[Federal Register Volume 79, Number 32 (Tuesday, February 18, 2014)]
[Proposed Rules]
[Pages 9317-9378]
[FR Doc No: 2014-02714]

Vol. 79

Tuesday,

No. 32

February 18, 2014

Part II

Environmental Protection Agency

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40 CFR Part 51

Promulgation of Air Quality Implementation Plans; Arizona; Regional
Haze and Interstate Visibility Transport Federal Implementation Plan;
Proposed Rule

Federal Register / Vol. 79 , No. 32 / Tuesday, February 18, 2014 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 51

[EPA-R09-OAR-2013-0588, FRL-9906-30-Region 9]

Promulgation of Air Quality Implementation Plans; Arizona;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This proposed Federal Implementation Plan (FIP) addresses the
requirements of the Regional Haze Rule (RHR) and interstate visibility
transport for the disapproved portions of Arizona's Regional Haze (RH)
State Implementation Plan (SIP) as described in our final rule
published on July 30, 2013. Our final rule on Arizona's RH SIP
partially approved and partially disapproved the State's plan to
implement the regional haze program for the first planning period.
Today's proposed rule addresses the RHR's requirements for Best
Available Retrofit Technology (BART), Reasonable Progress Goals (RPGs)
and Long-term Strategy (LTS) as well as the interstate visibility
transport requirements for pollutants that affect visibility in
Arizona's 12 Class I areas as well as areas in nearby states. The BART
sources addressed in this proposed FIP are Tucson Electric Power (TEP)
Sundt Generating Station Unit 4, Lhoist Nelson Lime Plant Kilns 1 and
2, ASARCO Incorporated Hayden Smelter, and Freeport-McMoran Inc. (FMMI)
Miami Smelter. The sources with proposed controls for reasonable
progress are the Phoenix Cement Clarkdale Plant and the CalPortland
Cement Rillito Plant.

DATES: Written comments must be submitted to the designated contact at
the address in the General Information section of SUPPLEMENTARY
INFORMATION on or before March 31, 2014.

ADDRESSES: See the General Information section of SUPPLEMENTARY
INFORMATION for further instructions on where and how to learn more
about this proposal, attend a public hearing, or submit comments.

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9,
Planning Office, Air Division, Air, 75 Hawthorne Street, San Francisco,
CA 94105. Thomas Webb may be reached at telephone number<PHONE_NUMBER>
and via electronic mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

I. General Information
    A. Definitions
    B. Docket
    C. Instructions for Submitting Comments to EPA
    D. Submitting Confidential Business Information
    E. Tips for Preparing Your Comments
    F. Public Hearings
II. Proposed Actions Background and Overview
    A. Background
    B. Regional Haze
    C. Interstate Transport of Pollutants That Affect Visibility
III. Review of State and EPA Actions on Regional Haze
    A. EPA's Schedule To Act on Arizona's RH SIP
    B. History of State Submittals and EPA Actions
    C. EPA's Authority To Promulgate a FIP
IV. EPA's BART Process
    A. BART Factors
    B. Visibility Analysis
    C. Explanation of Visibility Tables
V. EPA's Proposed BART Analyses and Determinations
    A. Sundt Generating Station Unit 4
    B. Nelson Lime Plant Kilns 1 and 2
    C. Hayden Smelter
    D. Miami Smelter
VI. EPA's Proposed Reasonable Progress Analyses and Determinations
    A. Reasonable Progress Analysis of Point Sources for
NOX
    B. Reasonable Progress Analysis of Area Sources for
NOX and SO2
    C. Reasonable Progress Goals
    D. Meeting the Uniform Rate of Progress
VII. EPA's Proposed Long-Term Strategy Supplement
    A. Emission Reductions for Out-of-State Class I Areas
    B. Emissions Limitations and Schedules for Compliance To Achieve
RPGs
    C. Enforceability of Emissions Limitations and Control Measures
    D. Proposed Partial LTS FIP
VIII. EPA's Proposal for Interstate Transport
IX. Summary of Proposed Actions
    A. Regional Haze
    B. Interstate Transport
X. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act

I. General Information

A. Definitions

    (1) The words or initials Act or CAA mean or refer to the Clean Air
Act, unless the context indicates otherwise.
    (2) The initials ADEQ mean or refer to the Arizona Department of
Environmental Quality.
    (3) The words Arizona and State mean the State of Arizona.
    (4) The initials BACT mean or refer to Best Available Control
Technology.
    (5) The initials BART mean or refer to Best Available Retrofit
Technology.
    (6) The initials BOD mean or refer to boiler operating day.
    (7) The term Class I area refers to a mandatory Class I Federal
area.
    (8) The initials CEMS refers to continuous emission monitoring
system or systems.
    (9) The initials dv mean or refer to deciview, a measure of visual
range.
    (10) The words EPA, we, us or our mean or refer to the United
States Environmental Protection Agency.
    (11) The initials FGD mean or refer to flue gas desulfurization.
    (12) The initials FIP mean or refer to Federal Implementation Plan.
    (13) The initials FLM mean or refer to Federal Land Managers.
    (14) The initials IMPROVE mean or refer to Interagency Monitoring
of Protected Visual Environments monitoring network.
    (15) The initials IPM mean or refer to Integrated Planning Model.
    (16) The initials lb/MMBtu mean or refer to pounds per one million
British thermal units.
    (17) The initials LDSCR and HDSCR mean or refer to low and high
dust Selective Catalytic Reduction, respectively.
    (18) The initials LNB mean or refer to low NOX burners.
    (19) The initials LTS mean or refer to Long-term Strategy.
    (20) The initials MACT mean or refer to Maximum Achievable Control
Technology.
    (21) The initials MW mean or refer to megawatts.
    (22) The initials NAAQS mean or refer to National Ambient Air
Quality Standards.
    (23) The initials NEI mean or refer to National Emissions
Inventory.
    (24) The initials NESCAUM mean or refer to Northeast States for
Coordinated Air Use Management.
    (25) The initials NM mean or refer to National Monument.
    (26) The initials NOX mean or refer to nitrogen oxides.

    (27) The initials NP mean or refer to National Park.
    (28) The initials NPS mean or refer to the National Park Service.
    (29) The initials NSCR mean or refer to non-selective catalytic
reduction.
    (30) The initials NSPS mean or refer to new source performance
standards.
    (31) The initials PM mean or refer to particulate matter.
    (32) The initials PM2.5 mean or refer to fine particulate matter
with an aerodynamic diameter of less than 2.5 micrometers.
    (33) The initials PM10 mean or refer to particulate matter with an
aerodynamic diameter of less than 10 micrometers.
    (34) The initials PSAT mean or refer to Particulate Source
Apportionment Technology.
    (35) The initials PSD mean or refer to Prevention of Significant
Deterioration.
    (36) The initials PTE mean or refer to potential to emit.
    (37) The initials RH mean or refer to regional haze.
    (38) The initials RHR mean or refer to the Regional Haze Rule,
originally promulgated in 1999 and codified at 40 CFR 51.301-309.
    (39) The initials RMC mean or refer to Regional Modeling Center.
    (40) The initials RP mean or refer to Reasonable Progress.
    (41) The initials RPG or RPGs mean or refer to Reasonable Progress
Goal(s).
    (42) The initials SCR mean or refer to Selective Catalytic
Reduction.
    (43) The initials SIP mean or refer to State Implementation Plan.
    (44) The initials SNCR mean or refer to Selective Non-catalytic
Reduction.
    (45) The initials SO2 mean or refer to sulfur dioxide.
    (46) The initials SOFA mean or refer to Separated Overfire Air.
    (47) The initials SRP mean or refer to Salt River Project
Agricultural Improvement and Power District.
    (48) The initials tpy mean tons per year.
    (49) The initials TSD mean or refer to Technical Support Document.
    (50) The initials TSF mean or refer to tons of stone feed.
    (51) The initials ULNB mean or refer to ultra-low NOX
burners.
    (52) The initials URP mean or refer to Uniform Rate of Progress.
    (53) The initials VOC mean or refer to volatile organic compounds.
    (54) The initials WRAP mean or refer to the Western Regional Air
Partnership.

 B. Docket

    This proposed action relies on documents, information and data that
are listed in the index on http://www.regulations.gov under docket
number EPA-R09-OAR-2013-0588. Previous proposed and final actions
regarding Arizona's RH SIP are under docket number EPA-R09-OAR-2012-
0904 and EPA-R09-OAR-2012-0021. Although listed in the index, some
information is not publicly available (e.g., Confidential Business
Information (CBI)). Certain other material, such as copyrighted
material, is publicly available only in hard copy form. Publicly
available docket materials are available either electronically at
http://www.regulations.gov or in hard copy at the Planning Office of
the Air Division, AIR-2, EPA Region 9, 75 Hawthorne Street, San
Francisco, CA 94105. EPA requests that you contact the individual
listed in the FOR FURTHER INFORMATION CONTACT section to view the hard
copy of the docket. You may view the hard copy of the docket Monday
through Friday, 9-5 PST, excluding Federal holidays.

C. Instructions for Submitting Comments to EPA

    Written comments must be submitted on or before March 31, 2014.
Submit your comments, identified by Docket ID No. EPA-R09-OAR-2013-
0588, by one of the following methods:
     Federal Rulemaking portal: http://www.regulations.gov.
Follow the on-line instructions for submitting comments.
     Email<EMAIL_ADDRESS>     Fax:<PHONE_NUMBER> (Attention: Thomas Webb).
     Mail, Hand Delivery or Courier: Thomas Webb, EPA Region 9,
Air Division (AIR-2), 75 Hawthorne Street, San Francisco, California
94105. Hand and courier deliveries are only accepted Monday through
Friday, 8:30 a.m. to 4:30 p.m., excluding Federal holidays. Special
arrangements should be made for deliveries of boxed information.
    EPA's policy is to include all comments received in the public
docket without change.

We may make comments available online at http://www.regulations.gov,
including any personal information provided, unless the comment
includes information claimed to be CBI or other information for which
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or that is otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an email comment directly to EPA, without
going through http://www.regulations.gov, we will include your email
address as part of the comment that is placed in the public docket and
made available on the Internet. If you submit an electronic comment,
EPA recommends that you include your name and other contact information
in the body of your comment and with any disk or CD-ROM you submit. If
EPA cannot read your comment due to technical difficulties and cannot
contact you for clarification, EPA may not be able to consider your
comment. Electronic files should not include special characters or any
form of encryption, and be free of any defects or viruses.

D. Submitting Confidential Business Information

    Do not submit CBI to EPA through http://www.regulations.gov or
email. Clearly mark the part or all of the information that you claim
as CBI. For CBI information in a disk or CD ROM that you mail to EPA,
mark the outside of the disk or CD ROM as CBI and identify
electronically within the disk or CD ROM the specific information that
is claimed as CBI. In addition to one complete version of the comment
that includes information claimed as CBI, you must submit a copy of the
comment that does not contain the information claimed as CBI for
inclusion in the public docket. We will not disclose information so
marked except in accordance with procedures set forth in 40 CFR part 2.

 E. Tips for Preparing Comments

    When submitting comments, remember to:
     Identify the rulemaking by docket number and other
identifying information (e.g., subject heading, Federal Register date
and page number).
     Explain why you agree or disagree; suggest alternatives
and substitute language for your requested changes.
     Describe any assumptions and provide any technical
information and/or data that you used.
     If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
     Provide specific examples to illustrate your concerns, and
suggest alternatives.
     Explain your views as clearly as possible, avoiding
profanity or personal threats.
     Make sure to submit your comments by the identified
comment period deadline.
    To provide opportunities for questions and discussion, EPA will
hold an open house prior to the public hearing. During the open house,
EPA staff will be available informally to

answer questions on our proposed rule. Any comments made to EPA staff
during the open house must still be provided formally in writing or
orally during a public hearing to be considered in the record. The open
house and public hearing schedule is as follows.

