
[Federal Register Volume 79, Number 170 (Wednesday, September 3, 2014)]
[Rules and Regulations]
[Pages 52419-52498]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-15895]



[[Page 52419]]

Vol. 79

Wednesday,

No. 170

September 3, 2014

Part II





Environmental Protection Agency





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40 CFR Part 52





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

  Federal Register / Vol. 79 , No. 170 / Wednesday, September 3, 2014 / 
Rules and Regulations  

[[Page 52420]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R09-OAR-2013-0588; FRL-9912-97-OAR]


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This final action promulgates a Federal Implementation Plan 
(FIP) addressing 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 a final rule published in the Federal Register on July 30, 
2013. In that action, we partially approved and partially disapproved 
the State's plan to implement the regional haze program for the first 
planning period. This final action includes our responses to comments 
on our proposed FIP published in the Federal Register on February 18, 
2014. This final rule, together with a final rule published in the 
Federal Register on December 5, 2012, completes our FIP for the 
disapproved portions of Arizona's RH SIP. This final rule addresses the 
RHR's requirements for Best Available Retrofit Technology (BART), 
Reasonable Progress (RP), and a Long-term Strategy (LTS) as well as the 
interstate visibility transport requirements of the Clean Air Act (CAA) 
for pollutants that affect visibility in Arizona's 12 Class I areas and 
areas in nearby states. The BART sources addressed in this final FIP 
are Tucson Electric Power (TEP) Sundt Generating Station Unit 4, Lhoist 
North America (LNA) Nelson Lime Plant Kilns 1 and 2, ASARCO 
Incorporated Hayden Smelter, and Freeport-McMoRan Incorporated (FMMI) 
Miami Smelter. The reasonable progress sources addressed in the FIP are 
Phoenix Cement Company (PCC) Clarkdale Plant Kiln 4 and CalPortland 
Cement (CPC) Rillito Plant Kiln 4. EPA is prepared to work with the 
State on a SIP revision that would replace some or all elements of the 
FIP.

DATES: Effective Date: This rule is effective October 3, 2014.

ADDRESSES: EPA has established docket number EPA-R09-OAR-2013-0588 for 
this action. Generally, documents in the docket are available 
electronically at http://www.regulations.gov or in hard copy at EPA 
Region 9, 75 Hawthorne Street, San Francisco, California. Please note 
that while many of the documents in the docket are listed at http://www.regulations.gov, some information may not be specifically listed in 
the index to the docket and may be publicly available only at the hard 
copy location (e.g., copyrighted material, large maps, multi-volume 
reports, or otherwise voluminous materials), and some may not be 
available at either locations (e.g., confidential business 
information). To inspect the hard copy materials, please schedule an 
appointment during normal business hours with the contact listed 
directly below.

FOR FURTHER INFORMATION CONTACT: Thomas Webb, U.S. EPA, Region 9, 
Planning Office, Air Division, Air-2, 75 Hawthorne Street, San 
Francisco, CA 94105. Thomas Webb may be reached at telephone number 
(415) 947-4139 and via electronic mail at r9azreghaze@epa.gov.

SUPPLEMENTARY INFORMATION: 

Table of Contents

I. Introduction
II. History of State and Federal Plans
    A. State Submittals and EPA Actions
    B. EPA's Authority To Promulgate a FIP
III. Summary of Proposed Rule
    A. Regional Haze
    B. Interstate Transport of Pollutants That Affect Visibility
IV. Overview of Final Action
    A. BART Determinations
    B. Reasonable Progress Determinations
    C. Reasonable Progress Goals and Demonstration
    D. Long-Term Strategy
    E. Interstate Visibility Transport
    F. Other Changes From Proposal
V. Responses to General Comments
    A. Introduction
    B. Comments on State and EPA Actions on Regional Haze
    C. Comments on State and Federal Roles in the Regional Haze 
Program
VI. Responses to Comments on EPA's Proposed BART Determinations
    A. Comments on Sundt Generating Station Unit 4
    B. Comments on Nelson Lime Plant Kilns 1 and 2
    C. Comments on the Hayden Smelter
    D. Comments on the Miami Smelter
VII. Responses to Comments on EPA's Proposed Reasonable Progress 
Determinations
    A. Comments on Phoenix Cement Clarkdale Plant
    B. Comments on CalPortland Cement Rillito Plant
    C. Comments on Other Reasonable Progress NOX Point 
Sources
    D. Comments on Area Sources of NOX and SO2
    E. Comments on Reasonable Progress Goals and Uniform Rate of 
Progress
    F. Other Comments on Reasonable Progress
VIII. Responses to Comments on Statutory and Executive Order Reviews
IX. Responses to Other Comments
    A. Comments on Preamble Language
    B. Comments on Rule Language
    C. Comments on Other Benefits of the Regional Haze Program
    D. Miscellaneous Comments
X. Summary of Final Action
    A. Regional Haze
    B. Interstate Transport
XI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory 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 Concerning Regulations 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
    L. Petitions for Judicial Review

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 initials CAMD mean or refer to Clean Air Markets 
Division at EPA.
    (8) The initials CBI mean or refer to confidential business 
information.
    (9) The term Class I area refers to a mandatory Class I Federal 
area.
    (10) The initials CEMS refers to continuous emission monitoring 
system or systems.
    (11) The initials CRP mean or refer to converter retrofit 
project.
    (12) The initials dv mean or refer to deciview, a measure of 
visual range.
    (13) The initials DOE mean or refer to United States Department 
of Energy.
    (14) The initials ESECA mean or refer to Energy Supply and 
Environmental Coordination Act of 1974.
    (15) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
    (16) The initials FGD mean or refer to flue gas desulfurization.
    (17) The initials FIP mean or refer to Federal Implementation 
Plan.

