 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 th e full day list. The two procedures

are eq uivalent.



### 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 Nelso n Lime Plant, EPA is relying on modeling performed by Trinity Consultants for the facility owner, Lhoist North America (LNA).



### II I . Best Available Retrofit Technology (BART) Analysis

II I .A. Introduction

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

emission reduction based on the BART Guidelines 18 as summarized below. Steps 1 through 3 address the availability, feasibility and effectiveness of retrofit control options. In our analysis of control technology option s, 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.Page 16 of 133

factor in determining control effectiveness. Step 4 is the five

- factor 19 BART analysis that results in selecting the emission limit that represents BART in Step 5.

EPA conducted Best A vailable 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.



### II I

. B

. Sundt Generating Station Unit 4

I II. B .1. Summary

This document contains the basis for the determination of BART control options for nitrogen oxides (NO X ), particulate matter (PM), and sulfur dioxide (SO 2 ) 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: Energ y 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 Arizon a 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 compli ance, 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 calcu lation 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 correspo nding technologies listed in Table III.B

- 1 . As further described in our NO X BART analysis, we are proposing an emission limit consistent with the use of SNCR as constituting

BART for NO X

. In addition, we are proposing a switch to natu ral gas as a better

- than

- BART

alternative.

Table III.B

- 1 : Summary of Proposed BART determinations

Pollutant Emission Limit

(lb/MMBtu) Control Technology

Basis 1

NO X 0. 36 Selective Non

- Catalytic
Reduction (S N CR)

PM 10 0.030 Fabric filter baghouse
(existing)

SO 2 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 up graded with low

- NO X 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 op erating scenario):Page 18 of 133 Table III.B

- 2 : Current emission control technology

Pollutant Control Device Emission Limit

NO X LNB with OFA 0.46 lb/MMBtu 21

PM Fabric filter/baghouse 233 lb/hr 22

SO 2 None 1 lb/MMBtu 23

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 si ze 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 (200 8

- 12)

Year Heat Duty NO X SO 2 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 analy sis was performed by our contractors, the U niversity of

N orth C arolina 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 imp lemented 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 constraint s and variable values that feed into the model algorithms used during an actual IPM model run. S pecifically , we relied upon one specific component of IPM, the air pollution control cost development component. We used the cost information and equations cont ained 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 dispatc h 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 perfo rmance assumptions contained in this component for SO 2 and nitrogen oxides NO X 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 2 012. TEP has indicated that

while Sundt Unit 4 has predominantly operated as a coal

- fired unit, it has rec ently 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 baseli ne period in the BART analysis. Although this represents onl y 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 perio d 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.Page 20 of 133

Factor 2: Energy and Non

- air Environmental Impacts

Given the differences in the technologies for NO X and SO 2 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 calcula tions 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 co st analysis as allowed by the BART Guidelines. 28 Since we are not aware of any enforceable shut

down 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 c onsidered in this proposed

action. 29

Factor 5: Anticipated Degree of Visibility Improvement

Baseline Emissions

Baseline emissions for NO X and SO 2 were based on maximum daily emission rates for Sundt Unit 4 as reported to EPA’s CAMD Acid Rain Program dat abase, for the period from 2008 to

201 0

. 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 per iod correspond ed 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 b aseline 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 c ontrol

.

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 SO 2 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 recom mended 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

- sp ecific 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 recept or 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 correc ted the CALPOST processing for all areas for visibility methods 6a and 6b. Method 6 is the old IMPROVE equation, which does

not include an NO 2 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 SO 2 controls (DSI at 75% control, DFGD, WFGD). EPA performed additional modeling for Pipeline Natural Gas (PNG)

scenarios and for DSI at 70% SO 2 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 SO 2 for the Saguaro National Park. That is, the effect of the SO 2 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 (“ctr l2”), and for intermediate scenarios for

which the SO 2 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 disbene fit, 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

mor e 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 NO 2 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 pre

control emission rates. For e xample, if the 24

- hr pre

- control emission rate is 100 lb/hr of SO 2 , 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 tha t the benefit of proposed BART (SNCR plus DSI) and of conversion to PNG, scaled down along with the percent NO

- to

- NO 2 conversion assumed. As summarized in the notice, the benefits remain substantial for both, and PNG shows greater visibility improvement th an 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 constru cted 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

operate s 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 t han 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 stringe nt 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 t o comprehensively complete a full five

factor BART anal ysis, a s 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 S tandard or MATS), and has the option to comply with a filterable PM 10 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 high

load particulate emissions test results from a recent perform ance 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 PM 10 limit. 33

Table III.B

- 4 : Sundt Unit 4 Particulate Matter Test results

Heat Duty Filterable PM 10 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 PM 10 BART emission limit of 0.03 lb/MMBtu (on a filterable PM 10 basis) based on the use of the existing fabric filter b aghouse.

III.B.5 NO X 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. W hile a change in fuel supply to natural gas instead of coal is a n 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 NO X to nitrogen and water. A NO X 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 NO X removal eff iciencies 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 NO X reduction reactions diminish and unreacted ammonia emis sions increase. Above the desired temperature range, ammonia is oxidized to NO X resulting in low

NO X reduction e fficiencies.

Selective Catalytic Reduction (SCR) SCR is a post

- combustion gas treatment tech nique that uses either ammonia or urea in the presence of a metal

- based catalyst to selectively reduce NO and NO 2 to molecular nitrogen, water, and oxygen. The catalyst lowers the temperature required for the chemical reaction

between NO X and the reducing agent. Technical factors that impact the effec tiveness 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, Co mpliance/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 infeas ible 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 Re duction (SNCR) Design challenges primarily involve ensuring proper m ixing 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 tempera ture window. In addition to temperature and mixing, several other factors influence the performance of an SNCR system, including residence time, reagent

- to

- NO X ratio, and fuel sulfur content. Factors that can influence technical feasibility

include boiler size and configuration, which can cause difficulties in locating and install ing 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 vary ing sizes, and is considered technically feasible. We note that SCR s 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 contr ol 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

Selecti ve Non

- Catalytic Reduction (SNCR) Typical NO X control efficiencies range from 40% to 60%, depending on inlet NO X concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous reducing agent, mixing effectiveness, accepta ble levels of ammonia slip, and presence of interfering chemical substances in the gas stream. Guaranteed NO X reduction rates are in the 50% range to limit ammonia slip to 10 ppm. Because Sundt Unit 4 already operates with NO X combustion controls, we have used an SNCR control efficiency of 30% from a LNB with OFAPage 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 0.05 0 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 0.05 0 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 0.05 0 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 justify ing 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 f or each option. Emission reductions for each option are summarized in Table III.B

- 5 below. A

more detailed version of emission calculations can be fou nd in our docket

, 37 and in our contractor’s report. T he 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 burn ing 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 Contr ol” (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 Emission s.x lsx”.

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 un it gross rating.Page 26 of 133 Table III.B

- 5 : NO X Control Option Emission Estimates

Control Option Control

Efficiency Emission

Factor Heat Duty Capacity N O X Emission

Rate N O X

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,

re vised 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

modificat ions 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 : NO X 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 ca lculations and visibility modeling. In the case of NO X , 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 e xplained 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 consumpti on 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

con sidered, 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 NO X 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

eliminatin g 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 NO X con trol scenario modeling can be found in the model emission rate spreadsheet prepared by our

contractor. 41 Table s 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.xlsPage 28 of 133 Tab le III.B

- 7 : NO X 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 : NO X 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 1.61Page 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 eva luation 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 peri od 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 SN CR 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 im pacts associated with each control option. We note that each of the available

NO X 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 tha t BART for NO

x 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 v isibility 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 av erage cost to be warranted by the projected visibility benefit of SCR for this facility.