 F. Public Hearings

    EPA will hold two public hearings at the dates, times and locations
stated below to accept oral and written comments into the record. To
request interpretation services or to request reasonable accommodation
for a disability, please contact the person in the FOR FURTHER
INFORMATION CONTACT section by February 14, 2014.
    Public Hearing in Phoenix:
    Date: February 25, 2014.
    Open House: 4-5 p.m.
    Public Hearing: 6-8 p.m.
    Location: Phoenix Convention Center, Rooms 150-153, 33 South 3rd
Street, Phoenix, Arizona 85004.
    Public Hearing in Tucson:
    Date: February 26, 2014.
    Open House: 4-5 p.m.
    Public Hearing: 6-8 p.m.
    Location: Tucson High Magnet School, Auditorium, 400 North 2nd
Avenue, Tucson, Arizona 85705.
    The public hearing will provide the public with an opportunity to
present views or information concerning the proposed RH FIP for
Arizona. EPA may ask clarifying questions during the oral
presentations, but will not respond to the presentations at that time.
We will consider written statements and supporting information
submitted during the comment period with the same weight as any oral
comments and supporting information presented at the public hearing.
Please consult section I.C, I.D and I.E of this preamble for guidance
on how to submit written comments to EPA. We will include verbatim
transcripts of the hearing in the docket for this action. The EPA
Region 9 Web site for the rulemaking, which includes the proposal and
information about the public hearing, is at http://www.epa.gov/region9/air/actions.

II. Proposed Actions Background and Overview

A. Background

    The Clean Air Act (CAA) establishes as a national goal the
prevention of any future, and the remedying of any existing man-made
impairment of visibility in 156 national parks and wilderness areas
designated as Class I areas. Arizona has a wealth of such areas. The
sources addressed in this FIP affect many Class I areas in the State of
Arizona and adjacent states. This FIP will ensure that progress is made
toward natural visibility conditions at these national treasures, as
Congress intended when it directed EPA to improve visibility in
national parks and wilderness areas. Please refer to our previous
rulemaking on the Arizona RH SIP for additional background regarding
the CAA, regional haze and EPA's RHR.\1\
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    \1\ 77 FR 75704, 75707-75702 (December 21, 2012).
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B. Regional Haze

    We propose to promulgate a FIP as described in this notice and
summarized in this section to address those portions of Arizona's RH
SIP that we disapproved on July 30, 2013.\2\ We disapproved in part
Arizona's BART control analyses and determinations for four sources,
Reasonable Progress Goal (RPG) analyses and determinations, and Long-
term Strategy (LTS) for making reasonable progress. The proposed FIP
includes emission limits, compliance schedules and requirements for
equipment maintenance, monitoring, testing, recordkeeping and reporting
for all affected sources and units. The regulatory language for the
proposed FIP requirements is under Part 52 at the end of this notice.
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    \2\ 78 FR 46142.
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 1. Proposed BART Determinations
    EPA conducted 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 results of our BART evaluations
are summarized here for each source and are shown in Table 1. We are
seeking comments on our proposals.
    Sundt: We propose that Sundt Unit 4 is BART-eligible and subject to
BART for sulfur dioxide (SO2), nitrogen oxides
(NOX) and particulate matter with aerodynamic diameter less
than 10 micrometers (PM10). For NOX, we propose
an emission limit of 0.36 lb/MMBtu as BART based upon an annual
capacity factor of 0.49, which is consistent with the use of Selective
Non-Catalytic Reduction (SNCR) as a control technology. For
SO2, we propose an emission limit of 0.23 lb/MMBtu as BART
on a 30-day boiler operating day (BOD) rolling basis, which is
consistent with dry sorbent injection (DSI) as a control technology.
For PM10, we propose a filterable PM10 emission
limit of 0.030 lb/MMBtu as BART based on the use of the existing fabric
filter baghouse. We also are proposing a switch to natural gas as a
better-than-BART alternative to the other proposed controls for all
three pollutants.
    Nelson Lime Plant: We propose that Nelson Lime Kilns 1 and 2 are
subject to BART for NOX, SO2 and PM10.
For NOX, we propose a BART emission limit at Kiln 1 of 3.80
lb/ton lime and at Kiln 2 of 2.61 lb/ton lime on a 30-day rolling basis
as verified by continuous emission monitoring systems (CEMS). This
emission limit is consistent with the use of low-NOX burners
(LNB) and SNCR as control technologies. We propose that BART for
SO2 is an emission limit of 9.32 lb/ton for Kiln 1 and 9.73
lb/ton for Kiln 2 on a 30-day rolling basis, which is consistent with
the use of a lower sulfur fuel blend. For PM10, we propose a
BART emission limit of 0.12 lb/tons of stone feed (TSF) to control
PM10 at Kilns 1 and 2 based on the use of the existing
fabric filter baghouses. This level of control is commensurate with the
MACT standard that applies to this source.
    Hayden Smelter: We propose that the Hayden Smelter is subject to
BART for NOX, and propose BART emission limits for
NOX and SO2. EPA previously approved the State's
determination that the Hayden Smelter is subject to BART for
SO2. For NOX, we propose to find that controlling
emissions from the converters and anode furnaces is cost-effective, but
would not result in sufficient visibility improvement to warrant the
cost. Therefore, we are proposing an annual emission limit of 40 tpy
NOX emissions from the BART-eligible units, which is
consistent with current emissions from these units. For SO2
from the converters, we propose a BART control efficiency of 99.8
percent on a 30-day rolling basis on all SO2 captured by
primary and secondary control systems, which can be achieved with a new
double contact acid plant. For SO2 from the anode furnaces,
we propose to find that controlling the 37 tons per year (tpy) of
SO2 emissions from these furnaces, while cost-effective, is
not warranted as BART given the potential for only minimal visibility
improvement. We propose as an emission limitation for the anode furnace
a work practice standard requiring that the furnaces only be charged
with blister copper or higher purity copper. We previously approved
Arizona's determination that BART for PM10 at the Hayden
Smelter is no additional controls. In order to ensure the
enforceability of this determination, we are proposing to incorporate
emission limitations and associated compliance requirements from the
National Emission Standard for Hazardous Air Pollutants (NESHAP) for

Primary Copper Smelting at 40 CFR Part 63, Subpart QQQ, as part of the
LTS.
    Miami Smelter: EPA proposes that the Miami Smelter is subject to
BART for NOX, and proposes BART emission limits for
NOX and SO2. EPA previously approved the State's
determination that the Miami Smelter is subject to BART for
SO2. For NOX, we propose to find that controlling
the small amount of emissions from the converters and electric furnace
is cost-effective, but would not result in sufficient visibility
improvement to warrant the cost. Therefore, we are proposing an annual
emission limit of 40 tpy NOX emissions from the BART-
eligible units, which is consistent with current emissions. For
SO2 from the converters, we propose a BART control
efficiency of 99.7 percent on a 30-day rolling basis on all
SO2 emissions captured by the primary and secondary control
systems as verified by CEMS. This control efficiency could be met
through improvements to the primary capture system, construction of a
secondary capture system, and application of the MACT QQQ standards to
the capture systems. For SO2 emissions from the electric
furnace, we propose as BART the work practice standard to prohibit
active aeration. We previously approved Arizona's determination that
BART for PM10 at the Miami Smelter is the NESHAP for Primary
Copper Smelting. We now propose to find that the federally enforceable
provisions of the NESHAP, which apply to the Miami Smelter and are
incorporated into its Title V Permit, are sufficient to ensure the
enforceability of this determination.

                                                    Table 1--Proposed Emission Limits on BART Sources
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                                                                                Corresponding control
               Source                          Units                  Pollutants           Limit             Measure                  technology
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Sundt Generating Station............  Unit 4.................  NOX....................         0.36  lb/MMBtu..............  Selective Non-Catalytic
                                                               SO2....................         0.23                           Reduction.
                                                               PM10...................        0.030                          Dry Sorbent Injection.
                                                                                Fabric filter baghouse
                                                                                (existing).
                                      Unit 4 (Alternative)...  NOX....................         0.25  lb/MMBtu..............  Switch to natural gas.
                                                               SO2....................      0.00064
                                                               PM10...................        0.010
Chemical Lime Nelson................  Kiln 1.................  NOX....................         3.80  lb/ton feed...........  Selective Non-Catalytic
                                                               SO2....................         9.32                           Reduction.
                                                               PM10...................         0.12                          Lower sulfur fuel.
                                                                                Fabric filter baghouse
                                                                                (existing).
                                      Kiln 2.................  NOX....................         2.61  ......................  Selective Non-Catalytic
                                                               SO2....................         9.73                           Reduction.
                                                               PM10...................         0.12                          Lower sulfur fuel.
                                                                                Fabric filter baghouse
                                                                                (existing).
Hayden Smelter......................  Converters 1, 3-5......  NOX....................           40  tpy...................  None.
                                                               SO2....................         99.8  Control efficiency....  New double contact acid
                                                                                plant.
                                      Anode Furnaces 1, 2....  SO2....................         None  None..................  Work practice standard.
Miami Smelter.......................  Converters 2-5.........  NOX....................           40  tpy...................  None.
                                                               SO2....................         99.7  Control efficiency....  Improve primary and new
                                                                                secondary capture systems.
                                      Electric Furnace.......  SO2....................         None  None..................  Work practice standard.
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2. Proposed RP Determinations
    Point Sources of NOX: EPA conducted an extensive RP analysis of
NOX point sources that resulted in proposed determinations
for nine sources and proposed controls on two sources as shown in Table
2. We are proposing an emissions limit of 2.12 lb/ton on Kiln 4 of the
Phoenix Cement Clarkdale Plant based on a 30-day rolling average, which
is consistent with SNCR as a control technology. We are proposing an
emissions limit of 2.67 lb/ton on Kiln 4 of the CalPortland Cement
Rillito Plant based on a 30-day rolling average, which also is
consistent with SNCR control technology. We are also taking comment on
the possibility of requiring a rolling 12-month cap on NOX
emissions in lieu of a lb/ton emission limit. For Phoenix Cement, this
cap would be 947 tpy and apply to Kiln 4. For CalPortland, this cap
would be 2,082 tpy and apply to Kilns 1-4.