[[Page 52421]]

    (18) The initials FLM mean or refer to Federal Land Managers.
    (19) The initials FUA mean or refer to Fuel Use Act of 1978.
    (20) The initials IMPROVE mean or refer to Interagency 
Monitoring of Protected Visual Environments monitoring network.
    (21) The initials IPM mean or refer to Integrated Planning 
Model.
    (22) The term lb/MMBtu means or refers to pounds per one million 
British thermal units.
    (23) The initials LDSCR and HDSCR mean or refer to low and high 
dust Selective Catalytic Reduction, respectively.
    (24) The initials LNB mean or refer to low NOX 
burners.
    (25) The initials LTS mean or refer to Long-term Strategy.
    (26) The initials MACT mean or refer to Maximum Achievable 
Control Technology.
    (27) The initials MW mean or refer to megawatts.
    (28) The initials NAAQS mean or refer to National Ambient Air 
Quality Standard or Standards.
    (29) The initials NEI mean or refer to National Emissions 
Inventory.
    (30) The initials NESCAUM mean or refer to Northeast States for 
Coordinated Air Use Management.
    (31) The initials NESHAP mean or refer to National Emission 
Standards for Hazardous Air Pollutants.
    (32) The initials NOX mean or refer to nitrogen 
oxides.
    (33) The initials NP mean or refer to National Park.
    (34) The initials NPS mean or refer to the National Park 
Service.
    (35) The initials NSCR mean or refer to Non-Selective Catalytic 
Reduction.
    (36) The initials NSPS mean or refer to new source performance 
standards.
    (37) The initials OFA mean or refer to Over Fire Air.
    (38) The initials PM mean or refer to particulate matter.
    (39) The initials PM2.5 mean or refer to fine particulate matter 
with an aerodynamic diameter of less than 2.5 micrometers.
    (40) The initials PM10 mean or refer to particulate matter with 
an aerodynamic diameter of less than 10 micrometers.
    (41) The initials PSD mean or refer to Prevention of Significant 
Deterioration.
    (42) The initials PTE mean or refer to potential to emit.
    (43) The initials RH mean or refer to regional haze.
    (44) The initials RHR mean or refer to the Regional Haze Rule, 
originally promulgated in 1999 and codified at 40 CFR 51.308-309.
    (45) The initials RMC mean or refer to Regional Modeling Center.
    (46) The initials RP mean or refer to Reasonable Progress.
    (47) The initials RPG or RPGs mean or refer to Reasonable 
Progress Goal(s).
    (48) The initials SCR mean or refer to Selective Catalytic 
Reduction.
    (49) The initials SIP mean or refer to State Implementation 
Plan.
    (50) The initials SNCR mean or refer to Selective Non-catalytic 
Reduction.
    (51) The initials SO2 mean or refer to sulfur dioxide.
    (52) The initials SOFA mean or refer to Separated Over Fire Air.
    (53) The initials SRP mean or refer to Salt River Project 
Agricultural Improvement and Power District.
    (54) The initials tpy mean tons per year.
    (55) The initials TSD mean or refer to Technical Support 
Document.
    (56) The initials TSF mean or refer to tons of stone feed.
    (57) The initials ULNB mean or refer to ultra-low NOX 
burners.
    (58) The initials URP mean or refer to Uniform Rate of Progress.
    (59) The initials VOC mean or refer to volatile organic 
compounds.
    (60) The initials VRP mean or refer to Visibility Restoration 
Plan.
    (61) The initials WRAP mean or refer to the Western Regional Air 
Partnership.

I. Introduction

    The purpose of the Federal and state regional haze plans is to 
achieve a national goal, declared by Congress, of restoring and 
protecting visibility at 156 Federal class I areas across the United 
States, most of which are national parks and wilderness areas with 
scenic vistas enjoyed by the American public. The national goal as 
described in CAA Section 169A is ``the prevention of any future, and 
the remedying of any existing, impairment of visibility in mandatory 
class I Federal areas which impairment results from man-made air 
pollution.'' Arizona has 12 Class I areas, including some of the most 
magnificent natural areas in our country. Five other Class I areas are 
close by in neighboring states. Please refer to our previous rulemaking 
on the Arizona RH SIP for additional background information 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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    EPA has previously acted to approve a number of elements of the 
Arizona RH SIP, and to disapprove others. In today's final action, EPA 
is reducing harmful emissions from six facilities that contribute to 
visibility impairment in 17 protected national parks and wilderness 
areas in Arizona and neighboring states. Four of the facilities are 
subject to Best Available Retrofit Technology (BART) controls for 
emissions of nitrogen oxides (NOX), sulfur dioxide 
(SO2), and particulate matter (PM). The other two facilities 
are subject to limits on their NOX emissions pursuant to the 
Reasonable Progress (RP) provisions of the Regional Haze Rule (RHR). 
The BART sources are Sundt Generating Station Unit 4, Nelson Lime Plant 
Kilns 1 and 2, Hayden Smelter, and Miami Smelter. The RP sources are 
the Phoenix Cement Clarkdale Plant Kiln 4 and CalPortland Cement 
Rillito Plant Kiln 4. EPA is promulgating this partial FIP because we 
found that Arizona had failed to submit a complete RH SIP, and later 
disapproved portions of Arizona's RH SIP for not meeting all the 
requirements of the CAA and EPA's RHR.
    EPA has worked with the owners and operators of the facilities 
regulated by today's rule to ensure we have the most up-to-date 
information for making decisions on BART, RP, and the Long-Term 
Strategy (LTS), the three major requirements of the RHR. In today's 
notice, we respond to comments on our proposed rule, present our 
analysis, and indicate where we have made adjustments based on the 
comments and additional information. The required emission limits, 
compliance methods, and deadlines for compliance in our final rule are 
compatible with each facility's operations, and provide sufficient 
flexibility for achieving compliance in a reasonable period of time. In 
several instances we have adjusted the emission limits, averaging times 
and/or compliance deadlines in response to additional information 
supplied by the facilities' owners or operators. Further, in the case 
of TEP Sundt Unit 4, we have included an alternative to BART controls 
suggested by the facility's owner, which provides better emission 
reductions to improve visibility.
    Given the combination of State and Federal plans to implement the 
regional haze program in Arizona, EPA and the Arizona Department of 
Environmental Quality (ADEQ) must continue to rely on their 
historically strong partnership under the CAA to protect the 
environment and human health. We would welcome a State plan to replace 
some or all of the Federal plan. Moreover, we commit our resources to 
ensuring a successful regional haze program for Arizona. EPA estimates 
today's action will result in annual emission reductions of about 2,900 
tons/year of NOX and 29,300 tons/year of SO2. 
These reductions are expected to benefit at least 17 Class I areas in 
four states, including Arizona.