We are also seeking comment on the appropriate NO X 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 ac count for this variability, we examined the difference between the highest 30

- day rolling NO X value and the highest annual average NO X value observed over the 2008

- 11 period, which is approximately 17%. 42 We have applied this variability to the annual aver age 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 requiremen t 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 requ iring the installation of additional SO 2 controls (as discussed in the sections below), we consider a three year period for compliance with both BART determinations to be appropriate. W e 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 estab lishes 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 c ompliance deadline are enforceable.

Table III.B

- 9 : NO X 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. W e 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 the se available control technologie s.

Visibility Improvement

Single Largest Class I Improvement (dv)

-- 0.23 0.78

Single Class I A rea C ost E ffectiveness ($/dv)

-- $5,503,339 $7,714,710

Areas ≥ 0.50 dv improvement

-- 0 1

Cumulative Vis i b ility Impr ovement (dv)

-- 0.52 1.63

Cumulative Class I A rea C ost

E ffectiveness ($/dv)

-- $2,434,169 $3,691,702

III.B.6 SO 2 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. W hile a change in fuel supply to natural gas instead of coal is a n inherently less pollut ing 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 s ection VII below.

Lime or limestone

- based wet Flue Gas Desulfurization ( FGD )

W et scrubb ing 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 SO 2 in the flue gas. Design variations may include ch anges to increase the alkalinity of the scrubber slurry, increase slurry/ SO 2 contact, and minimize scaling and equipment problems. Insoluble calcium sulfite (CaSO 3 ) and calcium sulfate (CaSO 4 ) salts are formed in the chemical reaction that occurs

in the s crubber , 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 CaSO 3 , which is difficult to dewater. Solid waste by

- products from wet lime scrubbing are typically m anaged 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 SO 2 in the flue gas to form calcium sulfite s olids. 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, dr y 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 a nd 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, particu late 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. D SI 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 lowe r when compared to a SDA system.

Soda ash and t rona (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 w et FGD control system must
be located after the fabric filter baghou se 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

i nfeasible. 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 g as.

Lime spray dry absorber (SDA or dry FGD)

46 TEP’s review does not eliminate consideration of wet FGD, but does describe several desig n 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 F GD 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

SO 2 emiss ion 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% cont rol 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 SO 2 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 theref

ore 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 : SO 2 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", North east 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 2010Page 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 f or each option. Emission reductions for each option are summarized in Table III.B

- 12 below. A

more detailed version of emission calculations can be fo und in our docket

, 49 and in our contractor’s report. As noted in our NO X BART analysis above, t he heat duty and capacity factor used in the calculations summarized below differ from the values used in the calculations originally prepared by our contractor b ecause 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 : SO 2 Control Option Emission Estimates

Control Option Control

Efficiency Emission

Factor Heat Duty Capacity SO 2 Emission

Rate SO 2 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 : SO 2 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 SO 2 , 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 “remaini ng 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

aux iliary power costs in the cost of compliance estimates. Non

- air q uality 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 chall enge 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 require ments, 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 d egree 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 scru bber.

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 increa sing solid waste generation rates at the plant. Energy impacts are limited to auxiliary power requirements for operation of the DSI system.

Factor 5: Visibility improvementPage 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 NO X control scenario modeling can be found in the model emission rate spreadsheet prepared by our

contractor. 52 Table s III.B

- 1 4 and III.B

- 15 provide the visibility benefits (visibil ity method 8, best 20% days background concentrations) of the three control options

.

Table III.B

- 14 : SO 2 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: SO 2 Control Option Modeling Results, Visibility Benefits

Class I Area Control Scenario

Base

case DFGD (ctrl02) WFGD (ctrl 03) 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

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- 29.xlsPage 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 predict ed visibility disbenef it at Saguaro NP

.

Step 5

– Select BART

The results of our five

- factor analysis are summarized in Table III.B

- 16 below. W e 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

SO 2 control technology in use in the plant, baseline emissions reflect uncontrolled SO 2 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 hi gh 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 primari ly on the improvement from base case impacts associated with each control option. We note that each of the available

SO 2 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 benefit s 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 eno ugh 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 highestPage 38 of 133

30

- day rolling SO 2 value and the highest annual average SO 2 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 0.2 3 lb/MMBtu on a 30

- day (BOD ) rolling basis.

We propose to requir e 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 d ifferent 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 : SO 2 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

-- 7 0 % 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)

-- 0.2 0 0.16 0.11 Single Class I A rea C ost

E ffectiveness ($/dv)

-- $13,944,466 $60,759,680 $98,530,339

Areas ≥ 0.50 dv I mpr ovement

-- 0 0 0

Cumulative v is i b ility Impr ovement (dv)

-- 0.80 0.59 0.43

Cumulative Class I A rea C ost

E ffectiveness ($/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 NO

x and SO 2 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 instal lation 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 alt ernative 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 NO X 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 Summary 59

Year Start Date End Date NO X Emissions Heat Rate NO X 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 0.2 6

2011

-- -- -- -- -- 2012 1/15/2012 11/3/2012 713 5,197,211 0.27

As seen above, Sundt Unit 4 has achieved NO X emission rates between 0.22 and 0.27 lb/MMBtu when operating on natural gas with LNB and OFA. SO 2 emissions over these periods are approximately 0.0055 lb/MMBtu. By comparison, EPA estimates default SO 2 emission factors for natural gas of approximately 0.0006 4 lb/MMBtu. 60 For particulate matter, EPA estimates

default PM 10 emission factors for natural gas of 0.0076 lb/MMBtu. 61 A comparison of natural gas and BART emission rates, based on a proposed NO X 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

NO X Ctrl Tech SNCR+LNB+OFA LNB+OFA

lb/MMBtu 1 0.31 0.22

tpy 917 652 265

Particulate

Matter Ctrl Tech Fabric Filter None

lb/MMBtu 1 0.03 0.01

tpy 88 30 59

SO 2 Ctrl Tech Dry Sorbent Injection None

lb/MMBtu 1 0.22 0.00064

tpy 644 1.9 642

1 Annual average emission factors

As seen in Table III.B

- 1 8 , 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

tha t 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

l b/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 NO

x may not be fully

converted to NO 2 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 exp lored 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

- NO 2 conversion is assumed (i.e., no additiona l conversion of NO to NO 2 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 conv ersion 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 infor mation, 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 NO

x emission limit of 0.25 lb/MMBtu based on a 30

- day BOD rolling average. As discussed previously in the NO

x BART determinati on, 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 t imes, including periods of startup and shutdown. In addition, we are proposing particulate matter and SO 2 emission limits consistent with natural gas use, as well as monitoring, reporting, and recordkeeping requirements.