                                                     Table 2--Proposed Emission Limits on RP Sources
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             Source                     Units            Pollutants         Limit           Measure              Corresponding control technology
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Phoenix Cement.................  Kiln 4............  NOX...............         2.12  lb/ton............  Selective Non-Catalytic Reduction.
CalPortland Cement.............  Kiln 4............  NOX...............         2.67  lb/ton............  Selective Non-Catalytic Reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Area Sources of NOX and SO2: We propose to find that it is
reasonable not to require additional controls on these sources at this
time. Primarily, these area source categories are distillate fuel oil
combustion in industrial and commercial boilers and in internal
combustion engines, and residential natural gas combustion. The State's
area sources, which currently contribute a relatively small percentage
of the visibility impairment at impacted Class I areas, would benefit
from better emission inventories and an improved RP analysis in the
next planning period.
    Reasonable Progress Goals: EPA is proposing RPGs consistent with a
combination of control measures that include those in the approved
Arizona RH SIP as well as the approved and proposed Arizona RH FIP.
While not quantifying a new set of RPGs based on these control
measures, we propose that it is reasonable to assume improved levels of
visibility at Arizona's 12 Class I areas by 2018 since the measures in
the FIP are significantly beyond what was in the State's plan.
    Demonstration of Reasonable Progress: EPA proposes to find that it
is not reasonable to provide for rates of progress at the 12 Class I
areas consistent with the uniform rate of progress (URP) in this
planning period.\3\ Given the variety and location of sources
contributing to visibility impairment in Arizona, EPA considers

it unlikely that Arizona's Class I areas will meet the URP in 2018. We
propose to find that the RP analyses underlying our actions on the
Arizona SIP \4\ and in this proposal are sufficient to demonstrate that
it is not reasonable to provide for rates of progress in this planning
period that would attain natural conditions by 2064.\5\ This is
consistent with our proposed and final rules on the Arizona RH SIP in
which we approved Arizona's determinations that it is not reasonable to
require additional controls to address organic carbon, elemental
carbon, coarse mass and fine soil during this planning period.\6\ We
also approved the State's decision not to require additional controls
(i.e., controls beyond what the State or we determine to be BART) on
point sources of SO2.\7\
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    \3\ 40 CFR 51.308(d)(1)(ii).
    \4\ See proposed actions at 77 FR 75727-75730, 78 FR 29297-
292300 and final action at 78 FR 46172.
    \5\ 40 CFR 51.308(d)(1)(ii).
    \6\ See 77 FR 75728 for a discussion on sources of organic
carbon and elemental carbon (fires), and 78 FR 29297-29299 for a
discussion of coarse mass and fine soil.
    \7\ 78 FR 46172.
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 3. Long-Term Strategy Proposal
    EPA proposes to find that provisions in today's proposal in
combination with provisions in the approved Arizona SIP and FIP \8\
fulfill the requirements of 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F).
These requirements are to include in the LTS measures needed to achieve
emission reductions for out-of-state Class I areas, emissions
limitations and schedules for compliance to achieve the reasonable
progress goals, and enforceability of emissions limitations and control
measures.\9\ In today's notice we propose to promulgate emission
limits, compliance schedules and other requirements for four BART
sources and two RP sources to complete the actions taken in our
previous final rule to address these requirements.
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    \8\ 77 FR 75512-72580, December 5, 2012.
    \9\ See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)).
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C. Interstate Transport of Pollutants That Affect Visibility

    We propose that a combination of SIP and FIP measures will satisfy
the FIP obligation for the visibility requirement of CAA section
110(a)(2)(D)(i)(II) for the 1997 8-hour ozone, 1997 PM2.5,
and 2006 PM2.5 NAAQS. CAA section 110(a)(2)(D)(i)(II)
requires that all SIPs contain adequate provisions to prohibit
emissions that will interfere with other states' required measures to
protect visibility. We refer to this requirement herein as the
interstate transport visibility requirement. ADEQ submitted SIP
revisions to address this requirement in 2007 for the 1997 8-hour ozone
NAAQS \10\ and 1997 PM2.5 NAAQS \11\ (2007 Transport SIP)
\12\ and in 2009 for the 2006 PM2.5 NAAQS \13\ (2009
Transport SIP).\14\ Each of these SIP revisions indicated that it is
appropriate to assess Arizona's interference with other states'
measures to protect visibility in conjunction with the State's RH
SIP.\15\ In our final rule published on July 30, 2013, EPA disapproved
these SIP submittals with respect to the interstate transport
visibility requirement, triggering the obligation for EPA to promulgate
a FIP to address this requirement.\16\ Accordingly, today's notice
describes our proposed FIP for the interstate transport visibility
requirement for the 1997 8-hour ozone, 1997 PM2.5, and 2006
PM2.5 NAAQS.
---------------------------------------------------------------------------

    \10\ 62 FR 38856, July 18, 1997.
    \11\ 62 FR 38652, July 18, 1997.
    \12\ ``Revision to the Arizona State Implementation Plan Under
Clean Air Act Section 110(a)(2)(D)(i)--Regional Transport,''
submitted by ADEQ on May 24, 2007.
    \13\ 71 FR 61144, October 17, 2006.
    \14\ ``Arizona State Implementation Plan Revision under Clean
Air Act Section 110(a)(1) and (2); 2006 PM2.5 NAAQS, 1997
PM2.5 NAAQS, and 1997 8-hour Ozone NAAQS,'' submitted by
ADEQ on October 14, 2009, which addressed the requirements of
section 110(a)(2)(D)(i) with respect to the 2006 PM2.5
NAAQS in Section 2.4 and Appendix B of the submittal.
    \15\ This concept is also presented in EPA's 2006 guidance memo
on interstate transport, which recommended that states make a
submission indicating that it was premature, at that time, to
determine whether there would be any interference with other states'
required measures to protect visibility until the submission and
approval of regional haze SIPs. See ``Guidance for State
Implementation Plan (SIP) Submissions to Meet Current Outstanding
Obligations Under Section 110(a)(2)(D)(i) for the [1997] 8-Hour
Ozone and PM2.5 National Ambient Air Quality Standards,''
August 15, 2006.
    \16\ 78 FR 46142, July 30, 2013.
---------------------------------------------------------------------------

III. Review of State and EPA Actions on Regional Haze

 A. EPA's Schedule To Act on Arizona's RH SIP

    EPA received a notice of intent to sue in January 2011 stating that
we had not met the statutory deadline for promulgating RH FIPs and/or
approving RH SIPs for dozens of states, including Arizona. This notice
was followed by a lawsuit filed by several advocacy groups (Plaintiffs)
in August 2011.\17\ In order to resolve this lawsuit and avoid
litigation, EPA entered into a Consent Decree with the Plaintiffs,
which sets deadlines for action for all of the states covered by the
lawsuit, including Arizona. This decree was entered and later amended
by the United States District Court for the District of Columbia over
the opposition of Arizona.\18\ Under the terms of the Consent Decree,
as amended, EPA is currently subject to three sets of deadlines for
taking action on Arizona's RH SIP as listed in Table 3.\19\
---------------------------------------------------------------------------

    \17\ National Parks Conservation Association v. Jackson (D.D.C.
Case 1:11-cv-01548).
    \18\ National Parks Conservation Association v. Jackson (D.D.C.
Case 1:11-cv-01548), Memorandum Order and Opinion (May 25, 2012),
Minute Order (July 2, 2012), Minute Order (November 13, 2012) and
Minute Order (February 15, 2013).
    \19\ Id.

                      Table 3--Consent Decree Deadlines for EPA To Act on Arizona's RH SIP
----------------------------------------------------------------------------------------------------------------
              EPA actions                          Proposed rule                          Final rule
----------------------------------------------------------------------------------------------------------------
Phase 1--BART determinations for        July 2, 2012 \1\...................  November 15, 2012.\2\
 Apache, Cholla and Coronado.
Phase 2--All remaining elements of the  December 8, 2012 \3\...............  July 15, 2013.\4\
 Arizona RH SIP.
Phase 3--FIP for disapproved elements   January 27, 2014...................  June 27, 2014.
 of the Arizona RH SIP.
----------------------------------------------------------------------------------------------------------------
\1\ Published in the Federal Register on July 20, 2012, 77 FR 42834.
\2\ Published in the Federal Register on December 5, 2012, 77 FR 72512.
\3\ Published in the Federal Register on December 21, 2012, 77 FR 75704.
\4\ Published in the Federal Register on July 30, 2013, 78 FR 46142.

 B. History of State Submittals and EPA Actions

    Because four of Arizona's 12 mandatory Class I Federal areas are on
the Colorado Plateau, the State had the option of submitting a RH SIP
under CAA section 309 of the RHR. A SIP that is approved by EPA as
meeting all of the requirements of section 309 is ``deemed to comply
with the requirements for reasonable progress with respect to the 16
Class I areas [on the Colorado

Plateau] for the period from approval of the plan through 2018.'' \20\
When these regulations were first promulgated, 309 SIPs were due no
later than December 31, 2003. Accordingly, ADEQ submitted to EPA on
December 23, 2003, a 309 SIP for Arizona's four Class I Areas on the
Colorado Plateau. ADEQ submitted a revision to its 309 SIP, consisting
of rules on emissions trading and smoke management, and a correction to
the State's regional haze statutes, on December 31, 2004. EPA approved
the smoke management rules submitted as part of the revisions in
2004,\21\ but did not propose or take final action on any other portion
of the 309 SIP.
---------------------------------------------------------------------------

    \20\ 40 CFR 51.309(a).
    \21\ 71 FR 28270 and 72 FR 25973.
---------------------------------------------------------------------------

    In response to a court decision,\22\ EPA revised 40 CFR 51.309 on
October 13, 2006, making a number of substantive changes and requiring
states to submit revised 309 SIPs by December 17, 2007.\23\
Subsequently, ADEQ sent a letter to EPA dated December 24, 2008,
acknowledging that it had not submitted a SIP revision to address the
requirements of 40 CFR 51.309(d)(4) related to stationary sources and
40 CFR 51.309(g), which governs reasonable progress requirements for
Arizona's eight mandatory Class I areas outside of the Colorado
Plateau.\24\
---------------------------------------------------------------------------

    \22\ Center for Energy and Economic Development v. EPA, 398 F.3d
653 (D.C. Circuit 2005).
    \23\ 71 FR 60612.
    \24\ Letter from Stephen A. Owens, ADEQ, to Wayne Nastri, EPA,
dated December 24, 2008.
---------------------------------------------------------------------------

    EPA made a finding on January 15, 2009, that 37 states, including
Arizona, had failed to make all or part of the required SIP submissions
to address regional haze.\25\ Specifically, EPA found that Arizona
failed to submit the plan elements required by 40 CFR 51.309(d)(4) and
(g). EPA sent a letter to ADEQ on January 14, 2009, notifying the State
of this failure to submit a complete SIP. ADEQ decided to submit a SIP
under CAA section 308, instead of under section 309. EPA proposed on
February 5, 2013,\26\ to disapprove Arizona's 309 SIP except for the
smoke management rules that we had previously approved. Our final rule
partially disapproving Arizona's 309 SIP was published on August 8,
2013.\27\
---------------------------------------------------------------------------

    \25\ 74 FR 2392.
    \26\ 78 FR 8083.
    \27\ 78 FR 48326.
---------------------------------------------------------------------------

    ADEQ adopted and transmitted its 2011 RH SIP under section 308 of
the RHR to EPA Region 9 in a letter dated February 28, 2011. The SIP
was determined complete by operation of law on August 28, 2011.\28\ The
SIP was properly noticed by the State and available for public comment
for 30 days prior to one public hearing held in Phoenix, Arizona, on
December 2, 2010. Arizona included in its SIP responses to written
comments from EPA Region 9, the National Park Service, the U.S. Forest
Service, and other stakeholders including regulated industries and
environmental organizations. The 2011 RH SIP is available to review in
the docket for this proposed rule.\29\
---------------------------------------------------------------------------

    \28\ CAA section 110(k)(1)(B).
    \29\ ``Arizona State Implementation Plan, Regional Haze under
Section 308 of the Federal Regional Haze Rule,'' February 28, 2011.
---------------------------------------------------------------------------

    As shown in Table 3, the first phase of EPA's action on the 2011 RH
SIP addressed three BART sources. The final rule for the first phase (a
partial approval and partial disapproval of the State's plan and a
partial FIP) was signed by the Administrator on November 15, 2012, and
published in the Federal Register on December 5, 2012. The emission
limits on the three sources will improve visibility by reducing
NOX emissions by about 22,700 tons per year. In the second
phase of our action, we proposed on December 21, 2012, to approve in
part and disapprove in part the remainder of the 2011 RH SIP. ADEQ
submitted an Arizona RH SIP Supplement on May 3, 2013, to correct
certain deficiencies identified in that proposal. We then proposed on
May 20, 2013, to approve in part and disapprove in part the Supplement.
Our final rule approving in part and disapproving in part Arizona's RH
SIP was published on July 30, 2013.