II. History of State and Federal Plans

A. State Submittals and EPA Actions

    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.\2\ Specifically, EPA found that Arizona 
failed to submit the plan elements required by 40 CFR 51.309(d)(4) and 
(g). In 2011 ADEQ submitted a SIP under section 308 of the

[[Page 52422]]

RHR, but did not withdraw its 309 SIP. EPA disapproved Arizona's 309 
SIP (with the exception of several smoke management rules) on August 8, 
2013.\3\ Both of the Arizona RH SIPs are available to review in the 
docket for this final rule.\4\
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    \2\ 74 FR 2392.
    \3\ 78 FR 48326.
    \4\ ``Arizona State Implementation Plan, Regional Haze under 
Section 308 of the Federal Regional Haze Rule,'' February 28, 2011.
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    As shown in Table 1, 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 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 tpy. 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. 
Subsequently, ADEQ submitted a supplement to the Arizona RH SIP (``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 SIP Supplement. Our final 
rule approving in part and disapproving in part the Arizona RH SIP was 
published on July 30, 2013. In the third phase of our action, we 
proposed a FIP on February 18, 2014, to address the remaining 
disapproved portions of the State's plan, which we are finalizing 
today.

                              Table 1--EPA's Actions on the Arizona RH SIP and FIP
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----------------------------------------------------------------------------------------------------------------
                     EPA actions              Federal Register
                                 -------------------------------------------------------------------------------
                                                          Proposed rule                  Final rule
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Phase 1:
    SIP, FIP....................  BART determinations  July 20, 2012 (77    December 5, 2012 (77 FR 72512).
                                   for Apache, Cholla   FR 42834).
                                   and Coronado.
Phase 2:
    SIP.........................  Partial approval     December 21, 2012    July 30, 2013 (78 FR 46142).
                                   and partial          (77 FR 75704), May
                                   disapproval of       20, 2013 (78 FR
                                   remaining elements   29292).
                                   of the SIP,
                                   including SIP
                                   Supplement.
Phase 3:
    FIP.........................  FIP for remaining    February 18, 2014    Today's Final Action.
                                   disapproved          (79 FR 9318).
                                   elements of the
                                   SIP.
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B. EPA's Authority To Promulgate a FIP

    Under CAA section 110(c), EPA is required to promulgate a FIP at 
any time within 2 years of the effective date of a finding that a state 
has failed to make a required SIP submission or has made an incomplete 
submission, or of the date that EPA disapproves a SIP. The FIP 
requirement is terminated only if a state submits a SIP, and EPA 
approves that SIP as meeting applicable CAA requirements before 
promulgating a FIP. Specifically, CAA section 110(c) provides that EPA 
``shall promulgate'' a FIP ``at any time within 2 years'' after finding 
that ``a State has failed to make a required submission'' or that the 
SIP or SIP revision submitted by the State does not satisfy the minimum 
criteria established under CAA section 110(k)(1)(A), or after 
disapproving a SIP in whole or in part ``unless the State corrects the 
deficiency'' EPA approves the plan or plan revision before promulgating 
a FIP.
    Section 302(y) defines the term ``Federal implementation plan'' in 
pertinent part, as a plan (or portion thereof) promulgated EPA ``to 
fill all or a portion of a gap or otherwise correct all or a portion of 
an inadequacy'' in a SIP, 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).
    In the case of the Arizona RH SIP, two different triggering events 
have occurred under section 110(c). EPA has made a finding that the 
State failed to make a required submission,\5\ and we have partially 
disapproved the submissions that the State subsequently made. 
Therefore, EPA is required under CAA section 110(c) to promulgate a FIP 
for the portions of the Arizona RH SIP that we disapproved on July 30, 
2013.
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    \5\ 74 FR 2392-93 (January 15, 2009).
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III. Summary of Proposed Rule

    In this section, we provide a summary of the proposed rule that was 
published in the Federal Register on February 18, 2014,\6\ as 
background for understanding today's final action.
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    \6\ 79 FR 9318-9378.
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A. Regional Haze

    Our proposed rule included proposed BART determinations for four 
sources and proposed RP determinations for nine sources. These 
determinations resulted in proposed emission limits, compliance 
schedules, and other requirements for four BART sources and two of the 
RP sources. The proposed regulatory language was included under Part 52 
at the end of that document. We also addressed the reasonable progress 
goals (RPGs), as well as the requirements of the LTS. Lastly, we 
proposed that the approved measures in the Arizona RH SIP, and measures 
in our previously promulgated FIP and proposed FIP, would adequately 
address the interstate transport of pollutants that affect visibility.
1. Proposed BART Determinations
    Sundt Generating Station Unit 4: EPA proposed to find that Sundt 
Unit 4 is BART-eligible and subject to BART for NOX, 
SO2, and particulate matter of less than 10 micrometers 
(PM10). For NOX, we proposed an emission limit of 
0.36 lb/MMBtu as BART, which is consistent with the use of Selective 
Non-Catalytic Reduction (SNCR) as a control technology. For 
SO2, we proposed an emission limit of 0.23 lb/MMBtu as BART 
on a 30-day boiler operating day (BOD) rolling basis, which is 
consistent with the use of dry sorbent injection (DSI) as a control 
technology. For PM10, we proposed a filterable 
PM10 emission limit of 0.030 lb/MMBtu as BART based on the 
use of the unit's existing fabric filter baghouse. We also proposed a 
switch to natural gas as a better-than-BART alternative to the proposed 
BART controls for all three pollutants.
    Nelson Lime Plant Kilns 1 and 2: EPA proposed to find that Nelson 
Lime Kilns 1 and 2 are subject to BART for NOX, 
SO2, and PM10. For NOX, we proposed a 
BART emission limit at Kiln 1 of 3.80