### III.C. Lhoist Nelson Lime Plant

I II.C.1. Summary

This five factor analysis documents the basis for determination of the Best Available Retrofit Technology (BART) for control of sulfur dioxide (SO 2 ), nitrogen oxides (NO

x ), 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 ( a pprox imately 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 (Sno wflake) 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 wi th 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 Techn ology Determinations.Page 43 of 133

Step 4

-- Evaluat e 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 impac ts 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 Technology 1

Kiln 1

NO X 3.80 Selective Non

- Catalytic Reduction (S N CR)

PM 10 0.12 Fabric filter baghouse (existing)

SO 2 9.32 Lower sulfur fuel

Kiln 2

NO X 2.61 Selective Non

- Catalytic Reduction (S N CR)

PM 10 0.12 Fabric filter baghouse (existing)

SO 2 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 PlantPage 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 electr ic 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)

pr ocessing 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 equipm ent 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

lim e 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 (CaCO 3 ) into quicklime (CaO).

Emissions from this facility include SO 2 , N O

x 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 equ ipment for NO

x and SO 2

.

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 ourPage 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 Contracto r’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 in formation, 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 e mission factors are based on lb/ton values observed during

CEMS te sting 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 base d on the statistical analysis. LNA notes that, in general, the emission calcul ations 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 “i n 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 NO X or SO 2 CEMS, continuously measured actual emis sions 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 basel ine 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 BAR T 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 ha ve 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 Dail y and Annual Baseline Emissions

Kiln Lime Production NO X SO 2

Max Daily 2 Max

Annual 3 Year Emission

Factor 1 Emissions Emission

Factor 1 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 NO X and SO 2 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 c ontrol 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.

P ollutant

- 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 BAR T Guidelines. 63 Since we are not aware of any enforceable shut

down 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

ac tion.

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 Plan t , cited above,

63 40 CFR Part 51, Appendix Y, section IV.D.4.k.Page 47 of 133

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 da ta 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 contractor s in the BART analyses that they prepared for select sources, including the N elson 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
tempera tures 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 SO 2 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 NO X

Step 1

-- Identify all available technologies

NO

x is generated during fuel combustion by oxidation of chemically

- bound nitrogen in the fuel and by thermal fixation of nitrogen in the combustion air. NO

x is generated in both the burning

zone of Kiln 1 and Kiln 2

. The kilns are allowed to burn coal, petrol eum coke, fuel oil, or any

combination of these fuels.

The available retrofit NO

x controls technologies for Kiln 1 and Kiln 2 are as follows:

 Low

- NO

x 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

pro vided upon request.Page 48 of 133

 Selective Non

- Catalytic Reduction (SNCR)

Step 2

-- Eliminate technically infeasible options

Low

- NO

x 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 NO

x emissions, it is not clear whether this control technology will be effective o n lime kilns. This technology has not been applied to similar rotary lime kilns according to EPA’s RACT/BACT/LAER Clearinghouse and other

recent NO

x control technology determinations. This control technology is eliminated as technically infeasible for retr ofit on Kiln 1 and Kiln 2.

Selective Non

- Catalytic Reduction

– This control technique relies on the reduction of NO

x in exhaust gases by injection of ammonia or urea, without using any catalyst. This approach avoids the problems related to catalyst fouli ng 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 NO

x emissions from

the Nelson kilns.

Selective Cat a l

ytic Reduction

– This process uses ammoni a in the presence of a catalyst to selectively reduce NO

x 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 NO

x 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 11 00°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 woul d 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 SC R 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 NO X 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 NO X , 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 NO X 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 th at 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 do es not significantly impact the BART determination.

Factor 4: Rema ining 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 affect ed 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 NO X 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 NO X 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 NO

x control technology in use in the plant, baseline emissions reflect uncontrolled NO

x emissions. InPage 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 e limination 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 ach ieve 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

ea ch 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 a nd $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 NO

x 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 NO

x 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

SN CR installation on lime kilns. Given this relative lack of information regarding SNCR

installation schedules on lime ki lns, 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

o r 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 al so proposing regulatory text that includes monitoring, reporting, and recordkeeping requirements associated with this emission limit.

III.C.5 SO 2 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 th e 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 SO 2 . This technology has b een used for SO 2 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

SO 2 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 SO 2

.

Wet scrubbing involves passin g 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 SO 2 reacts with the scrubbing reagent to form lime sludge that is collected.

The sl udge 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 SO 2 in the exhaust to form solid particles that are the n 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 Nel son Plant experienced disruptive operational issues in the form of buildup of ash rings in the kilns when using a fuel blend with ash conten t approaching a certain range. As a result, LNA believes that a 50% coal mix in the fuel mixture was the

maximum amo unt of coal that could be accommodated and used a 50% coal/50% coke mixture

in its evaluation of a fu el 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 unrea sonable, 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 tha t 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 n ot 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 concl udes 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 scrubb er 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 SO 2

.

Step 3

– Ev aluate 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 5 0%

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 SO 2 emissions.

DSI control effectiveness was estimated at approximately 75% in the C ontractor’s R eport, 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, a nd kiln CO concentration. LNA concluded that control efficiencies in the range of

20

- 40% can be achieved using high sorbent to SO 2 ratios

, and used 40% control efficiency in its

cost and emission calculations. 72 Given the differences in operation between li me 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

71 See 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 regar ding certain annual operatin g 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 C ontractor’s Re p ort. 73

A summary of SO 2 control emission rates and control costs are included in Tables

III.C

- 8 and Table III.C

- 9 below.

Table III.C

- 8 : SO 2 Control Option Emission Estimates

SO 2 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 : SO 2 Control Option Cost Effectiveness

SO 2 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 seco nd, 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 SO 2 , 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 a ny 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 kiln s. Since t here 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 requi re 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, a nd 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 SO 2 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 SO 2 emissions, the impact of burning a lower sulfur fuel blend on other pollutants such as NO

x 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 SO 2 control scenario modeling are summarized below.

Table III.C

- 10 : SO 2 Control Model Emission Rates

SO 2 Con trol 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 2Page 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

- 1 1 and III.C.1 2 show the visibility benefits (visibility method 8, best 20% days background concentrations) of the two control methods

.

Table III.C

- 1 1 : Visibility Modeling of SO 2 Control Option s, 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

- 1 2 : Visibility Modeling of SO 2 Control Option s, 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 0Page 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 SO 2 control technology in use in the plant, baseline emissions reflect uncontrolled SO 2 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 e ach control option. We note that each of the available

SO 2 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

n ot 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 SO 2 is u se 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 technologiesPage 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 Guide lines 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 l ong these most stringent controls available are made federally enforceable for the purpose of implementing BART for that so urce, you may skip the remainder of the analysis, including the visibility analysis. 75

It is unclear to us what degree additional imp rovements, 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 sourc e 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

techn ologies 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 a nd 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.



### I I I. D . A SARCO Smelter

I I I. D .1. Summary This five factor analysis documents the basis for determination of the Best Available Retrofit Technology (BART) for control of sulfur dioxide (SO 2 ) and nitrogen oxides (NO

x ), emissions at

the ASARCO Hayden Smelter.

EPA cond ucted 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 th e Economic Impact Analysis for the Lime Manufacturing MACT Standard (EPA

452/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 Determinatio ns.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: N on

- 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 Technology 1

Pierce

- Smith Converters

NO X NA No additional controls

SO 2 99.8% Double contact acid plant control of gases
collected by primary and secondary capture

systems

Anode Furnaces

NO X NA No additional controls

SO 2 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

.