C. EPA's Authority To Promulgate a FIP

    Under CAA section 110(c), EPA is required to promulgate a FIP
within 2 years of the effective date of a finding that a state has
failed to make a required SIP submission. The FIP requirement is
terminated if a state submits a regional haze SIP, and EPA approves
that SIP before promulgating a FIP. See 74 FR 2392. Specifically, CAA
section 110(c) provides:

    (1) The Administrator shall promulgate a Federal implementation
plan at any time within 2 years after the Administrator--
    (A) finds that a State has failed to make a required submission
or finds that the plan or plan revision submitted by the State does
not satisfy the minimum criteria established under [CAA section
110(k)(1)(A)], or
    (B) disapproves a State implementation plan submission in whole
or in part, unless the State corrects the deficiency, and the
Administrator approves the plan or plan revision, before the
Administrator promulgates such Federal implementation plan.

Section 302(y) defines the term ``Federal implementation plan'' in
pertinent part, as:

    [A] plan (or portion thereof) promulgated by the Administrator
to fill all or a portion of a gap or otherwise correct all or a
portion of an inadequacy in a State implementation plan, and which
includes enforceable emission limitations or other control measures,
means or techniques (including economic incentives, such as
marketable permits or auctions or emissions allowances) . . .

Thus, because we determined that Arizona failed to timely submit a
Regional Haze SIP, we are required to promulgate a Regional Haze FIP
for Arizona, unless we first approve a SIP that corrects the non-
submittal deficiencies identified in our finding of January 15, 2009.
For the reasons explained below, we approved in part and disapproved in
part the Arizona Regional Haze SIP on July 30, 2013. Therefore, we are
proposing a FIP to address those portions of the SIP that we
disapproved.

IV. EPA's BART Process

 A. BART Factors

    The purpose of the BART analysis is to identify and evaluate the
best system of continuous emission reduction based on the BART
Guidelines \30\ as summarized below. Steps 1 through 3 address the
availability, feasibility and effectiveness of retrofit control
options. In our analysis of control technology options, we expressly
include the emission baseline calculation that is a key factor in
determining control effectiveness. Step 4 is the five-factor BART
analysis that results in selecting the emission limit that represents
BART in Step 5. Following the process steps is a short description of
each BART factor.
---------------------------------------------------------------------------

    \30\ See July 6, 2005 BART Guidelines, 40 CFR 51, Regional Haze
Regulations and Guidelines for Best Available Retrofit Technology
Determinations.
---------------------------------------------------------------------------

    Step 1--Identify all available retrofit control technologies.
    Step 2--Eliminate technically infeasible options.
    Step 3--Evaluate control effectiveness of remaining control
technologies.
    Step 4--Evaluate impacts and document the results.
     Factor 1: Cost of compliance.
     Factor 2: Energy and non-air quality environmental impacts
of compliance.
     Factor 3: Pollution control equipment in use at the
source.
     Factor 4: Remaining useful life of the facility.
     Factor 5: Visibility impacts.
    Step 5--Select BART.
    Factor 1: Costs of Compliance: The evaluation of costs is an
important part of a five-factor analysis because it influences the
cost-effectiveness that is

compared to the visibility benefits. Estimating the cost of compliance
primarily depends on the cost estimates and control effectiveness of
each technically feasible BART control option. For each of the four
BART facilities evaluated in this section, we state the source of the
cost-related information and how it was used in our analysis. While EPA
relies primarily on the cost methods in our Control Cost Manual, we
also rely on verified cost estimates from the companies and cost
methods used for specific industries. In some cases, certain capital
costs and annual operating costs were developed by our contractor based
on actual costs associated with specific types of sources. Where
possible, we have conducted new cost analyses considering more recent
information from ADEQ or from the four BART facilities. Please refer to
the TSD for the detailed cost analyses.
    Factor 2: Energy and Non-air Quality Environmental Impacts: In
assessing the potential energy impacts of BART control options, we
consider direct and indirect effects on energy availability and costs.
An example of a direct energy impact is the cost of energy consumption
from the control equipment. Examples of non-air quality impacts include
safety issues associated with handling and transportation of anhydrous
ammonia or the ability to sell fly ash rather than dispose of it.
    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, we always consider simple
retention of existing equipment as a BART candidate. We also consider
existing equipment in determining available control technologies that
can be used with or replace such equipment. Second, where appropriate,
we consider existing equipment in developing baseline emission rates
for use in cost calculations and visibility modeling. Pollutant-
specific discussions of these issues are included in the following
sections.
    Factor 4: Remaining Useful Life of the Source: We consider each
source's ``remaining useful life'' as one element of the overall cost
analysis as allowed by the BART Guidelines.\31\ In cases where we are
not aware of any enforceable shut-down date for a particular source or
unit, we use a 20-year amortization period as the remaining useful life
per the EPA Cost Control Manual.
---------------------------------------------------------------------------

    \31\ 40 CFR Part 51, Appendix Y, section IV.D.4.k.
---------------------------------------------------------------------------

    Factor 5: Anticipated Degree of Visibility Improvement: EPA relied
on the CALPUFF modeling system (version 5.8) for visibility modeling,
which consists of the CALPUFF dispersion model, the CALMET
meteorological data processor, and the CALPOST post-processing program.
The initial modeling was performed by our contractor, the University of
North Carolina (UNC) at Chapel Hill. In some cases, companies submitted
BART analyses including visibility modeling that we used to evaluate
visibility benefits. An explanation of the visibility analysis and
tables follows this section, a description of the modeling is included
in the five-factor discussion for each source, and more details are
available in the TSD.

 B. Visibility Analysis

    EPA estimated the degree of visibility improvement expected to
result from various BART control options based on the difference
between baseline visibility impacts prior to controls and visibility
impacts with controls in operation. Baseline emissions were based on
the highest 24-hour emissions from monitored emissions data when
available, otherwise from estimates of production rates and emission
factors. Control case emissions were derived from the baseline by
applying the percent reduction in emission factor expected from the
control. Impacts at all Class I areas within 300 km of each facility
were assessed. EPA used the CALPUFF model version 5.8 \32\ to determine
the baseline and post-control visibility impacts, following the
modeling approach recommended in the BART Guidelines. Our contractor at
UNC developed a modeling protocol and carried out most of the modeling
and the post-processing of model output into tables of visibility
impacts. EPA supplemented this for certain sources with modeling of
additional control scenarios, corrections to some scenarios and post-
processing work, and some sensitivity simulations. Also, EPA performed
the modeling for the two smelters. Details of the modeling are in the
TSD.
---------------------------------------------------------------------------

    \32\ 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 part 51, Appendix W, section 6.2.1.e; 68 FR 18440, April 15,
2003). EPA updated the specific version to be used for regulatory
purposes on June 29, 2007, including minor revisions as of that
date; the approved CALPUFF modeling system includes CALPUFF version
5.8, level 070623, and CALMET version 5.8 level 070623. At this
time, any other version of the CALPUFF modeling system would be
considered an ``alternative model'', subject to the provisions of
Guideline on Air Quality Models section 3.2.2(b), requiring a full
theoretical and performance evaluation.
---------------------------------------------------------------------------

    EPA modeled all units (stacks) and pollutants simultaneously for
each source. Modeling of all emissions from all units accounts for the
chemical interaction between multiple plumes, and between plumes and
background concentrations. This also accounts for the fact that
deciview benefits from controls on individual units are not strictly
additive. As recommended in the BART Guidelines, the 98th percentile
daily impact in deciviews is used as the basic metric of visibility
impact. EPA relied on the 98th percentile over the merged 2001-2003
period. The alternative of using the average of the three 98th
percentiles from 2001, 2002 and 2003 was also calculated, and the
results of using it are provided in the TSD, although they differ
little from the merged approach. Both are valid indicators of the 98th
percentile.\33\ EPA also mainly relied on the revised IMPROVE equation
for translating pollutant concentrations into deciviews (CALPOST
visibility method 8), the recommended method for new visibility
analyses. The old IMPROVE equation (method 6) was used by most states
in their original SIP submittals and was acceptable at that time. EPA
used the best 20 percent of natural background days in calculating
delta deciviews. For the original SIP submittals, states were free to
use this or the annual average background. Overall, we refer to the
method we used as method ``8b'' (``b'' for ``best''). Model results
using visibility method 6 and annual average background conditions
(``a'' for average) also are provided in the TSD (i.e., methods 6a, 6b,
and 8a, as well as 8b).
---------------------------------------------------------------------------

    \33\ For each modeled day, the CALPUFF model provides the
highest impact from among the receptor locations for a given Class I
area. The baseline impact in the tables is the 98th percentile among
these daily values. The improvement in the tables is the difference
between that baseline impact and the 98th percentile impact after
applying controls. The 98th percentile is represented by the 22nd
high over the 2001-2003 period modeled. The TSD includes an
alternative, the average of each of the three years' 8th highs,
which yields slightly different values.
---------------------------------------------------------------------------

 C. Explanation of Visibility Tables

    For each facility, this notice provides one or more tables of
visibility impacts and visibility improvement from controls in
deciviews. Each table has the same format: columns list the Class I
areas within 300 km of the facility, the distance,\34\ baseline modeled
visibility impact from the facility for each area, and one or more
columns with the

modeled visibility improvement from a candidate control option. A
modeling run abbreviation, such as ``base'' or ``ctrl2'', is included
along with a short description of the option. For several facilities,
there are two different baselines incorporating different emission
assumptions. For these, there are baseline and control columns for each
of the two baselines. For Sundt Unit 4, there are separate tables for
SO2 and NOX controls, and an additional table
showing the effect of reductions for both SO2 and
NOX for the proposed BART controls and for a better-than-
BART alternative. At the bottom of each table are five rows showing
impacts and improvements from the facility for all the Class I areas
considered together, and also two measures of visibility cost-
effectiveness. The cost-effectiveness here is ``dollars per deciview,''
where dollars is the annualized total cost of the control in millions
of dollars per year, divided by either the sum of deciview improvements
over all impacted Class I areas, or the largest single area deciview
improvement. Cost-effectiveness in terms of dollars per ton is
presented in other tables and has been considered for each source and
BART option. The headings for these table rows are:
---------------------------------------------------------------------------

    \34\ The distances given are from the facility to the nearest
model receptor location; distances to the actual Class I area
boundary may be slightly less. Receptor locations are defined for
all Class I areas by the National Park Service. See ``Class I
Receptors'' Web site, http://www2.nature.nps.gov/air/maps/Receptors/
.
---------------------------------------------------------------------------

    (1) ``Cumulative (sum),'' the cumulative impact or improvement that
is computed as the sum of impact or improvement over all the areas;
    (2) ``Maximum,'' single largest impact or improvement that is the
maximum over all the areas;
    (3) `` CIAs >= 0.5 dv,'' the number of Class I areas
having a baseline impact from the source of at least 0.5 dv (or, for
the control columns, the number of areas showing improvement of at
least 0.5 dv due to the control);
    (4) ``Million $/dv (cumul. dv),'' annual control cost in millions
of dollars per deciview considering the improvement at all the Class I
areas together; and
    (5) ``Million $/dv (max. dv),'' annualized cost per deciview
considering the largest single area improvement.
    The Federal Land Managers have sometimes used $10 million/dv as a
comparison benchmark for the $/dv computed from the maximum, and $20
million/dv as a benchmark for $/dv computed from cumulative deciviews.
We have not endorsed the use of these or any other $/dv benchmarks as
criteria for making BART determinations.
    The TSD for this notice provides bar charts and additional
visibility tables, including results for individual modeled years and
their average, the old IMPROVE equation, and annual average background
conditions instead of best 20 percent. There also are model results for
various sensitivity analyses.