[[Page 52423]]

lb/ton of lime and at Kiln 2 of 2.61 lb/ton of lime on a 30-day rolling 
basis as verified by continuous emission monitoring systems (CEMS). 
These emission limits are consistent with the use of low-NOX 
burners (LNB) and SNCR as control technologies. We proposed that BART 
for SO2 is an emission limit of 9.32 lb/ton of lime for Kiln 
1 and 9.73 lb/ton of lime for Kiln 2 on a 30-day rolling basis, which 
is consistent with the use of a lower sulfur fuel blend. For 
PM10, we proposed a BART emission limit of 0.12 lb/tons of 
stone feed (TSF) at Kilns 1 and 2 based on the use of the unit's 
existing fabric filter baghouses.
    Hayden Smelter: EPA proposed that the Hayden Smelter is subject to 
BART for NOX, and we proposed BART emission limits for 
NOX and SO2. We previously approved the State's 
determination that the Hayden Smelter is subject to BART for 
SO2, but disapproved the State's SO2 BART 
determination. For NOX, we proposed an annual emission limit 
of 40 tons per year (tpy) of NOX emissions from the BART-
eligible units, which is consistent with current emissions from these 
units. For SO2 from the converters, we proposed 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 proposed a work practice 
standard requiring that the furnaces be charged only 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 proposed to incorporate the emission limits and 
associated compliance requirements of the Maximum Achievable Control 
Technology (MACT),\7\ Subpart QQQ, as part of the LTS.
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    \7\ National Emission Standard for Hazardous Air Pollutants for 
Primary Copper Smelting at 40 CFR Part 63.
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    Miami Smelter: EPA proposed that the Miami Smelter is subject to 
BART for NOX, and we proposed BART emission limits for 
NOX and SO2. EPA previously approved the State's 
determination that the Miami Smelter is subject to BART for 
SO2, but disapproved the State's SO2 BART 
determination. For NOX, we proposed 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 proposed 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 Subpart QQQ requirements to the capture systems. For 
SO2 emissions from the electric furnace, we proposed as BART 
a work practice standard to prohibit active aeration. We previously 
approved Arizona's determination that BART for PM10 at the 
Miami Smelter is the MACT for Primary Copper Smelting. We proposed to 
find that the federally enforceable provisions of the MACT, which apply 
to the Miami Smelter and are incorporated into its Title V Permit, are 
sufficient to ensure the enforceability of this determination.
2. Proposed RP Determinations
    Point Sources of NOX: EPA conducted source-specific RP analyses of 
potential NOX controls for non-BART units at nine different 
sources. Based on these analyses, we proposed to require controls on 
two cement kilns: PCC Clarkdale Kiln 4 and CPC Rillito Kiln 4. 
Specifically, EPA proposed an emission limit of 2.12 lb/ton on Kiln 4 
of the Clarkdale Plant based on a 30-day rolling average, which is 
consistent with SNCR as a control technology. We proposed an emission 
limit of 2.67 lb/ton on Kiln 4 of the Rillito Plant based on a 30-day 
rolling average, which also is consistent with SNCR as a control 
technology. We also requested comment on the possibility of requiring a 
rolling 12-month limit on NOX emissions in lieu of a lb/ton 
emission limit at these facilities. For the remaining seven sources, as 
well as other units at CPC, we proposed to find that it was reasonable 
not to require NOX controls during this planning period. 
These sources are the CPC Rillito Plant (Kilns 1-3); Arizona Public 
Service (APS) Cholla (Unit 1); El Paso Natural Gas (EPNG) Tucson, 
Flagstaff, and Williams Compressor Stations; TEP Sundt (Units 1-3); Ina 
Road Sewage Plant; and TEP Springerville (Units 1 and 2).
    Area Sources of NOX and SO2: We proposed to find that it is 
reasonable not to require additional controls on area 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. While the 
State's area sources currently contribute a relatively small percentage 
of the visibility impairment at impacted Class I areas, we recommended 
better emission inventories and an improved RP analysis in the next 
planning period for area sources.
    Reasonable Progress Goals: EPA proposed RPGs consistent with a 
combination of control measures that include those in the approved 
portion of the Arizona RH SIP and in EPA's finalized and proposed FIPs. 
While not quantifying a new set of RPGs based on these control 
measures, we proposed that it is reasonable to assume improved levels 
of visibility at Arizona's 12 Class I areas by 2018 because the 
measures in the FIPs produce emissions reductions that are 
significantly beyond those required by the State.
    Demonstration of Reasonable Progress: EPA proposed to find that it 
is reasonable not to provide for rates of progress at the 12 Class I 
areas consistent with the uniform rate of progress (URP) in this 
planning period.\8\ We also proposed to find that the RP analyses 
underlying our actions on the Arizona RH SIP \9\ and FIP are sufficient 
to demonstrate that it is reasonable not to provide for rates of 
progress in this planning period that would attain natural conditions 
by 2064.\10\ Lastly, we 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.\11\
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    \8\ 40 CFR 51.308(d)(1)(ii).
    \9\ See proposed actions at 77 FR 75727-75730, 78 FR 29297-
292300 and final action at 78 FR 46172.
    \10\ 40 CFR 51.308(d)(1)(ii).
    \11\ 78 FR 46172.
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3. Long-Term Strategy
    EPA proposed to find that provisions in the Arizona RH SIP and FIP 
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, emission 
limitations and schedules for compliance to achieve the RPGs, and 
enforceability provisions for emission limitations and control 
measures.\12\ We proposed to promulgate emission limits, compliance 
schedules, and other requirements for four BART sources and two RP 
sources to complete this part of the FIP for these requirements.
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    \12\ See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)).
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B. Interstate Transport of Pollutants That Affect Visibility

    We have proposed 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

[[Page 52424]]

provisions to prohibit emissions that will interfere with other states' 
required measures to protect visibility. We refer to this as the 
interstate transport visibility requirement.