I I I. 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 pr oduce 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 con centrates 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 copper

rich (approximately 50

- 60% copper) matte to the converters where oxygen

- enriched air oxidizes sulfur to sulfur dioxide (SO 2 ) and iron to iron( II ) oxide (ferrous oxide). The output of thePage 61 of 133

converters, call ed 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 ASAR CO’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 anod e 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, 33 0 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 ga s cleaning plant to remove PM and a double contact sulfuric acid plant that converts SO 2 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, SO 2 , 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 em issions 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 NO

x emissions.

Anode Furnaces

Emissions from the anode furnaces include SO 2 resulting from oxidation of residual sulfur remaining in the blister copper and products of natural gas combustion, including NO

x . In 2011 ASARCO installed a baghouse to control particulate emissions from the anode furnaces, but SO 2 and NO

x emissions are uncontrolled.

Baseline Emissions

Neither ASARCO nor ADEQ identified baseline emissions for ASARCO Hayden. Therefore, as
a prelim inary step, we calculated baseline emissions for both NO X and SO 2

. For SO 2

, w e are considering the average of the two highest emitting years from the last five years that ASARCO
reported to ADEQ as the baseline. For NO X , we determined the potential to emit NO

x 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

SO 2 1,034 20,341 1,209 38

NO

x 31 19

I I I. 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 C ompliance

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 th e BART analyses that follow.

81 See BART Gu idelines, 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 BART

eligible. (For example, some units in that set may not have been const ructed between 1962 and 1977.)”Page 63 of 133

Factor 2: Energy Impacts

Given the differences in the technologies for NO X and SO 2 control, there are no common elements relating to this factor discussed here. Pollutant

- specific discussions of these issues are

included in t he following sections.

Factor 3: Non

- air Quality Impacts

Given the differences in the technologies for NO X and SO 2 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 U NC (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 m ethods 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.

II I

. D .4. SO 2 BART Analysis

Converters

Step 1

– Identify all available technologies

We identified two possible control technologies for controlling SO 2 emissions from the

converters:
1. Double contact acid plant

2. Wet scrubbing

Because SO 2 emissions captured by the primary capture system are already controlled by a double contact acid plant, we evaluated potential upgra des 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 Contac t Acid PlantPage 64 of 133

A double contact acid plant uses a solid state catalyst to convert SO 2 to SO 3 , which reacts with water to form sulfuric acid. Sulfuric acid plants typically are designed to control feed streams containing several percent SO 2 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 SO 2 , although it may be necessary to heat the inlet gas stream or the catalyst. In 1984, EPA reported t hat SO 2 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 mixtu re 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

d eactivation, 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 a cid plant to control SO 2 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 SO 2 with li quid 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 SO 2

.

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 SO 2 vented to it. 85 The expected control effectiveness

of wet sc rubbing was provided by ASARCO in the same letter.

Control Technology SO 2 - 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 Ja ck 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 SO 2 collecte d 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 SO 2 collected by the primary capture system.

Double Contact Acid Plant to Contro l 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

- 13 86 :

ln(cost) = 0.1325 + 0.378(%SO 2 ) 0.177 + 0.783(%SO 2 ) - 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

%SO 2 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 rel ative accuracy

test audit (RATA) and SO 2 emissions test multiplied by a factor of 1.5 for “Q” and the second

lowest SO 2 concentration measured during the test. The result of the equation was multiplied by

a factor of 2.57 to convert from 1981 to 2013 dolla rs. 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 1 00 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

cap ture system baseline emissions.

Control

Effectiveness Tons SO 2

Reduced Capital Cost Annualized Capital

Cost Annual

Variable

Cost Total

Annual

Cost $/ton SO 2

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 Perfo rmance 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. W e 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. S ome of the emissions captured by the secon dary capture system could be du cted to the
existing acid plant thus reducing the capacity needed for a new acid plant; and

5. W e 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 t o C ontrol Secondary Capture System

EPA calculated costs of constructing and operating a wet scrubber to control SO 2 from the secondary based on information included in Jack Garrity’s July 11, 2013 letter to Thomas Webb.

We used t he more conservative high

- end estimate of operating costs. We also included a sludge hauling fee of $60 per ton and assumed one ton of SO 2 controlled would result in five tons of sludge.

Control

Effectiveness Tons SO 2

Reduced Capital Cost Annualized Capit al

Cost Annual

Variable

Cost Total

Annual

Cost $/ton SO 2

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 t o C ontrol Acid Plant Tailstack

EPA ca lculated costs of constructing and operating a wet scrubber to control SO 2 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 co sts. We also included a sludge hauling fee of $60 per ton and assumed one ton of SO 2 controlled would result in five tons of sludge.

Control

Effectiveness Tons SO 2

Reduced Capital Cost Annualized Capital

Cost Annual

Variable

Cost Total

Annual

Cost $/ton SO 2

Removed

85% 879 $28,000,000 $2,643,002 $9,274,521 $11,917,523 $13,564Page 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 SO 2 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 req uire 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 cap acity 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 SO 2 emissions t hrough a second double contact acid plant results in visibility improvement in 12 Class I areas in Arizona and New Mexico as indicated in Table s III.D

- 4 and

III.D

- 5

.

We did not conduct visibility modeling for the addition of a scrubber . Because the addit ion of a scrubber to the secondary capture system is less efficient at removing SO 2 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 A P 42 factor for low NOx burners

.Page 6 8 of 133

Similarly, we did no t conduct visibility modeling for the addition of a tailstack scrubber because of the much higher cost per ton of SO 2 removed and the relatively low quantity of SO 2 reduced

.

Table III.D

- 4: Visibility Modeling of SO 2 Control Option s, 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 SO 2 Control Option s, 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. 0.44Page 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 BA RT 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 SO 2 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 SO 2 ). 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, w e 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 SO 2 for the converters :

1. An SO 2 control efficiency of 99.8 percent, 30

- day rolling average, on all SO 2 captured by
the primary and secondary control systems. The control efficiency may be averaged
between the two capture systems on a mass basis. (For ever y 30

- day period the total mass

of SO 2 exiting the two control systems must be no greater than 0.0019 percent of the SO 2 entering the control systems.)

2. Compliance with the SO 2 BART limit may be verified either through the use of SO 2 CEMS before and after co ntrols in each system or by using post

- control CEMS and acid
production rates. A limit of 2.49 lbs SO 2 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 SO 2

.

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 ImpactsPage 71 of 133

Factor 1: Cost of Compliance

We performed a calculation of the cost to control SO 2 from the anode furnac es using the same equation used for the converters and estimated the cost to control SO 2 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 scrubbe r 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 SO 2

Reduced Control

Efficiency $/ton SO 2

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 SO 2

Reduced Control

Efficiency $/ton SO 2

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 visibi lity improvement, we propose that controlling

SO 2 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 limitPage 72 of 133

where “technolog ical 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 i nfeasible 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 cop per 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 NO x

Step 1

– Identify all available technologies

We identified low

- NO

x 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 NO

x 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 NO

x 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.