V. EPA's Proposed BART FIP

A. Sundt Generating Station Unit 4

    Summary: EPA is proposing to find that Sundt Unit 4 is eligible for
and subject to BART. EPA is proposing BART emissions limits on Sundt
Generating Station Unit 4 for NOX, SO2 and
PM10 based on the corresponding control technologies listed
in Table 4 and described in the following BART analyses. For
NOX, we propose an emission limit of 0.36 lb/MMBtu
consistent with the use of SNCR. For SO2, we propose an
emission limit of 0.23 lb/MMBtu consistent with the use of DSI. For
PM10, we propose a filterable PM10 emission limit
of 0.03 lb/MMBtu based on the use of the existing fabric filter
baghouse. Finally, we are also proposing a switch to natural gas as a
better-than-BART alternative.

                            Table 4--Sundt 4: Summary of Proposed BART Determinations
----------------------------------------------------------------------------------------------------------------
                                   Emission limit (lb/
            Pollutant                    MMBtu)                            Control technology
----------------------------------------------------------------------------------------------------------------
NOX..............................               0.36   Selective Non-Catalytic Reduction.
SO2..............................               0.23   Dry Sorbent Injection.
PM10.............................               0.030  Fabric filter baghouse (existing).
----------------------------------------------------------------------------------------------------------------

    Affected Class I Areas: Ten Class I areas are within 300 km of
Sundt. Their nearest borders range from 17 km to 247 km away, with
Saguaro NP the closest, and Galiuro WA the second closest. The highest
baseline visibility impact of Sundt Unit 4 is 3.4 dv at Saguaro. The
second highest baseline impact is 1.1 dv at Galiuro. Other areas have
visibility impacts of 0.5 dv or less. The cumulative sum of visibility
impacts over all the Class I areas is 6.6 dv.
    Facility Overview: The Sundt Generating Station is an electric
utility power plant located in Tucson, Arizona, operated by Tucson
Electric Power. The plant consists of four steam electric boilers and
three stationary combustion turbines for a total net generating
capacity of approximately 500 megawatts (MW).\35\ Sundt Unit 4 is a
steam electric boiler that was manufactured in 1964 and placed into
operation in about 1967. Unit 4 is a dry bottom wall-fired boiler with
a maximum gross capacity of 130 MW when firing coal. Originally
designed to fire natural gas and fuel oil, Sundt Unit 4 was converted
to also be able to fire coal in the early 1980s as a result of an order
issued by the Department of Energy. The unit now fires both coal and
natural gas, as explained in more detail below. As part of the coal
conversion, the unit was equipped with a fabric filter for particulate
matter control. Unit 4 was upgraded in 1999 with LNB and overfire air
(OFA) designed to meet Phase II Acid Rain Program requirements. At
present, Unit 4 operates with the pollution control equipment and is
subject to the emission limits listed in Table 5 that reflects a coal-
operating scenario.
---------------------------------------------------------------------------

    \35\ As described in Pima DEQ Permit No. 1052, in the TSD.

                        Table 5--Sundt 4: Current Emission Limits and Control Technology
----------------------------------------------------------------------------------------------------------------
            Pollutant                Emission limit                          Control device
----------------------------------------------------------------------------------------------------------------
NOX.............................  0.46 lb/MMBtu \36\.  LNB with OFA.
SO2.............................  1 lb/MMBtu \37\....  None.
PM10............................  233 lb/hr \38\.....  Fabric filter/baghouse.
----------------------------------------------------------------------------------------------------------------

    TEP has indicated that the generating capacity of Sundt Unit 4
while firing coal is reduced compared to its capacity using natural
gas. As reported to the Energy Information Agency (EIA), Unit 4 has a
173 MW nameplate capacity while firing natural gas. However, the
maximum gross capacity at which the unit could operate for a sustained
period of time while burning coal is about 130 MW. This is due
primarily to the fact that the amount of coal that can be introduced to
the boiler is limited by the size of the boiler. Excess coal injection
causes the flame to impinge on the back wall of the boiler which
damages the boiler tubes.\39\ A summary of historical emissions data
for a recent period of time is in Table 6.
---------------------------------------------------------------------------

    \36\ Pima DEQ Permit No. 1052, Attachment F: Phase II Acid Rain
Permit.
    \37\ Pima DEQ Permit No. 1052, Specific Condition II.A.2.b.
    \38\ As determined by Pima DEQ Permit No. 1052, Specific
Condition II.A.1.
    \39\ TEP's letter dated May 10, 2013, page 2.

                                                   Table 6--Sundt 4: Historical Emissions (2008-2012)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                NOX                       SO2
                             Year                               Heat duty  ---------------------------------------------------- Coal (tons)  Natural gas
                                                                (MMBtu/yr)     (tpy)      (lb/MMBtu)     (tpy)      (lb/MMBtu)                  (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
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Baseline Emissions Calculations: The baseline period, baseline
emissions, and capacity factor are three key variables in determining
BART that are linked to fuel usage. TEP has indicated that while Sundt
Unit 4 predominantly has operated as a coal-fired unit, it has recently
expanded its use of natural gas as a result of historically low natural
gas prices.\40\ As shown in the last column of Table 6, Unit 4 has used
much higher amounts of natural gas during 2009-2010 and again in 2012
that are not representative of anticipatable operations based on coal.
Accordingly, we use calendar year 2011 emissions when Unit 4
predominately used coal as the baseline period for annual average
emission estimates. Although this represents only a single year of
emissions 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 when burning coal.\41\ In
addition, we rely on an annual capacity factor of 0.49 based on a coal-
fired capacity of 130 MW and actual generation from the baseline period
of 2011. For visibility modeling, we used baseline emissions for
NOX and SO2 based on maximum daily emission
rates, as reported to EPA's CAMD Acid Rain Program database, for the
period from 2008 to 2010. While this time period is prior to the 2011
baseline period used for the annual emission estimates, the highest
daily emission rates from 2008 to 2010 correspond to coal usage. Since
these maximum daily emission rates still 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 estimate annual emission rates. For PM10, the
baseline emission rate used in visibility modeling is based on the
value in the original Western Regional Air Partnership (WRAP)
visibility modeling that reflects the use of coal and the existing
fabric filter. For a more detailed analysis of how we determined the
baseline period, baseline emissions and capacity factor, please refer
to the TSD.
---------------------------------------------------------------------------

    \40\ TEP's letter dated May 10, 2013, page 2.
    \41\ As discussed in the BART Guidelines, 40 CFR Part 51,
Appendix Y, section IV.D.4.d.
---------------------------------------------------------------------------

    Modeling Overview: EPA's contactor UNC performed the initial
modeling of Sundt's visibility impacts. EPA performed supplemental
modeling to correct some minor errors in the initial work and to
estimate impacts from additional control scenarios, such as switching
entirely to natural gas fuel. EPA also modeled the impacts for the
western unit of Saguaro NP, whereas originally only the eastern unit
was included. Although only Unit 4 is BART-eligible, all four Sundt
units were included in the CALPUFF modeling to more accurately
represent the chemistry of the facility's pollutant plume. Baseline
emissions for modeling were based on daily CAMD emissions monitoring
data for 2008-2010, a period with no changes in pollution controls at
the facility. Control case emissions were derived from the baseline by
applying the percent reduction expected from the control.
    Saguaro NP has an eastern unit, the Rincon Mountain District, and a
western unit, the Tucson Mountain District. In the original set of
modeling receptor locations developed by the National Park Service,
only the eastern unit was included. CALPUFF modeling typically covered
only the eastern unit. This is true of modeling by the WRAP, and also
of modeling by EPA's contractor UNC, which used the WRAP work as a
starting point. A more recent set of NPS modeling receptors from 2008
is available that covers both eastern and western units of Saguaro. For
this FIP, EPA remodeled for both Saguaro units where needed for a given
facility. The only facilities for which it makes a significant
difference are TEP Sundt and CalPortland Cement due to their close
proximity to Saguaro.

 1. Proposed Eligible and Subject to BART
    EPA is proposing to find that Sundt Unit 4 is eligible for and
subject to BART. In our final rulemaking on the Arizona RH SIP dated
July 30, 2013, we disapproved ADEQ's finding that Sundt Unit 4 was not
eligible for BART.\42\ In particular, we found that, although this unit
was ``reconstructed'' in 1987, it remains BART-eligible because it did
not undergo prevention of significant deterioration (PSD) review at the
time of reconstruction.\43\ For this reason, we propose to find Sundt
Unit 4 is eligible for a BART analysis of the three haze-causing
pollutants: NOX, SO2 and PM10.
---------------------------------------------------------------------------

    \42\ 78 FR 46175 (codified at 40 CFR 52.145(e)(2)(i)).
    \43\ See 78 FR 75722, 78 FR 46151, and ``TEP Sundt Unit I4 BART
Eligibility Memo'' (November 21, 2012).
---------------------------------------------------------------------------

    Under the RHR and the BART Guidelines, any BART-eligible source
that either ``causes'' or ``contributes'' to visibility impairment at
any Class I area is subject to BART.\44\ EPA previously approved ADEQ's
decision to set 0.5 dv as the threshold for determining whether a
source contributes to visibility impairment at a given Class I
area.\45\ In order to determine whether Sundt Unit 4 is subject to
BART, EPA's contractor UNC evaluated whether Unit 4 has an impact of
0.5 dv or more at any Class I area. UNC's visibility modeling showed
that two Class I areas experienced a 98th percentile impact greater
than 0.5 dv due to emissions from Sundt Unit 4.\46\ In particular, the
98th percentile impact across the three years modeled was 2.798 dv at
Saguaro and 0.839 dv at Galiuro.\47\ These results indicate that Sundt
Unit 4 causes visibility impairment at Saguaro and contributes to
impairment at Galiuro. Therefore, EPA proposes to find that Sundt Unit
4 is subject to BART.
---------------------------------------------------------------------------

    \44\ 40 CFR part 51, appendix Y, section III.A.
    \45\ 77 FR 46152-53.
    \46\ Technical Analysis for Arizona and Hawaii Regional Haze
FIPs: Report on Identification of Sources Subject to BART, UNC, July
20, 2012, Table 4.
    \47\ For an expanded discussion of our approach to visibility
modeling, please refer to Section III (General Approach to the Five-
Factor BART analysis) of the Sundt4 TSD. This approach was used in
both determining whether Sundt 4 was subject to BART, as well as in
evaluating the visibility factor in the BART analysis.
---------------------------------------------------------------------------