IV. Overview of Final Action

    We are promulgating a FIP to address the remaining disapproved 
portions of the Arizona RH SIP.\13\ We include in Section V below a 
summary of our responses to comments on our proposed FIP,\14\ and 
describe where comments resulted in revisions to the proposal. In this 
section, we provide a summary of the final BART determinations, RP 
determinations, RPGs and demonstration, LTS provisions, and interstate 
transport provisions of the FIP. This final FIP also includes emission 
limits, compliance schedules and requirements for equipment 
maintenance, monitoring, testing, recordkeeping, and reporting for all 
affected sources and units. The final regulatory language for the FIP 
is under Part 52 at the end of this notice.
---------------------------------------------------------------------------

    \13\ 78 FR 46142 (July 30, 2013).
    \14\ 79 FR 9318 (February 18, 2014).
---------------------------------------------------------------------------

A. BART Determinations

    EPA conducted BART analyses and determinations for four sources: 
Sundt Generating Station Unit 4, Nelson Lime Plant Kilns 1 and 2, the 
Hayden Smelter, and the Miami Smelter. The final BART determinations 
are listed in Table 2, comparing the final limits to the proposed 
limits with short descriptions of changes in the footnotes. The exact 
compliance deadlines will be calculated based upon the date that this 
document is published in the Federal Register, which we anticipate will 
occur sometime in July 2014.
    Sundt Generating Station: In this final rule, we have retained the 
BART determination and the final BART emission limits as proposed, as 
well as the option of a better-than-BART alternative that was submitted 
by TEP. Although the final BART determination and limits are the same, 
we have made some changes to the better-than-BART alternative based on 
comments and additional information.
    Regarding BART, we are finalizing our determination that Sundt Unit 
4 is BART-eligible and subject to BART for SO2, 
NOX, and PM10. The final BART emission limits are 
the same as proposed. The NOX emission limit is 0.36 lb/
MMBtu, which is equivalent to using SNCR with the existing LNB as 
control technologies. The SO2 emission limit is 0.23 lb/
MMBtu on a 30-day BOD rolling basis, which is consistent with using DSI 
as a control technology. The PM10 emission limit is 0.030 
lb/MMBtu based on the use of the existing fabric filter baghouse. 
Compliance is required within three years of the publication of this 
notice in the Federal Register, also as proposed.
    Regarding the better-than-BART alternative to switch to natural 
gas, we are finalizing the proposed emission limit for NOX 
of 0.25 lb/MMBtu, but revising the SO2 and PM10 
emission limits. The final SO2 limit is increased from 
0.00064 to 0.054 lb/MMBtu to allow for continued co-firing with 
landfill gas that has a higher sulfur content than pipeline natural 
gas. The final PM10 limit relies on a performance test due 
to the uncertainties related to switching from coal to gas, which now 
includes measuring condensable, in addition to filterable, 
PM10. Further, we have extended the final compliance 
deadline by six months to December 31, 2017, consistent with the date 
that TEP initially included in its better-than-BART proposal. TEP is 
required to notify EPA regarding its selection of BART or the 
alternative by March 2017.
    Nelson Lime Plant: EPA is finalizing its determination that Nelson 
Lime Plant Kilns 1 and 2 are subject to BART for NOX, 
SO2, and PM10. We have revised the final emission 
limits for NOX and SO2 to account for startup and 
shutdown emissions, which were not considered in LNA's original BART 
analysis that was submitted to EPA for consideration. This change to 
the emission limits for NOX and SO2 does not 
change the corresponding control technologies, which are still SNCR and 
lower sulfur fuel, respectively. The final BART emission limit for 
PM10 is 0.12 lb/ton for each kiln as proposed, equivalent to 
using the existing baghouse.
    We are making the following revisions to the NOX limits 
in response to comments received on our proposal. First, we are 
revising the averaging time for the lb/ton limits to a 12-month rolling 
average instead of a 30-day rolling average. The longer 12-month 
averaging time should even out the emission spikes from startup and 
shutdown events that would more significantly influence a 30-day 
average. Second, we are requiring an optimization plan to assess the 
final BART emission limit for NOX based on a 12-month 
rolling average, which is 3.80 lb/ton for Kiln 1 and 2.61 lb/ton for 
Kiln 2. Third, we are adding a combined limit for Kilns 1 and 2 of 3.27 
tons/day on a 30-day rolling average to ensure short-term visibility 
protection. Both compliance methods (lb/ton at each kiln as optimized 
and tons/day for both kilns) are equivalent to using SNCR control 
technology. The compliance deadline for the final NOX 
emission limit is three years from the publication date, as proposed.
    We are making the following revisions to the SO2 limits 
in response to comments received on our proposal. First, as with the 
final limit for NOX, we are revising the averaging time for 
the lb/ton limits to a 12-month rolling average instead of a 30-day 
rolling average to account for emission spikes from startup and 
shutdown events that would more significantly influence a 30-day 
average. The final BART emission limits for SO2 are 9.32 lb/
ton for Kiln 1 and 9.73 lb/ton for Kiln 2, as proposed. Second, we are 
adding a combined limit for Kilns 1 and 2 of 10.1 tons/day to ensure 
short-term visibility protection. Both compliance methods (lb/ton at 
each kiln and tons/day at both kilns) are equivalent to using lower 
sulfur fuel, as proposed. Finally, we have extended the compliance 
deadline for meeting the final limit for SO2 from six to 18 
months to allow sufficient time for installation of monitoring 
equipment to demonstrate compliance with the new limits.
    Hayden Smelter: EPA is finalizing its determination that the Hayden 
Smelter is subject to BART for NOX. We previously approved 
the State's determination that the Hayden Smelter is subject to BART 
for SO2 and PM10, and the State's determination 
that BART for PM10 is equivalent to existing controls. The 
final BART emission limit for NOX is 40 tpy and applies to 
the converters and anode furnaces. The NOX limit is 
consistent with current emissions and is the same as proposed. The 
final BART emission limit for SO2 from the anode furnaces is 
equivalent to existing controls, as proposed. For PM10, we 
are incorporating by reference provisions of the National Emission 
Standards for Hazardous Air Pollutants (NESHAP) for primary copper 
smelters \15\ to ensure that Arizona's BART determination is made 
enforceable, as part of the LTS.
---------------------------------------------------------------------------