Fact or 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 “emis sion 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 98 th percentile visibility impact resulting from baseline NO

x emissions from the Hayden Smelter is 0.01 dv. 92 T hus, 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 NO

x emissions is not warranted for purposes of BART. However, in order to ensure that NO

x emissions do not increase in the future, we propose to set a 12

- month rolling limit of 40 tons of

NO

x 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 sligh tly 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



### I I I. E . Freeport McMoRan Smelter

I I I. E .1. Summary

This five factor analysis documents the basis for determination of the Best Available Retrofit Technology (BART) for control of sulfur dioxide (SO 2 ) and nitrogen oxides (NO

x ), emissions at

the Freeport McMoRan Smelter.

EPA conducted a five step analysis, with step four incorporating the five factor analysis, in accordance with BART guideli nes. 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 emi ssions and document the results Factor 1: Cost of compliance

Factor 2: Energy impacts

Factor 3: N on

- 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 report

Asarco

- 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 Gui delines 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 Technology 1

Hoboken Converters

NO X NA No additional controls

SO 2 99.7% Double contact acid plant control of gases
collected by primary and secondary capture

systems

Electric Furnace

SO 2 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

I I I. 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 m atte 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 th e 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 o utput 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

atmosp here 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 (conv erters 2

- 5), the electric furnace, and the remelt/mold pouring furnace were installed in 1974 and are subject to BART for sulfur dioxide (SO 2 ), nitrogen oxides (NO

x ), and particulate matterPage 75 of 133

(PM 10 ). FMMI later provided documentation that the pour/remelt fur nace 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 SO 2 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 SO 2 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.

Becau se the converters are heated by the combustion of natural gas they are also sources of NO

x 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 i nto 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 me lt in the electric furnace.

96 Letter from Todd Weaver, FMMI to Mr. Gregory Nudd, EPA. (March 6, 2013)

.Page 76 of 133

SO 2 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 duct s emissions to be controlled by the vent fume scrubber.

Because the electric furnace is electrically heated it does not emit measurable quantities of NO

x .

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 SO 2 fugitives through their sulfur bal ance method.

FMMI reports point source SO 2 emissions to ADEQ by stack and performs a mass

- balance equation to determine uncollected emissions. Table III.E

- 3 contains SO 2 emissions in tons per year reported by FMMI to ADEQ for the acid plant duct, acid pla nt 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 SO 2 sent to the acid plant is emitted by the converters and 65 percent by the IsaSmelt and elect ric 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 calcula ted 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 SO 2 emissions using a sulfur balance method

defined in their T itle V p ermit. 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 SO 2 emissions by assuming a range of collection efficiencies of the

e xisting capture system associated with the Hoboken converters from 95 to 98 percent.

Table III.E

- 3 : FMMI 2010 Baseline SO 2 Emissions in TPY

Acid Plant Duct Acid Plant

Bypass Vent Fume Duct Uncollected

SO 2 1,415 93 331 8,472

BART

- Eligible 495 33 7 3,231

– 8,078

FMMI reports potentially BART

- eligible NO

x emissions from the acid plant duct and from “natural gas combustion.” FMMI estimates that 15 percent of NO

x 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 emi ssions” 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 Baselin e NO

x Emissions in TPY

Acid Plant Duct Natural Gas Combustion

NO

x 154 15

BART

- Eligible 23 15

I I I. 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 o f 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 A SARCO 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 NO X and SO 2 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 NO X and SO 2 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 requirem ents 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 actio n.

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 difference s in the modeling. Full FMMI Miami modeling results, includingPage 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_visib ility_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 investig ate 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 Sup erstition 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

I I I. E .4. BART Analysis for SO 2

Converters Step 1

– Identify all available technologies

We identified two possible control technologies for controlling SO 2 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 SO 2 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 SO 2 to SO 3 which reacts with water to form sulfuric acid. Sulfuric acid plants typically are designed to control feed streams containing several percent SO 2 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 SO 2 , although it may b e necessary to heat the inlet gas stream or the catalyst. In 1984, EPA reported that SO 2 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 Primar y 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 c ontact 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. Ac cording 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 conta ct acid plant. 99

As noted above, FMMI currently uses a double contact acid plant to control SO 2 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 SO 2 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 (NaO H). Wet scrubbing is commonly used in many industries for control of SO 2 . FMMI uses magnesium oxide scrubbers to control acid plant tailstack emissions “when necessary.”

Step 2

– Eliminate technically infeasible options

Both double contact acid plants an d wet scrubbing are technically feasible and are being used at

FMMI.

Step 3

– Evaluate control effectiveness of remaining control technologies

Based on SO 2 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 SO 2 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 SO 2 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 one

hour SO 2 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 35520Page 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 ar e 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 pr oject 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 SO 2 emissions from the

converters.

Control

Effectiveness Tons SO 2

Reduced Capital Cost Annualized Capital

Cost Annual

Variable

Cost Total

Annual

Cost $/ton SO 2

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 SO 2 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, EP A, July 11, 2013.Page 81 of 133

As shown in Table III.E

- 5 , installing a secondary capture system to collect and direct SO 2 emissions from the converters to the acid plant, the maximum 98th percentile baseline improvement r anges from a low of 0.41 dv to a high of 1.06 dv at Superstition WA.

Table III.E

- 5: Visibility Modeling of SO 2 Control Scenarios, Visibility Impacts

Class I Area Control Scenario

High Base

case (basehi) High Base

converter 85%

capt ure (opt1hi) Low Base

case (baselo) Lo w Base

converter 85%

capt ure (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 SO 2 Control Scenarios, Visibility Benefits

Control Scenario

Class I Area High Base

case (basehi) High Base

converter 85%

capt ure (opt1hi) Low Base

case (baselo) Lo w Base

converter 85%

capt ure (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 0.12Page 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 SO 2 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 SO 2 emissions make numeric capture efficiency infeasible. Therefore, we are proposing to prescribe specific equipment for capture of SO 2 emissions, in addition to numeric control efficiency and related compliance requirements. Specifically, we are proposing the following as BART for SO 2 from the converters:

1. Improvements to the primary capture system and construction of a secondary c apture system and application of the MACT QQQ standards to the capture systems.

2. An SO 2 control efficiency of 99.69 percent, 30

- day rolling average, on all SO 2 captured
by the primary and secondary control systems.

3. Compliance with the SO 2 BART limit may be verified either through the use of SO 2 CEMS before and after controls or by using post

- control CEMS and acid production

rates. A limit of 4.06 lbs SO 2 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 co ntrol 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 technicall y feasible for the reduction of SO 2

.

Step 3

– Evaluate control effectiveness of remaining control technologies

Based on SO 2 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 SO 2 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 SO 2 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 ac id 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 s odium 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 v alues becau se of the uncertainty over how much SO 2 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 SO 2 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 SO 2

Reduced Capital

Cost Annual ized

Capital

Cost Annual

Variable

Cost Total

Annual

Cost $/ton SO 2

Removed

98% 5

- 10

- - $2,000,000 $2,000,000 $200,000

- $400,000

Factor 2: Energy Impacts

106 Lett er 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 SO 2 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

SO 2 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 r esults 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 improvem ents 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 SO 2 for the electric

furnace. While we would prefer to set a numeric emission limit in order to ensure that SO 2 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 un its in the vent fume stack. Therefore, cons istent 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 NO x

Step 1

– Identify all available technologies

We iden tified low

- NO

x 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 NO

x 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 NO

x 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 Li fe

We are not aware of any limits on the useful life of the project.