 2. Proposed BART Analysis and Determination for NOX
    For our NOX BART analysis, we identify all available
control technologies, eliminate options that are not technically
feasible, and evaluate the control effectiveness of the remaining
control options. We then evaluate each technically feasible control in
terms of a five-factor BART analysis and propose a determination for
BART.
a. Control Technology Availability, Technical Feasibility, and
Effectiveness
    EPA proposes to find that SNCR and selective catalytic reduction
(SCR) are available and technically feasible options to control
NOX emissions with a control efficiency of approximately 50
percent for SNCR and approximately 89 percent for SCR.
    SNCR involves the non-catalytic decomposition of NOX to
molecular nitrogen and water. Typical NOX control
efficiencies for SNCR range from 40 to 60 percent, depending on inlet
NOX concentrations, fluctuating flue gas temperatures,
residence time, amount and type of nitrogenous reducing agent, mixing
effectiveness, acceptable levels of ammonia slip, and presence of
interfering chemical substances in the gas stream. Because Sundt Unit 4
already operates with NOX combustion controls, we have used
an SNCR control efficiency of 30 percent from a baseline that includes
LNB with OFA. Considering typical combustion control technologies such
as LNB and OFA can achieve control efficiencies of about 25 to 30
percent, the result is total control efficiency from an uncontrolled
baseline of about 50 percent, which is in the mid-range of SNCR control
efficiencies.
    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 NOX to molecular nitrogen, water, and
oxygen. The catalyst lowers the temperature required for the chemical
reaction between NOX and the reducing agent. Technical
factors that impact the effectiveness of this technology include the
catalyst reactor design, operating temperature, type of fuel fired,
sulfur content of the fuel, design of the ammonia injection system, and
the potential for catalyst poisoning. SCR has been installed on
numerous coal-fired boilers of varying sizes, and is considered
technically feasible. We note that SCRs are classified as a low dust
SCR (LDSCR) or high dust SCR (HDSCR). As explained in the TSD, the SCR
system considered in this analysis is the HDSCR.
    Existing vendor literature and technical studies indicate that SCR
systems are capable of achieving approximately 80 to 90 percent control
efficiency, and that this emission rate can be achieved on a retrofit
basis, particularly when combined with combustion control technology
such as LNB.\48\ Our contractor used a design emission rate of 0.050
lb/MMBtu (annual average), which in the case of Sundt Unit 4
corresponds to a control efficiency of 89 percent. While this is a
value close to the upper range of SCR control efficiency, we consider
the use of 0.050 lb/MMBtu appropriate for Sundt Unit 4. A review of
Acid Rain Program data indicates that there are up to seven dry-bottom,
wall-fired boilers operating with SCR on a retrofit basis that have
achieved an annual average emission rate of 0.050 lb/MMBtu or lower in
practice.\49\ However, there are design differences between Sundt Unit
4 and these other units (i.e., boiler size, coal type and
characteristics, and loading profile) that have the potential to affect
this comparison. If we receive additional comments that sufficiently
document source-specific considerations justifying the use of an
emission rate higher than 0.050 lb/MMBtu, we may incorporate such
considerations in our selection of BART.
---------------------------------------------------------------------------

    \48\ 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).
    \49\ See spreadsheet ``CAMD Wall-fired Coal EGUs.xlsx'' in the
docket.
---------------------------------------------------------------------------

b. BART Analysis for NOX
    Costs of Compliance: In evaluating the costs of compliance for SNCR
and SCR, we calculated the control costs ($) and emission reductions
(tons/year of pollutant) for each control technology, and developed
average cost-effectiveness ($/ton) values. Estimated NOX
emission reductions are summarized in Table 7 and cost-effectiveness
numbers are summarized in Table 8 for each option. A more detailed
version of emission calculations are in our docket \50\ and in our
contractor's report. The heat duty and capacity factor used in the
emission calculations below differ from the values used in the
calculations originally prepared by our contractor, due to the unit's
lower capacity when burning coal (130 MW) rather than natural gas (173
MW). The heat duty (MMBtu/hr) and capacity factor (0.49) reflect the
coal-burning heat duty, rather than the natural gas-burning heat
duty.\51\
---------------------------------------------------------------------------

    \50\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
    \51\ As noted by TEP in its May 10, 2013 letter, 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.

                                                 Table 7--Sundt 4: NOX Control Option Emission Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Control      Emission    Heat duty     Capacity       NOX emission rate         NOX
                                                                efficiency     factor   -------------    factor   --------------------------   emission
                        Control option                        --------------------------             -------------                            reduction
                                                                                MMBtu/hr                   lb/hr         tpy     ------------
                                                                    %         lb/MMBtu                     %                                     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
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Our consideration of the cost of compliance focuses primarily on
the cost-effectiveness of each control option as measured in average
cost per ton and incremental cost per ton of each control option as
shown in Table 8. SCR is the most stringent option with the highest
average cost-effectiveness of $5,176/ton, and incremental cost-
effectiveness over SNCR of $6,174/ton. Detailed cost calculations can
be found in our docket.\52\ While we have relied primarily upon the
cost calculations prepared by our contractor, we have incorporated
certain elements of TEP's analysis \53\ into our cost calculations. The
most significant revisions to cost estimates include the following:
---------------------------------------------------------------------------

    \52\ See spreadsheet ``Sundt4 Control Costs 2014-01-26.xlsx'' in
the docket.
    \53\ Letter dated May 10, 2013.
---------------------------------------------------------------------------

     We have changed the unit size from 173 MW to 130 MW to
reflect the gross capacity of using coal. Although this has the net
effect of decreasing certain costs, particularly several operation and
maintenance (O&M) costs, the revised capital cost estimates increased
for SCR (from $38 million to $45 million) and SNCR (from $2.8 million
to $3.1 million).
     We have used a retrofit difficulty value of 1.5 (increased
from 1.0) in cost estimates due to certain difficulties associated with
retrofit installation of SCR. These difficulties are the result of site
congestion and the configuration of the existing boiler structure and
coal handling system as noted by TEP.
     We have included the cost of air preheater modifications
that TEP stated are necessary in order to accommodate SCR due to site
congestion and coal handling configuration.

                                                 Table 8--Sundt 4: NOX Control Option Cost-Effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Capital     Annualized     Annual       Total       Emission    Cost-effectiveness  ($/
                                                                   cost       capital     operating   annual cost   reduction             ton)
                        Control option                        -------------     cost         cost    ---------------------------------------------------
                                                                           --------------------------
                                                                   ($)          ($)          ($)         ($/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
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Pollution Control Equipment in Use at the Source: The presence of
existing pollution control technology at Sundt Unit 4 is reflected in
the consideration of available control technologies and in the
development of baseline emission rates for use in cost calculations and
visibility modeling. In the case of NOX, current pollution
controls are reflected in our selection of 2011 as the baseline period,
which includes the use of LNB and OFA.
    Energy and Non-Air Quality Environmental Impacts: Regarding
potential energy impacts of the BART control options, we note that SCR
incurs a draft loss that will result in certain load loss, 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. Indirect energy impacts,
such as the energy to produce raw materials, are not considered, which
is 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. The ability to sell fly ash is unlikely to be
affected by the installation of SNCR or SCR technologies. Finally, SNCR
and SCR 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 to warrant the
elimination of either of the available control technologies.
    Remaining Useful Life of the Source: We are considering the
``remaining useful life'' of Sundt Unit 4 as one element of the overall
cost analysis as allowed by the BART Guidelines.\54\ Since there is not
state- or federally-enforceable shut-down date for this unit, we have
used a 20-year amortization period per the EPA Cost Control Manual as
the remaining useful life for the facility.\55\
---------------------------------------------------------------------------

    \54\ 40 CFR Part 51, Appendix Y, section IV.D.4.k.
    \55\ We note that the 20 year amortization period is primarily
used in NOX control cost calculations, such as for SCR.
In order to promote consistency in the analysis, we have used the 20
year period in the cost calculations for other control options, such
as for SO2 control, for which the Control Cost Manual
includes examples that use an amortization period of 15 years.
---------------------------------------------------------------------------

    Degree of Visibility Improvement: The visibility improvement due to
NOX controls is modest. SNCR was modeled at a 30 percent
NOX emission reduction. As shown in Table 9, this yields a
maximum visibility improvement of just over 0.2 dv at Saguaro. Galiuro
improves about half as much, and other areas much less. The cumulative
improvement across all impacted Class I areas is 0.5 dv. SCR was
modeled at 89 percent NOX reduction to achieve 0.05 lb/
MMBtu. SCR provides a maximum improvement of 0.8 dv, which occurs at
Saguaro. Galiuro again improves about half as much, and the cumulative
improvement across all Class I areas is 1.6 dv. This visibility
improvement is substantially greater for SCR than for SNCR.

                      Table 9--Sundt 4: Visibility Impact and Improvement From NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                                         Visibility     Visibility  improvement
                                                             Distance      impact    ---------------------------
                       Class I area                            (km)    --------------     SNCR
                                                                          Base case     (ctrl04)    SCR (ctrl08)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM............................................          144          0.43          0.03          0.12
Chiricahua WA............................................          141          0.51          0.05          0.15
Galiuro WA...............................................           64          1.10          0.12          0.34
Gila WA..................................................          232          0.17          0.02          0.04
Mazatzal WA..............................................          203          0.19          0.02          0.04
Mount Baldy WA...........................................          232          0.15          0.01          0.03
Pine Mountain WA.........................................          247          0.15          0.02          0.03
Saguaro NP...............................................           17          3.40          0.23          0.78
Sierra Ancha WA..........................................          178          0.19          0.01          0.04
Superstition WA..........................................          137          0.32          0.01          0.05
Cumulative (sum).........................................  ...........          6.6           0.5           1.6
Maximum..................................................  ...........          3.40          0.23          0.78
 CIAs >= 0.5 dv.................................  ...........          3             0             1
Million $/dv (cumul. dv).................................  ...........  ............         $2.4          $3.7
Million $/dv (max. dv)...................................  ...........  ............         $5.5          $7.7
----------------------------------------------------------------------------------------------------------------

c. Proposed BART Determination for NOX
    EPA proposes to find that BART for NOX is an emission
limit of 0.36 lb/MMBtu on a 30-day BOD rolling basis that is achievable
by SNCR with LNB and OFA. The primary factors supporting this proposed
finding are the average cost-effectiveness and anticipated visibility
benefits of controls. In particular, while SCR is anticipated to
achieve the greatest degree of visibility improvement, it is also
significantly more expensive than SNCR, with an average cost-
effectiveness of $5176/ton. We do not consider this average cost to be
warranted by the projected visibility benefit of SCR for this facility.
Table 10 provides a summary of our five-factor BART analysis.
    In proposing an emission limit of 0.36 lb/MMBtu, we have considered
the annual average design value for SNCR of 0.31 lb/MMBtu as well as
the need to account for emissions associated with startup and shutdown
events. To account for this variability, we have examined the
difference between the highest 30-day rolling NOX value and
the highest annual average NOX value observed over the
baseline period, which is approximately 17 percent.\56\ 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.
---------------------------------------------------------------------------

    \56\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
---------------------------------------------------------------------------

    We propose to require compliance with this requirement within three
years of the effective date of the final rule. A 2006 Institute of
Clean Air Companies (ICAC) study indicated that the installation time
for a typical SNCR retrofit, from bid to startup, is 10 to 13
months.\57\ However, because we are also requiring the installation of
additional SO2 controls, we consider a three year period for
compliance with both BART determinations to be appropriate. We are
seeking comment on whether this compliance date is reasonable and
consistent with the requirement of the Clean Air Act that BART be
installed ``as expeditiously as practicable but in no event later than
five years after [promulgation of the applicable FIP].'' \58\ If we
receive information during the comment period that establishes that a
different compliance time frame is appropriate, we may finalize a
different compliance date. Finally, we are proposing regulatory text
that includes monitoring, reporting, and recordkeeping requirements to
ensure that the emission limit and compliance deadline are enforceable.
As part of the proposed monitoring requirements, we are including a
requirement to monitor rates of ammonia injection in order to ensure
proper operation of the SNCR in a manner that minimizes ammonia
emissions.
---------------------------------------------------------------------------

    \57\ See ``Typical Installation Timelines for NOX
Emissions Control Technologies on Industrial Sources'', Institute of
Clean Air Companies, December 4, 2006.
    \58\ Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4).