    \15\ 40 CFR part 63 subpart QQQ.
---------------------------------------------------------------------------

    We are making a number of revisions to the proposed SO2 
emission limits from the converters in response to comments. For 
SO2 emissions from the converters, the final BART emission 
limits are a 99.8 percent control efficiency on a 365-day rolling 
average for the primary capture system, and a 98.5 percent control 
efficiency on a 365-day rolling average for the secondary capture 
system. The BART limit for the primary capture system corresponds to 
the existing double contact acid plant, whereas the limit for the 
secondary capture system is equivalent to a new

[[Page 52425]]

amine scrubber as a control technology. We have revised our proposal by 
applying separate limits to the primary and secondary capture systems 
in recognition of significant differences in flow volume and 
SO2 concentration between the two systems. We revised the 
averaging time from 30 to 365 days for the primary capture system in 
recognition that the control efficiency is based on annual acid 
production and annual SO2 emissions. In addition, we are 
finalizing a work practice standard requiring that the primary and 
secondary capture systems be designed and operated to maximize capture 
of SO2 emissions from the converters.
    The final compliance deadline for the primary capture and control 
system to meet the SO2 limit is three years from 
publication, as proposed. The final deadlines for the NOX 
and PM10 limits are also three years from publication. 
However, we extended the final compliance deadline to meet the 
SO2 limit for the secondary capture and control system from 
three to four years from publication to provide sufficient time to plan 
and build a new amine scrubber.
    Miami Smelter: EPA is finalizing its determination that the Miami 
Smelter is subject to BART for NOX. We previously approved 
the State's determination that the Miami Smelter is subject to BART for 
SO2 and PM10, and the State's determination that 
BART for PM10 is equivalent to the National Emission 
Standard for Hazardous Air Pollutants (NESHAP) for primary copper 
smelters. The final BART emission limit for NOX is 40 tpy 
that applies to the converters and electric furnace. The NOX 
limit represents current emissions and is the same as proposed. For 
SO2 from the electric furnace, the final BART emission limit 
is the existing work practice standard to prohibit active aeration. For 
PM10, we are incorporating by reference provisions of the 
NESHAP for primary copper smelters \16\ to ensure that Arizona's BART 
determination is made enforceable, as part of the LTS.
---------------------------------------------------------------------------

    \16\ 40 CFR part 63 subpart QQQ.
---------------------------------------------------------------------------

    For SO2 from the converters, the final BART emission 
limit is a control efficiency of 99.7 percent on a 365-day rolling 
average applied to the combined primary and secondary capture systems 
on a cumulative mass basis. While the control efficiency of 99.7 
percent is the same as proposed, we revised the compliance method from 
a 30-day average to a 365-day rolling average. We revised the averaging 
time in response to FMMI's comment that the control efficiency is based 
on annual acid production and annual SO2 emissions. The 99.7 
percent control efficiency is equivalent to improvements to the primary 
control system (existing acid plant with a tailstack scrubber) and 
construction of new secondary capture and control systems. In addition, 
we are finalizing a work practice standard requiring that the primary 
and secondary capture systems be designed and operated to maximize 
capture of SO2 emissions from the converters.
    The final compliance deadlines for SO2 from the electric 
furnace as well as the NOX and PM10 limits, are 
two years from the date of the document's publication. However, we 
extended the final compliance deadline for SO2 from the 
converters to January 1, 2018, to provide sufficient time to plan and 
build a new secondary capture and control system. We also added a 
compliance option for the secondary capture system to use either CEMS 
or to calculate emissions based on the amount of reagent added to the 
scrubber, because it may be impractical to operate CEMS on the inlet of 
a new scrubber.