Factor 5: Visibility Impacts

The maximum modeled 98 th percentile visibility impact resulting from baseline NO

x emission s from the Miami Smelter is 0.1 1 dv. 109 Thus, the maximum visibilit y bene fit of controls is less

than 0.1 1 dv.

Step 5

– Select BART

Given the small potential for visibility improvement, we propose that controlling these NO

x 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.



### I V . Reasonable Progress Goals and Controls

I V .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 R egional H aze R ule 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 report

Asarco

- 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

ar e 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 publishe d on July 30, 2013 113 , we partially approved and partially disapproved certain elements of the State's reas onable progress (RP) analysis. In particular, we approved the State's decision to focus on NO X and SO 2 sources and not to require

additional controls o n point sources of SO 2 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 SO 2 and NO X and point sources of NO X

. 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 NO X analyses

and Area Source NO X and SO 2 analyses.



### I V

. B

. CalPortl and 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 (NO X ) 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 a nd 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 C ement 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 Ril lito 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 c omments”). 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 plant 115

. Figure 1 shows an aeri al 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 ir on. 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 soli d 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 informat ion 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 (NO X ), and sulfur dioxide (SO 2 ), 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 NO X and SO 2 emissions, as well as the majority of the particulate emissions, are generated from the kiln systems

. A negligible amount of NO X and SO 2 are generated fromPage 89 of 133

ancillary combustion equipment at the facility. Also, the tables show that the facility

- wide SO 2 emissions are minimal. CPCC does not have SO 2 emissions controls.

Table IV.B

- 2 : CalPortland Facility

- wide Pollutant Emissions

Year NO

x

(as NO 2 ) SO 2 PM PM 10 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 NO

x (as NO 2 ) SO 2 PM PM 10 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 faci lity, 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 NO X emissions from the kiln systems.

116 See EPA Air Pollution Control Cost Manual

- Sixth Edition

, Section 6 : Particulate Matter Controls, EPA/452/B

02

- 001, January 2002

.Page 90 of 133

Kilns 1, 2 and 3 are long kilns, and currently rely on good combustio n practices to control NO X emissions. Kiln 4 is a preheater/precalciner kiln. Preheater/precalciner kilns generally use

inherent low NO X design features. NO X emissions from Kiln 4 are controlled by low NOx burners with indirect firing and preheater riser d uct firing. Preheater riser duct firing is applicable to preheater/precalciner kilns. Table IV.B

- 4 summarizes the NO X emissions for Kilns 1

- 4.

Table IV.B

- 4 : Kilns 1

- 4 NO

x 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 NO X

Step 1

- Identify All Available Retrofit Control Technologies for NO X

NO X 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,

NO X is generated in both the burning zone of the kiln and the burning zone of a precalciner. Generally, coal generates less NO X than does oil or gas. 117

NO X 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 combu stion to minimize the amount of combustion that must occur at the maximum temperatures. The emphasis is on reducing

NO X formation.

 Post

- combustion or add

- on controls

- remove NO X that is formed in the combustion

process.

Process control modifications can minimize NO X emissions through improved fuel efficiency. These practices may be considered standard operating procedures. Combustion modifications

and add

- on controls actually reduce NO X formation. The available NO X controls technologies for

cement kilns are listed in Table IV.B

- 5.

117 See AP

- 42, Chapter 11.6, Por tland Cement Manufacturing, January 1995

.Page 91 of 133 Table IV.B

- 5 : NOx Control Options for Cement Kilns

Category Control Options

Combustion Modifications  Low NO X burner system (LNB)

 Low NO Xx 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 NO X Burners (LNB) These burners are designed to reduce flame turbulence, delay fuel/air mixing, and establish fuel

rich zones for initial combustion. Some cement kiln burners are equipped with LNBs. Many of these systems focus on lowering the NO X formation in the calciner by air or fuel staging, by reburning, or by high temperature c ombustion. This technology is technically feasible for Kilns

1

- 3. Kiln 4 already uses LNB technology with indirect firing.

Low NO X Calciner (LNC) Most of the major cement kiln suppliers now offer “low NO X ” calciner designs for new kilns. These designs ty pically 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 NO X and destroys a portion of the NO X formed in the kiln burning zone. This technology is no t 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 NO X 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 NO X formed upstream in the kiln burning zone. MKF may also produce additional fuel NO X 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 app lied to Kiln 4 because it already uses a form of mid

kiln 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 Mixi ng 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 NO X emissions from exhaust gases. In SCR, ammonia, usually diluted with air or steam, is injecte d through a grid system into hot flue gases which are then passed through a catalyst bed to carry out NO X reduction reactions. Catalysts that have been used include titanium dioxide, vanadium pentoxide,

and zeolite

- based materials. The catalyst is not cons umed 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 visibl e 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

sys tems 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 Stat es, 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 d emonstration was

conducted in 1997

– 1999, and commercial installation of a high dust SCR unit in 2000. NO X removal efficiency was typically in the range of 59

– 67 percent, and NO X removals of more than 80 percent have been observed. This facility achieved NO X reductions by using a combination of

a low NO X 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 NO X 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 Sarc he 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 "A lternative 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

w ith 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 NO X 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 kil n 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 NH 3 that oxidizes

to NO X increases, and, in turn, the NO X reduction performance deteriorates. At temperatures at or below 1,600°F, unreacted NH 3 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 preh eater tower are likely to be in the temperature window appropriate for SNCR. SNCR has been widely used for reducing NO X 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 : NO X Control Technologies and Potential Application 121

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 kiln

firing 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 NO X emissions for 2005 through

2010.

122 “ NO X 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 NO X 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 NO X emissions should be possible. 123 CalPortland’s NO X reduction estimate of 25 percent is within this range. Thus, this is a reas onable 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 th ese 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 NO X emissions.

CalPortland’s NO X reduction estimate of 20 percent is within this range. 124 Thu s, 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 a t implementing these controls on the two long dry kilns at its plant in Colton , California (Colton P lant ) 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 appl ications 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 appr opriate 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 NO X 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 challeng es, t here 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 P lant . Based on emissions data for the Colton Plant kilns, we

consider this estimate to be overly conservative and we find the use of a 3 0% control efficien cy 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 Ibi d 10

. 125 Ibid 10

.Page 95 of 133

that the emission data from the Mohave optimiza tion 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 wil l 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 te mperature, residence time, ammonia injection rates and patterns, and inlet NOx concentrations. E mission data and feasibility studies from the following control technology determinations, each involving a preheater/precalciner kiln operating with existing c ombustion 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/CDPHE

AP/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 infor mation 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. Baselin e 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 Effectiveness 127

NOx Control Option Ctrl Efficiency (%) NO X Reduction

(tpy) Remaining NO X 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 (%) NO X Reduction

(tons/year) Remaining NO X 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

- 1 1 show the cost estimates for Kilns 1

- 4 for the remaining NO X 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 esti mate s 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 Estimates 129

Control Option Ctrl Efficiency (%) NO X

Reduction (tpy) NO X 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 (%) NO X Reduction

(tpy) NO X 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 ins tallation 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 cap acity 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 use ful 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 gr aphs 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 mis

specified 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 2008Page 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 E mission Calculations 2014

- 01

- 24.xlsx ” provided to UN C 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 r uns used to assess the effect of NOx control s.