                               Table 10--Sundt 4: Summary of BART Analysis for NOX
----------------------------------------------------------------------------------------------------------------
                                                 LNB+OFA
            Sundt unit 4 (130 MW)               (baseline)           SNCR+LNB                   SCR+LNB
----------------------------------------------------------------------------------------------------------------
                                                    Emissions
----------------------------------------------------------------------------------------------------------------
Emission Factor (lb/MMBtu)...................        0.445  0.312....................  0.050
Emission Rate (tpy)..........................         1310  917......................  147
Emission Reduction (tpy).....................  ...........  393......................  1,162
Control Effectiveness (%)....................  ...........  30%......................  89%
----------------------------------------------------------------------------------------------------------------
                                               Costs 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
----------------------------------------------------------------------------------------------------------------
                                       Pollution Control Equipment in Use
----------------------------------------------------------------------------------------------------------------
Low-NOX Burners and Over Fire Air
----------------------------------------------------------------------------------------------------------------
                                Energy and Non-Air Quality Environmental Impacts
----------------------------------------------------------------------------------------------------------------
Energy impacts have been reflected in annual O&M costs in the costs of compliance.
----------------------------------------------------------------------------------------------------------------
SCR and SNCR may create potential safety and environmental hazards from the transportation and handling of
 anhydrous ammonia. We consider these impacts manageable with the development of an RMP and additional safety
 procedures, and do not consider them sufficient enough to warrant eliminating either of these available control
 technologies.
----------------------------------------------------------------------------------------------------------------
                                              Remaining Useful Life
----------------------------------------------------------------------------------------------------------------
Control technology amortization period.......  ...........  20 years.................  20 years
----------------------------------------------------------------------------------------------------------------
                                             Visibility Improvement
----------------------------------------------------------------------------------------------------------------
Single largest Class I area improvement (dv).  ...........  0.23.....................  0.78
Single Class I area cost-effectiveness         ...........  $5.5.....................  $7.7
 (million $/dv).
Class I areas with >= 0.50 dv improvement....  ...........  0........................  1
Cumulative visibility improvement (dv).......  ...........  0.5......................  1.6
Cumulative cost-effectiveness (million $/dv).  ...........  $2.4.....................  $3.7
----------------------------------------------------------------------------------------------------------------

4. Proposed BART Analysis and Determination for SO2
    For our SO2 BART analysis, we identified all available
control technologies, eliminated options that are not technically
feasible, and evaluated the control effectiveness of the remaining
control options. We then evaluated each control in terms of a five-
factor BART analysis and proposed a determination for BART.
a. Control Technology Availability, Technical Feasibility, and
Effectiveness
    EPA identified three available and technically feasible
technologies to control SO2 emissions from Sundt Unit 4.
These technologies are lime or limestone-based wet flue gas
desulfurization (wet FGD), lime spray dry absorber (SDA or dry FGD),
and dry sorbent injection (DSI). While each of these control options
has certain design concerns and constraints associated with their
implementation, all three options are considered technically feasible.
    Lime or limestone-based wet FGD: Wet scrubbing systems mix an
alkaline reagent, such as hydrated lime or limestone, with water to
generate scrubbing slurry that is used to remove SO2 from
the flue gas. The alkaline slurry is sprayed countercurrent to the flue
gas, such as in a spray tower, or the flue gas may be bubbled through
the alkaline slurry as in a jet bubbling reactor. As the alkaline
slurry contacts the exhaust stream, it reacts with the SO2
in the flue gas. Design variations may include changes to increase the
alkalinity of the scrubber slurry, increase slurry/SO2
contact, and minimize scaling and equipment problems. Insoluble calcium
sulfite (CaSO3) and calcium sulfate (CaSO4) salts
are formed in the chemical reaction that occurs in the scrubber, and
exit as part of the scrubber slurry. The salts are eventually removed
and handled as a solid waste byproduct. The waste byproduct is mainly
CaSO3, which is difficult to dewater. Solid waste byproducts
from wet lime scrubbing are typically managed in dewatering ponds and
landfills.
    Design concerns associated with wet FGD involve the substantial
water usage requirements needed to generate the alkaline reagent slurry
as well as the substantial amount of wastewater and solid waste
discharge associated with the spent byproduct. A wet FGD control system
must be located after the fabric filter baghouse because the moist
plume resulting from the wet scrubber system would create baghouse
plugging issues if the control is placed ahead of the baghouse. In
addition, a substantial footprint is required for the management of
these waste products as well as for the absorber tower and associated
process equipment such as the slurry preparation, mixing, associated
tanks, and dewatering activities. While these design concerns do
present some challenges, they do not warrant elimination of this option
as technically infeasible.\59\
---------------------------------------------------------------------------

    \59\ TEP's review does not eliminate consideration of wet FGD,
but does describe several design challenges that TEP notes should be
reflected in the five factor analysis. We have incorporated certain
elements of TEP's review in our analysis, as discussed in Step 4.
---------------------------------------------------------------------------

    Our contractor has estimated that newly constructed wet FGD systems
could achieve design emission rates (annual average basis) of 0.06 lb/
MMBtu. Relative to baseline SO2 emission rates, this
corresponds to a control efficiency of 92 percent. We recognize that
FGD systems are designed to achieve more stringent emission rates, and
have demonstrated an ability to achieve control efficiencies up to 98
percent. Our contractor's report notes that the lower control
efficiency cited here is regarded as a conservative estimate. While
this is not the most stringent level of control that the technology is
capable of achieving, we consider 92 percent control efficiency to be
consistent with the median values reported for wet FGD systems.
    Lime SDA or dry FGD: A spray dryer absorber uses a stream of either
dry lime or hydrated lime (semi-dry) in a reaction tower where it
reacts with SO2 in the flue gas to form calcium sulfite
solids. Unlike wet FGD systems that produce a slurry by-product that is
collected

separately from the fly ash, dry FGD systems are designed to produce a
dry byproduct that must be removed with the fly ash in the particulate
control equipment. As a result, dry FGD systems must be located
upstream of the particulate control device to remove the reaction
products and excess reactant material. In instances where hydrated lime
is used as a reagent, the reaction towers must be designed to provide
adequate contact and residence time between the exhaust gas and the
slurry to produce a relatively dry byproduct. Typical process equipment
associated with a spray dryer typically includes an alkaline storage
tank, mixing and feed tanks, an atomizer, spray chamber, particulate
control device and a recycle system. The recycle system collects solid
reaction products and recycles them back to the spray dryer feed system
to reduce alkaline sorbent use.
    A design concern associated with a dry FGD system is that it 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 is reflected in the costs of
compliance for the five-factor analysis. We consider this control
option to be technically feasible.
    Our contractor has estimated that newly constructed dry FGD systems
could achieve design emission rate (annual average basis) of 0.08 lb/
MMBtu. Relative to baseline SO2 emission rates, this
corresponds to a control efficiency of 89 percent. As noted for wet FGD
systems, this is a conservative estimate of what dry FGD systems can
achieve, and is consistent with the median values reported for dry FGD
systems.
    Dry Sorbent Injection: DSI involves the injection of powdered
absorbent directly into the flue gas exhaust stream. These are simple
systems that generally require a sorbent storage tank, feeding
mechanism, transfer line and blower, and an injection device. The dry
sorbent is typically injected countercurrent to the gas flow. An
expansion chamber is often located downstream of the injection point to
increase residence time and efficiency. Particulates generated in the
reaction are controlled in the system's particulate control device. DSI
requires less capital equipment, less physical space, and less
modification to existing ductwork compared to a dry FGD system.
However, reagent costs are much higher and, depending upon the
absorbent and amount of sorbent injected, control efficiency is lower
when compared to a dry FGD system. Soda ash and Trona (sodium
sesquicarbonate) are potential options for reagent use. An important
design consideration of DSI is the ability of the downstream
particulate control device to accommodate the additional particulate
loading resulting from the addition of the DSI reagent into the boiler
flue gas. More effective particulate control devices allow for higher
rates of sorbent injection, which in turn allow for more effective
SO2 control.
    In a review of SO2 control options for BART eligible
units, the Northeast States for Coordinated Air Use Management
(NESCAUM) estimated control effectiveness for DSI in a range of 40-60
percent.\60\ More recently, as part of work done as part of the
Integrated Planning Model (IPM), EPA has estimated control
effectiveness as high as 80 percent,\61\ depending upon factors such as
the type of sorbent, the quantity of sorbent used, and the type of
particulate control device employed. Generally, the use of more
effective particulate control devices allow for higher rates of sorbent
injection, and therefore greater DSI effectiveness. Since Sundt Unit 4
operates with a fabric filter, we consider a control effectiveness
value in the upper range appropriate, and have used 70 percent control
effectiveness in our calculations. This value is above the range
indicated in the NESCAUM study, but does not require the high sorbent
injection rates required to achieve the upper range of control
indicated in IPM documentation. A summary of the control technologies
and their associated control effectiveness is presented in Table 11.
---------------------------------------------------------------------------

    \60\ ``Assessment of Control Technology Options for BART-
Eligible Sources'', Northeast States for Coordinated Air Use
Management In Partnership with The Mid-Atlantic/Northeast Visibility
Union, March 2005.
    \61\ IPM Model--Revisions to Cost and Performance for APC
Technologies, Dry Sorbent Injection Cost Development Methodology,
August 2010.

                 Table 11--Sundt 4: SO2 Control Options
------------------------------------------------------------------------
                                                              Control
                     Control option                        effectiveness
                                                                 %
------------------------------------------------------------------------
Dry Sorbent Injection...................................              70
Dry FGD or Lime SDA.....................................              89
Wet FGD (lime- or limestone-based)......................              92
------------------------------------------------------------------------

b. BART Analysis for SO2
    Costs of Compliance: Our consideration of the costs of compliance
focuses primarily on the cost-effectiveness of each control option, as
measured in cost per ton and incremental cost per ton. The emissions
estimates and cost-effectiveness for the three control options are
shown in Table 12 and Table 13, respectively. Both wet and dry FGD have
average cost-effectiveness values over $5,000/ton, much greater than
DSI, which is a control option that we consider very cost-effective at
$1,857/ton. Moreover, both wet and dry FGD have very high incremental
cost-effectiveness values, indicating that while they are more
effective than less stringent control options, this additional degree
of effectiveness comes at a substantial cost.
    In evaluating the costs of compliance for the control options, we
have calculated the control costs ($) and emission reductions (tons/
year of pollutant) for each control technology, developed average cost-
effectiveness ($/ton) values, and arrived at the emission reductions
for each option as summarized Table 12. A more detailed version of
emission calculations is in our docket,\62\ and in our contractor's
report. As noted previously in our NOX BART analysis, the
heat duty and capacity factor used in these calculations differ from
the values used in the calculations originally prepared by our
contractor because the maximum gross capacity of Sundt Unit 4 while
burning coal is about 130 MW, compared to its natural-gas nameplate
capacity of 173 MW. The heat duty (MMBtu/hr) and capacity factor used
in Table 12 reflect the coal-burning nameplate capacity.\63\ Detailed
cost calculations presented in Table 13 are in the docket.\64\
---------------------------------------------------------------------------

    \62\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
    \63\ 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.
    \64\ See spreadsheet ``Sundt4 Control Costs 2014-01-26.xlsx'' in
the docket.