                                                     Table 2--Final Emission Limits on BART Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Proposed                                             Corresponding control
              Source                       Units             Pollutants        limit         Final  limit           Measure              technology
--------------------------------------------------------------------------------------------------------------------------------------------------------
Sundt Generating Station.........  Unit 4..............  NOX                       0.36  Same...............  lb/MMBtu...........  Selective Non-
                                                         SO2                       0.23  Same...............  ...................   Catalytic Reduction.
                                                         PM10                     0.030  Same...............  ...................  Dry Sorbent
                                                                                                                                    Injection.
                                                                                                                                   Fabric filter
                                                                                                                                    baghouse (existing).
                                   Unit 4 Alternative..  NOX                       0.25  Same...............  lb/MMBtu...........  Switch to natural
                                                         SO2                    0.00064  0.054.\a\..........                        gas.
                                                         PM10                     0.010  Test.\b\...........
Nelson Lime Plant................  Kiln 1..............  NOX                       3.80  Same \c\...........  lb/ton \d\.........  Selective Non-
                                                                                         3.27...............  tons/day \e\.......   Catalytic Reduction.
                                                         SO2                       9.32  Same...............  lb/ton.\d\.........  Lower sulfur fuel.
                                                                                         10.1...............  tons/day.\e\.......
                                                         PM10                      0.12  Same...............  lb/ton.............  Fabric filter
                                                                                                                                    baghouse (existing).
                                   Kiln 2..............  NOX                       2.61  Same \c\...........  lb/ton \d\.........  Selective Non-
                                                                                         3.27...............  tons/day.\e\.......   Catalytic Reduction.
                                                         SO2                       9.73  Same...............  lb/ton \d\.........  Lower sulfur fuel.
                                                                                         10.1...............  tons/day.\e\.......
                                                         PM10                      0.12  Same...............  lb/ton.............  Fabric filter
                                                                                                                                    baghouse (existing).
Hayden Smelter...................  All BART Units......  NOX                         40  Same...............  tpy................  None.
                                   Converters 1, 3-5...  SO2                       99.8  99.8...............  Control efficiency.  Primary capture:
                                                                                                                                    Double contact acid
                                                                                                                                    plant (existing).
                                                         .................               98.5 \f\...........  ...................  Secondary capture:
                                                                                                                                    New amine scrubber.
                                   Anode Furnaces 1, 2.  SO2                       None  Same...............  None...............  Work practice
                                                                                                                                    standard.
Miami Smelter....................  All BART Units......  NOX                         40  Same...............  tpy................  None.
                                   Converters 2-5......  SO2                       99.7  Same...............  Control efficiency.  Improve primary and
                                                                                                                                    new secondary
                                                                                                                                    capture systems,
                                                                                                                                    additional controls
                                                                                                                                    as needed.
                                   Electric Furnace....  SO2                       None  Same...............  None...............  Work practice
                                                                                                                                    standard.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Final limit revised to accommodate co-firing with landfill gas that has higher sulfur content.
\b\ Final limit is based on result of initial performance test.
\c\ Final limit includes a requirement for SNCR optimization plan.
\d\ Final limit is based on rolling 12-month average instead of rolling 30-day average.
\e\ Final limit is combined for Kilns 1 and 2 with compliance based on a rolling 30-day average.
\f\ Final limit is separate for primary and secondary capture systems.


[[Page 52426]]

B. Reasonable Progress Determinations

    Point Sources of NOX: EPA is finalizing its determination that PCC 
Clarkdale Plant Kiln 4 and CPC Rillito Plant Kiln 4 are subject to 
NOX emission controls under the RP requirements of the RHR 
as shown in Table 3. We also are finalizing our determination that it 
is reasonable not to require controls at this time on NOX 
emissions from the other seven sources that we evaluated for RP as well 
as other units at the Rillito Plant. These sources are the CPC Rillito 
Plant (Kilns 1-3); APS Cholla (Unit 1); El Paso Natural Gas (EPNG) 
Tucson, Flagstaff, and Williams Compressor Stations; TEP Sundt (Units 
1-3); Ina Road Sewage Plant; and TEP Springerville (Units 1 and 2).
    Clarkdale Plant Kiln 4: PCC has two options for meeting the RP 
requirements. It can choose to meet either a lb/ton limit or tons/year 
limit for NOX. The final NOX limit for the first 
option is the proposed 2.12 lb/ton with a requirement for an SNCR 
optimization plan. The final lb/ton NOX limit is based on a 
30-day rolling average consistent with SNCR as a control technology. 
The second option is an 810 tons/year NOX limit that is 
achievable by installing SNCR or maintaining clinker production at 
current levels. The 810 tons/year limit is based on a 12-month rolling 
average equivalent to a 50 percent reduction in baseline emissions. PCC 
must notify EPA of the option it has selected no later than July 2018 
with a compliance deadline of December 31, 2018.
    Rillito Plant Kiln 4: The final RP emission limit for 
NOX is 3.46 lb/ton based on a 35 percent control efficiency. 
We have increased the final limit from the proposed 2.67 lb/ton that 
was based on a 50 percent control efficiency in response to additional 
information from CPC regarding constraints on efficiency due to the 
kiln design. In addition, we are requiring implementation of an SNCR 
optimization plan to determine if a higher control efficiency is 
achievable. The final NOX limit is based on a 30-day rolling 
average and is consistent with SNCR as a control technology. The 
compliance deadline is December 31, 2018, the same as proposed.

                                                      Table 3--Final Emission Limits on RP Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Proposed                                                Corresponding
              Source                       Units              Pollutants         limit         Final limit            Measure         control technology
--------------------------------------------------------------------------------------------------------------------------------------------------------
Clarkdale Plant..................  Kiln 4..............  NOX.................       2.12  Same \a\............  lb/ton.............  Selective Non-
                                                                                                                                      Catalytic
                                                                                                                                      Reduction.
                                                                                     810  Same \b\............  tons/year..........  Current Production
                                                                                                                                      Levels.
Rillito Plant....................  Kiln 4..............  NOX.................       2.67  3.46 \c\............  lb/ton.............  Selective Non-
                                                                                                                                      Catalytic
                                                                                                                                      Reduction.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Final limit includes a requirement for SNCR optimization plan.
\b\ Final limit for second option is in tons/year in lieu of lb/ton.
\c\ Final limit includes a requirement for SNCR optimization plan.

    Area Sources of NOX and SO2: EPA is finalizing its determination 
that it is reasonable not to require additional controls on Arizona's 
area sources at this time. Area source categories such as distillate 
fuel oil combustion in boilers and internal combustion engines as well 
as residential natural gas combustion currently contribute a relatively 
small percentage of the visibility impairment at Class I areas, but 
should be considered for controls in future planning periods.