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 NO 2 by the time they reach there, as is assumed by CALPUFF. To explore this, EPA used daily extinction values from CALPOST, and reduced the NO 2 and

NO 3 extinction by fractions ranging from 10% to 75%, and then recomputed delta deciview impacts from the facili ty, 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 appl ied 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. Th erefore 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 NO X Control Option s, Visibility Impacts

Class I Ar ea 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 1.02Page 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 NO X Control Option s, 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 $1,0 4 7/ton (based on an economic li fe 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. I n 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 o ur review, we consider a 30% upward revision appropriate. As a result, we propose an emission limit of 2. 6 7 lb/ton based on a 30

- day rolling average, which isPage 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

NO X emissions in lieu of a lb/ton emission limit. Such a c ap 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 o f 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 deter mination of Reasonable Progress (RP) control options for control of nitrogen oxide (NO X ) emissions at the Phoenix Cement Plant , located in Clark dale, 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 vis ibility 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 Ce ment 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

P hoenix C ement C ompany (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. T he facility is located in Clark dale, 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, NO X , sulfur dioxide (SO 2 ), 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

activitie s such as material handling, rock crushing, paved and unpaved road traffic, and quarry drilling and blasting.

NO X and SO 2 emissions are generated from fossil fuel combustion in the kiln, quarry blasting, and natural gas combustion in the dryers. VOC emis sions 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 s ame 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 NO X and SO 2 concentrations

and emissions. PCC uses actual source test data and AP

- 42 emissions factors for determining
PM, PM 10 , and VOC emissions.

Table IV.C

- 1 : Facility

- wide Actual Emissions

Year NO

x

(tpy) SO 2

(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 NO

x

(tpy) SO 2

(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 NO X and SO 2 emissions are generated from Kiln 4. A negligible amount of NO X and SO 2 are generated from ancillary combustion equipment at the facility. Also, the above tables show that the facility

- wide SO 2 emissions are very small. SO 2 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.

P CC uses baghouses and dust colle ctors throughout its facility, including on Kiln 4 , to control particulate emissions. Baghouses and dust collectors are forms of fabric filters used forPage 103 of 133

controlling particulate emissions at efficiencies greater than 98 percent. 131 The plant also operates und er a dust control plan for controlling fugitive particulate emissions.

Since the facility is already well

- controlled for particulate emissions and SO 2 emissions are negligible, these pollutants are not being analyzed in this RP analysis. Therefore, this RP analysis only focuses on the control of NO X emissions from Kiln 4. Table IV.C

- 3 shows the

actual NO X emissions and production rates for Kiln 4 for 2005 to 2010.

Table IV.C

- 3 : NO X Emissions and Production Rates for Kiln 4

Year NO X Emissions

(tpy) Kiln Operation

(hrs/yr) Clinker

Production (tpy) NO X 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 NO X

Step 1

- Identify Available Retrofit Control Technologies for NO X

NO X 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,

NO X is generated in both the burning zone of the kiln and the burning zone of a precalciner.

NO X 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 product ivity.

 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 NO X formation.

 Post

- combustion or add

- on controls

- remove NO X that is formed in the combustion process.

Process control modifications can minimize NO X emissions through improved fuel efficiency. These practices may be considered standard operating procedures. Combustion modifications

and add

- on controls actually re duce NO X formation. The available NO X 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/B

02

- 001, January 2002

.Page 104 of 133 Table IV.C

- 4 : NO X Control Options for Cement Kilns

Category Control Options

Combustion Modifications  Low NO X burner system (LNB)

 Low NO X 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 NO X precalciner to minimize NO X 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 NO X , while the secondary combustion takes place in an oxygen

- rich, lower temperature zone for minimized thermal NO X formation.

The low NO X precalciner introduces the calciner fuel into an oxygen

- lean environment where initial combustion takes place and a signif icant amount of NO X 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 NO X reductions.

Step 2

- Eliminate Technically Infeasible Options

Combustion Modifications

Low NO X Burners (LNB) These burners are designed to reduce flame turbulence, delay fuel/air mixing, and establish fuel

rich zones for initial combustion. Some cement kiln burners are equipped with LNBs. Many of these systems focus on lowering the NO X formation in the calciner by air or fuel staging, by reburning, or by high temper ature 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 NO X ” 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 NO X and destroys a portion of the NO X formed in the kiln burning zone. Kiln 4 includes use of a low NO X precalciner which mi nimizes NO X 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, MKFPage 105 of 133

changes both the flame temperature and flame length. These changes may reduce thermal NO X forma tion 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 NO X formed upstream in the kiln burning zone. MKF may also produce additional fuel NO X depending up on 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

. T herefore, t his control method is n ot 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 efficienc y. MAT or LNC provides similar levels of NO X reductions. Kiln 4 includes use of a LNB with an indirect firing system , as well as a low NO X precalciner which minimizes NO X emissions. Therefore, use of MAT is not likely to result in significant additional NO X reductions.

Add

- On Controls

Selective Catalytic Reduction (SCR) This process uses ammonia in the presence of a catalyst to selectively reduce NO X 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 NO X 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 cata lysts 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 pa rticulate 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. NO X

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 NO X removals of more than

80 percent have been observed. This facility achieved NO X reductions by u sing a combination of

a low NO X 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 N O X 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, a lso 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 techni que relies on the reduction of NO X 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 th e 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 NO X 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 : NO X Control Technologies and Potential Application

NO X 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/CDPHE

AP/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 j ustifies a different control efficiency at the p lant, 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 i n 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 ove r 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 f or 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, u se 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 NO X 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 NO X 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

p rovided by PCC in instances where we considered PCC’s estimate s 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 NO X Control Options

Contro l Option Ctrl

Efficiency (%) NO X

Reduction (tpy) NO X 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. T he 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 as sociated 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 bel ieves 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 C larkdale 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 v isibility

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_resu lts .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 NO 2 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 NO 2 and NO 3 , EPA inverted the quadratic equation for daily extinction b

e xt as a function of concentration in the new IMPROVE equation to find the concentration. EPA then scaled the concentrations, assuming that NO 2 and

NO 3 concentrations reduce in proportion to the the NO 2 , Finally, EPA recomputed extinction

and delta decivie w 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 supp ort EPA’s proposed control. The full results of this analysis are in the spreadsheet
PhoenixCement_vis_NO2conv .xlsx

.

Table I V .C

- 9: Visibility Modeling of N O X Control Option s, 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 4.51Page 110 of 133 Number of areas >= 0.5 dv 4 1

Table IV.C

- 10 : Visibility Modeling of N O X Control Option s, 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 appropria te, 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

resu lt, 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 NO X 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 NO X

. However, as illustrated in Table IV.C

- 3 above, NO X 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 NO X emissions from Kiln 4 may vary over the nex t 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 (NO X ) emissions from Cholla Power Plant, Unit 1. The Cholla Power Plant is located near Joseph City, AZ and oper ated 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 contro l 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 andPage 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

NO X Low NO X burners (LNB) with Overfire

Air (OFA)

PM Fabric filter/baghouse

SO 2 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 NO X SO 2

(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 si gned 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 c urrent coal contract for these units indicates that the typical sulfur content of this coal is equivalent to

2.4 lb/MMBtu SO 2 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 calcula ting baseline emissions. Although this represents only a single year of emission data, we consider this to be a morePage 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 NO X

Step 1

– Identify all available technologies

Selective Non

- Catalytic Reduction (SNCR)