                                                Table 12--Sundt 4: SO2 Control Option Emission Estimates
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Control      Emission    Heat  duty                   SO2 emission rate         SO2
                                                                efficiency     factor   -------------             --------------------------   emission
                        Control option                        --------------------------                Capacity                              reduction
                                                                                (MMBtu/hr)     factor      (lb/hr)       (tpy)    ------------
                                                                   (%)       (lb/MMBtu)                                                         (tpy)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline (no control)........................................  ...........        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
--------------------------------------------------------------------------------------------------------------------------------------------------------

                                                Table 13--Sundt 4: SO2 Control Option Cost-Effectiveness
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Capital     Annualized     Annual       Total       Emission    Cost-effectiveness  ($/
                                                                   cost       capital     operating   annual cost   reduction             ton)
                        Control option                        -------------     cost         cost    ---------------------------------------------------
                                                                           --------------------------
                                                                   ($)          ($)          ($)         ($/yr)       (tpy)         Ave      Incremental
--------------------------------------------------------------------------------------------------------------------------------------------------------
DSI..........................................................   $3,250,000     $306,777   $2,482,107   $2,788,884        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
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Pollution Control Equipment in use at Source: In the case of
SO2, Sundt Unit 4 does not operate with any existing control
technology. This is reflected in our selection of calendar year 2011 as
the baseline period, which represents uncontrolled coal-fired
emissions.
    Energy and Non-Air Quality Environmental Impacts: For wet FGD,
energy impacts include certain auxiliary power requirements that are
necessary to operate the wet FGD system and to potentially compensate
for pressure head loss through the scrubber. These energy impacts are
reflected as auxiliary power costs in the cost of compliance estimates.
Non-air quality environmental impacts include water usage requirements
and the storage and disposal of wet ash. Wet FGD requires very large
quantities of water to ensure proper control effectiveness. Securing
such quantities of water is a significant challenge in more arid
regions of the country such as Arizona, and would preclude the use of
that water for potentially more beneficial uses. The on-site storage
and disposal of wet ash in large retention ponds triggers significant
additional regulatory requirements, as it represents a substantial
water pollution threat.
    For dry FGD, the energy and non-air environmental impacts are
similar to those for wet FGD. Operation of a dry FGD system still
requires securing significant supplies of water, although to a lesser
degree than wet FGD systems. In addition, dry FGD systems will result
in generation of larger quantities of boiler ash, and has the potential
to affect negatively the properties and quality of boiler ash. In some
instances, boiler ash that is suitable to sell for beneficial purposes
may no longer be marketable following installation of a dry FGD system.
Energy impacts also include auxiliary power requirements for operation
of the dry FGD system, and for overcoming pressure head loss through
the scrubber. While 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 wet and dry FGD, we
do not consider these impacts sufficient enough to warrant eliminating
these control technologies.
    DSI could potentially have an adverse effect on the quality of the
boiler fly ash, which would make it unmarketable for beneficial uses.
Use of DSI also results in an ash byproduct which would require
landfill disposal, thereby increasing solid waste generation rates at
the plant. Energy impacts are limited to auxiliary power requirements
for operation of the DSI system. We do not consider these impacts
sufficient enough to warrant eliminating this control technology.
    Remaining Useful Life of the Source: We are considering the
remaining useful life of Sundt Unit 4 as one element of the overall
cost analysis as allowed by the BART Guidelines. Since we are not aware
of any federally- or State-enforceable shut down date for Sundt Unit 4,
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 Unit 4. 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.
    Degree of Visibility Improvement: The visibility improvement due to
SO2 controls is modest. As shown in Table 14, control via
DSI, with a 70 percent SO2 emissions reduction, gives a
maximum visibility improvement of 0.2 dv, which occurs at Saguaro.
Three other areas improve about half as much, and the cumulative
improvement is 0.8 dv. Emissions controls via dry and wet FGD were
modeled at 89 percent and 92 percent SO2 emissions
reduction, respectively. Both dry and wet FGD would cause a visibility
disbenefit at Saguaro as indicated by the negative improvements in
Table 14. The disbenefit is mainly due to the decreased stack exit
temperature and exit velocity associated with these technologies, and
more so for wet FGD than for dry FGD. These stack decreases result in
less plume rise and increased impacts nearby. At areas farther away,
the disbenefit is outweighed by the benefit of SO2
reductions from FGD. This issue is discussed further in the TSD. With
FGD, the maximum benefit occurs not at Saguaro, but at Galiuro, with
0.2 dv for dry FGD and 0.1 dv for wet FGD. The corresponding cumulative
improvements are 0.6 dv and 0.4 dv for dry and wet FGD, respectively,
including the areas of disbenefit. All these improvements are
substantially lower than those from DSI, and the visibility cost-
effectiveness of each FGD is more than quadruple that of DSI. EPA finds
that the improvement from DSI is substantial enough to support its
selection as BART, and that it is clearly a better choice than dry FGD
and wet FGD.

                     Table 14--Sundt 4: Visibility Impact and Improvement From SO2 Controls
----------------------------------------------------------------------------------------------------------------
                                                            Visibility             Visibility improvement
                                              Distance        impact      --------------------------------------
               Class I Area                     (km)    ------------------   DSI 70%      Dry FGD      Wet FGD
                                                            Base  case       (ctrl14)     (ctrl02)     (ctrl03)
----------------------------------------------------------------------------------------------------------------
Chiricahua NM.............................          144              0.43         0.05         0.07         0.06
Chiricahua Wild...........................          141              0.51         0.10         0.10         0.11
Galiuro Wild..............................           64              1.10         0.10         0.16         0.09
Gila Wild.................................          232              0.17         0.04         0.05         0.05
Mazatzal Wild.............................          203              0.19         0.07         0.08         0.09
Mount Baldy Wild..........................          232              0.15         0.05         0.05         0.06
Pine Mountain Wild........................          247              0.15         0.05         0.06         0.06
Saguaro NP................................           17              3.40         0.20        -0.16        -0.27
Sierra Ancha Wild.........................          178              0.19         0.06         0.08         0.08
Superstition Wild.........................          137              0.32         0.09         0.10         0.10
Cumulative (sum)..........................  ...........               6.6          0.8          0.6          0.4
Maximum...................................  ...........              3.40         0.20         0.16         0.11
 CIAs >= 0.5 dv..................  ...........                 3            0            0            0
Million $/dv (cumul. dv)..................  ...........  ................         $3.5        $16.4        $25.1
Million $/dv (max. dv)....................  ...........  ................          $14          $60          $97
----------------------------------------------------------------------------------------------------------------

c. BART Determination for SO2
    EPA proposes an emission limit of 0.23 lb/MMBtu on a 30-day (BOD)
rolling basis as BART to control SO2 from Sundt Unit 4. This
emission limit, equivalent to using DSI, is considered very cost-
effective at $1,857/ton. In evaluating the appropriate emission limit
for DSI, we have 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. To determine how to account for this
variability, we have examined the difference between the highest 30-day
rolling SO2 value and the highest annual average
SO2 value observed over the baseline period, which is
approximately 9 percent.\65\ We have applied this variability to the
annual average design value to develop a 30-day BOD rolling emission
limit, which we consider a sufficient margin for a limit that will
apply at all times. Please refer to Table 15 that provides a summary of
our five-factor BART analysis.
---------------------------------------------------------------------------

    \65\ See spreadsheet ``Sundt4 2001-12 Emission Calcs 2014-01-
24.xlsx'' in the docket.
---------------------------------------------------------------------------

    We propose to require compliance with this requirement within three
years of the effective date of the final rule. However, we are seeking
comment on whether this compliance date is reasonable and consistent
with the requirement of the Clean Air Act that BART be installed ``as
expeditiously as practicable but in no event later than five years
after [promulgation of the applicable FIP].'' \66\ If we receive
information during the comment period that establishes that a different
compliance time frame is appropriate, we may finalize a different
compliance date. We are also proposing regulatory text that includes
monitoring, reporting, and recordkeeping requirements associated with
this emission limit.
---------------------------------------------------------------------------

    \66\ Clean Air Act section 169A(g)(4), 42 U.S.C. 7491(g)(4).

                               Table 15--Sundt 4: Summary of BART Analysis for SO2
----------------------------------------------------------------------------------------------------------------
     Sundt Unit 4 (130 MW)        Baseline            DSI                  Dry FGD                Wet FGD
----------------------------------------------------------------------------------------------------------------
Emission Factor (lb/MMBtu)....        0.729  0.219................  0.08.................  0.06
Emission Rate (tpy)...........         2145  644..................  236..................  177
Emission Reduction (tpy)......  ...........  1,502................  1,909................  1,969
Control Effectiveness.........  ...........  70%..................  89%..................  92%
----------------------------------------------------------------------------------------------------------------
                                               Cost of Compliance
----------------------------------------------------------------------------------------------------------------
Capital Cost ($)..............  ...........  $3,250,000...........  $72,470,559..........  $80,629,663
Annualized Capital Cost ($)...  ...........  $306,777.............  $6,840,708...........  $7,610,870
Annual O&M ($)................  ...........  $2,482,107...........  $2,880,841...........  $3,227,467
Total Annual Cost ($).........  ...........  $2,788,884...........  $9,721,549...........  $10,838,337
Ave CE ($/ton)................  ...........  $1,857...............  $5,091...............  $5,505
Incremental CE ($/ton)........  ...........  .....................  $23,081..............  $18,795
----------------------------------------------------------------------------------------------------------------
                                  Pollution Control Equipment in Use at Source
----------------------------------------------------------------------------------------------------------------
There is no existing control technology for SO2
----------------------------------------------------------------------------------------------------------------
                                Energy and Non-Air Quality Environmental Impacts
----------------------------------------------------------------------------------------------------------------
Energy impacts are reflected in annual O&M costs in the costs of compliance.
----------------------------------------------------------------------------------------------------------------
Wet ash from wet and dry FGD represents a substantial water pollution threat.
----------------------------------------------------------------------------------------------------------------
Water resources for wet and dry FGD may preclude more beneficial uses of water.
----------------------------------------------------------------------------------------------------------------
                                              Remaining Useful Life
----------------------------------------------------------------------------------------------------------------
Control technology              ...........  20 years.............  20 years.............  20 years
 amortization period.
----------------------------------------------------------------------------------------------------------------

                                             Visibility Improvement
----------------------------------------------------------------------------------------------------------------
Single largest Class I area     ...........  0.20.................  0.16.................  0.11
 improvement (dv).
Single Class I area cost-       ...........  $14.3................  $60.4................  $96.8
 effectiveness (million $/dv).
Class I areas with >= 0.50 dv   ...........  0....................  0....................  0
 improvement.
Cumulative visibility           ...........  0.8..................  0.6..................  0.4
 improvement (dv).
Cumulative cost-effectiveness   ...........  $3.5.................  $16.4................  $25.1
 (million $/dv).
----------------------------------------------------------------------------------------------------------------

 3. Proposed BART Analysis and Determination for PM10
a. Control Technology Availability, Technical Feasibility, and
Effectiveness
    Sundt Unit 4 currently operates with a fabric filter baghouse for
particulate control, which is considered the most stringent control
device for particulate matter. These devices operate on the same
principle as a vacuum cleaner. Air carrying dust particles is forced
through a cloth bag that is designed and manufactured to trap particles
greater than a certain specified diameter. As the air passes through
the fabric, the dust accumulates on the cloth and is removed from the
air stream. The accumulated dust is periodically removed from the cloth
by shaking or by reversing the air flow. The layer of dust, known as
dust cake, trapped on the surface of the fabric has the potential to
result in high efficiency rates for particles ranging in size from
submicron to several hundred microns in diameter.
b. BART Analysis for PM10
    The BART Guidelines provide that, where a source has controls
already in place that are the most stringent controls available, it is
not necessary to complete comprehensively a full five-factor BART
analysis, as long the most stringent controls available are made