SNCR involves the non

- catalytic decomposition of NO X to nitrogen and water. A NO X 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 t emperature at the point of reagent injection can greatly affect NO X 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 NO X reduction reactions diminish and unreacted ammonia emissions increase. Above the desired temperature range, ammonia is oxidized to NO X resulting in low

NO X 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 NO 2 to molecular nitrogen, water, and oxygen. The catalyst lowers the temperature required for the chemical reaction

between NO X and the redu cing 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 catalys t 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 NO X control efficiencies range from 40% to 60%, depending on inlet NO X 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 NO X red uction rates are in the 50% range to limit ammonia slip to 10 ppm. Because Cholla Unit 1 already operates with NO X 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 co ntrol 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

e valuating 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: NO X Emission Estimates

Control Option NO X 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: NO X C ontrol 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 imp acts. 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 i mpacts, 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 NO X 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 affe ct 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 anhydrou s 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

no t 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 th at 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 1 16 of 133

for the 98th percentile in individual years, and for al ternative 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

(ctrl 1/c 21) SCR

( ctrl2 /c2 2 )

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 unit s 2, 3, and 4 ha ve 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 co st 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 elimin ating 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 consi deration 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 NO X control options achieves some degree of visibility improvement, neith er SCR nor SNCR is anticipated to achieve a large visibility benefit. As a result we are proposing no

additional controls for NO X during this planning period in light of the relatively small anticipated

vis ibility 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 (NO X ) emission s 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 facilit y

- 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 tangentiall y

- 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 Remai ning 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 CarolinaPage 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 o perate 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

NO X Low NO X burners (LNB) with Overfire Air

(OFA)

PM Fabric filter/baghouse

SO 2 Dry Flue Gas Desulfurization (DGD) Springerville Unit 2

NO X Low NO X burners (LNB) with Overfire Air

(OFA)

PM Fabric filter/baghouse

SO 2 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 NO X SO 2

(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 thePage 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 NO X

Step 1

– Identify all available technologies

Selective Non

- Catalytic Reduction (SNCR)

SNCR involves the non

- catalytic decomposition of NO X to nitrogen and water. A NO X 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 reactio n, temperatures of 1600

- 2100 degrees F are required. Flue gas temperature at the point of reagent injection can greatly affect NO X removal efficiencies and the quantity of ammonia or urea that will pass through the SNCR unreacted (referred to as ammonia sl ip). At temperatures below the desired operating range, the NO X reduction reactions diminish and unreacted ammonia emissions increase. Above the desired temperature range, ammonia is oxidized to NO X resulting in low

NO X reduction efficiencies.

Selective C atalytic 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 NO 2 to molecular nitrogen, water, and oxygen. The catalyst lowers the temperat ure required for the chemical reaction

between NO X 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 NO X co ntrol efficiencies range from 40% to 60%, depending on inlet NO X concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of

inte rfering chemical substances in the gas stream. Guaranteed NO X reduction rates are in the 50% range to limit ammonia slip to 10 ppm. Because Springerville 1 and 2 already operate with

NO X combustion controls, we have used an SNCR control efficiency of 30% f rom 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 m id

- 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 ach ieved 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 efficienc ies 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: NO X Emission Estimates

Control Option NO X 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: NO X 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

Springerv ille 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 materia ls, 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. Howe ver, other NO X 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 scal e 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 facilit ies 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 anhydro us 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 war rant 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 F ederal 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,

an d 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

(ctrl 1 /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 $53.4Page 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 potent ial 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 c ompliance 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 approxima tely $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 eac h 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

thi s planning period. Therefore, we are proposing no additional controls for NO X 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 co ntrol of nitrogen oxide (NO X ) 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 Doc ument 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, CalPor tland 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 calculation s)

 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, S undt Units 1

- 3 do not operate with any pollution control technology for NO X , SO 2 ,

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 SO 2 NO X

(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 3Page 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 g eneration and

emission rates for Sundt I1

- 3 do not differ significantly from the 2008

- 10 period.

IV.F.3. RP Analysis for NO X

Step 1

– Identify all available technologies

Selective Non

- Catalytic Reduction (SNCR)

SNCR involves the non

- catalytic decomposition of NO X to nitrogen and water. A NO X 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 driv e the reaction, temperatures of 1600

- 2100 degrees F are required. Flue gas temperature at the point of reagent injection can greatly affect NO X 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 NO X reduction reactions diminish and unreacted ammonia emissions increase. Above the desired temperature range, ammonia is oxidized to NO X resulting in low

NO X 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 cataly st to selectively reduce NO and NO 2 to molecular nitrogen, water, and oxygen. The catalyst lowers the temperature required for the chemical reaction

between NO X and the reducing agent. Technical factors that impact the effectiveness of this technology incl ude 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 optionsPage 126 of 133

ULNB, SNCR and SCR have been demonstra ted 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 cont rol effectiveness of remaining control technologies

Selective Non

- Catalytic Reduction (SNCR) Typical NO X control efficiencies range from 40% to 60%, depending on inlet NO X 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 SNC R 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.

Ult ra 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, o ur contractor used a design emission rate of 0.0 3 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 ar e based upon

the control effectiveness descr ibed in Step 3 above, and on annual capacity factors calculated

from data reported to EPA's CAMD.

Table IV.F

- 2: NO X Emission Estimates

Control Option NO X 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 46Page 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: NO X 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

Baseli ne

-- -- -- -- -- -- 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 rulePage 128 of 133

Factor 3: Energy and non

- a ir 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 impa cts. 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 im pacts, 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 i ntegrity of the use of fly ash in concrete. However, other NO X 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 affec t 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 c onclude 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 boiler s , and have

assu med 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

(ctrl 1/c 21 and

ctrl2 /c2 2)

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 u nit 4 having SNCR are interpolated between results hav ing unit 4 at base (LNB

, UNC’s Ctrl2

- 2 or c2 2

, CALPUFF ctrl 2 ) and unit 4 having SCR ( UNC’s Ctrl2

- 1 or c2 1 , 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 cos t 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 SC R 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 improveme nt fromPage 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 0.4 0 dv.

We are proposing no additional controls for NO X 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 NO X 

### and SO 2

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 alth ough 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 us ed 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 se t. 141

In EPA’s action on the Arizona Regional Haze SIP, we approved the St ate’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 NO X and SO 2 . These sources comp rise 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 A rizona 2002

- 2018 142

Category SO 2 [tpy] NO X [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 en sure 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.

EP A 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 prep ared every three years by the EPA based primarily upon emission estimates and emission m odel inputs provided by State, Local, and Tribal air agencies for sources in their jurisdictions, and suppleme nted 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 SO 2 and NO X 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

SO 2 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%

NO X 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 SO 2 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 knowledge able 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 err or and eliminated this source category from

further consideration. 144 No other top SO 2 sources required corrections.

The top two NO X area source categories also had data quality issues: d istillate combustion

industrial boilers and IC engines (SCC: 2102004000 ) and d istillate 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 Ari zona. 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 MCAQ D 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 est imates 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 d istillate

combustion commercial boilers a nd IC engines (SCC: 2103004000 ) in Maricopa County dropped from 3,273 tpy of NO X to 3.7 tpy of NO X . 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 e stimated emissions from d istillate 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 Regi on 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 Tabl e 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

ADE Q 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 c ontrol 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 documen tation 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.