C. Reasonable Progress Goals and Demonstration

    Reasonable Progress Goals: EPA is quantifying our proposed RPGs (in 
deciviews) for the 20 percent worst days and 20 percent best days in 
2018. The RPGs for Arizona's 12 Class I areas account for the emission 
reductions from BART and RP control measures in the final RH FIP. The 
RPGs reflect the results of our BART analyses and our RP analysis of 
point sources of NOX and area sources of NOX and 
SO2 as described in our proposal and in response to comments 
in today's final rule. The RPGs also include the effects of the three 
BART determinations finalized in our Phase 1 FIP and the effects of 
other existing State and Federal controls. Today's final RPGs provide 
for an improvement in visibility on the worst days and no degradation 
in visibility on the best days during this planning period.
    Demonstration of Reasonable Progress: EPA's final determination is 
that it is not reasonable to provide for rates of progress at Arizona's 
12 Class I areas that would attain natural visibility conditions by 
2064 (i.e., the URP).\17\ Our demonstration that a slower rate of 
progress is reasonable is based on the RP analyses performed by us and 
the State that considered the four statutory RP factors. Although 
progress is slower than the URP, the FIP provides for RPGs that reflect 
an improved rate of progress and a significantly shorter time period to 
reach natural visibility conditions at each of Arizona's Class I areas, 
compared with the RPGs in the Arizona RH SIP.
---------------------------------------------------------------------------

    \17\ 40 CFR 51.308(d)(1)(ii).
---------------------------------------------------------------------------

D. Long-Term Strategy

    EPA is finalizing its determination that provisions in this final 
rule in combination with provisions in the approved Arizona RH SIP and 
the Phase 1 Arizona RH FIP \18\ fulfill the requirements for the 
LTS.\19\ In this final rule, we are promulgating emission limits, 
compliance schedules and other requirements for four BART sources and 
two RP sources. This final action completes the LTS measures needed to 
achieve emission reductions for out-of-state Class I areas, emission 
limitations and schedules for compliance to achieve the RPGs, and 
enforceability of emission limitations and control measures.\20\ In 
particular, as explained above, we are incorporating by reference 
provisions of the NESHAP for primary copper smelters to ensure that 
Arizona's BART determinations for PM10 at the Hayden and 
Miami Smelters are made enforceable and are included in the applicable 
implementation plan.
---------------------------------------------------------------------------

    \18\ 77 FR 75512-72580, December 5, 2012.
    \19\ 40 CFR 51.308(d)(3)(ii), (v)(C) and (v)(F).
    \20\ See 78 FR 46173 (codified at 40 CFR 52.145(e)(ii)).
---------------------------------------------------------------------------

E. Interstate Visibility Transport

    EPA is finalizing its determination that the control measures in 
the Arizona RH SIP and FIP are adequate to prevent Arizona's emissions 
from interfering with other states' required measures to protect 
visibility. Thus, the combined measures from both plans satisfy the 
interstate transport 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. In our final rule published on July 
30, 2013, EPA disapproved these

[[Page 52427]]

SIP submittals with respect to the interstate transport visibility 
requirement for each of these NAAQS, triggering the obligation for EPA 
to promulgate a FIP.\21\
---------------------------------------------------------------------------

    \21\ 78 FR 46142, July 30, 2013.
---------------------------------------------------------------------------

F. Other Changes From Proposal

    Our proposed regulatory text incorporated by reference certain 
provisions of the Arizona Administrative Code that establish an 
affirmative defense for excess emissions due to malfunctions. We did 
not receive any comments on this aspect of our proposal. Following the 
close of the public comment period, the United States Court of Appeals 
for the D.C. Circuit issued a decision concerning various aspects of 
the NESHAP for Portland cement plants issued by EPA in 2013, including 
the affirmative defense provision of that rule.\22\ The court found 
that EPA lacked authority to establish an affirmative defense for 
private civil suits and held that under the CAA, the authority to 
determine civil penalty amounts lies exclusively with the courts, not 
EPA. The court did not address whether such an affirmative defense 
provision could be properly included in a SIP. However, the court's 
holding makes it clear that the CAA does not authorize promulgation of 
such a provision by EPA. In particular, the court's decision turned on 
an analysis of CAA sections 113 (``Federal enforcement'') and 304 
(``Citizen suits''). These provisions apply with equal force to a civil 
action brought to enforce the provisions of a FIP. The logic of the 
court's decision thus applies to the promulgation of a FIP and 
precludes EPA from including an affirmative defense provision in a FIP. 
Therefore, we are not including an affirmative defense provision in the 
final FIP.
---------------------------------------------------------------------------

    \22\ NRDC v. EPA, 2014 U.S. App. LEXIS 7281 (D.C. Cir.).
---------------------------------------------------------------------------

    We note that, if a source is unable to comply with emission 
standards as a result of a malfunction, EPA may use case-by-case 
enforcement discretion, as appropriate. Further, as the D.C. Circuit 
recognized in an EPA or citizen enforcement action, the court has the 
discretion to consider any defense raised and determine whether 
penalties are appropriate.\23\
---------------------------------------------------------------------------

    \23\ Id. at 24 (arguments that violations were caused by 
unavoidable technology failure can be made to the courts in future 
civil cases when the issue arises).
---------------------------------------------------------------------------

V. Responses to General Comments

A. Introduction

    EPA provided 60 days for the public to submit comments on the 
proposed rule, with the comment period concluding on March 31, 2014. We 
held two public hearings in Arizona, one on February 25, 2014, in 
Phoenix and another on February 26, 2014, in Tucson. The deadline for 
public comments was March 31, 2014. Certified records of the public 
hearings, written comments (excluding any confidential business 
information (CBI) materials), a summary of comments, and a list of 
commenters are available in the docket for this final action. We 
received a total of 24 written comments from industry or industrial 
associations (13), environmental groups (6), citizens (3), a state 
agency (1), and a federal agency (1). In addition, 14 individuals 
presented oral testimony at the two hearings. Summaries of significant 
comments and EPA's responses, organized by subject matter, are provided 
in the following sections. Because we received no comments regarding 
the LTS or interstate transport provisions of the FIP, there is no 
section in this notice addressing comments on these topics.
    We are using the following acronyms to refer to representatives of 
the following entities who submitted comments to us:
 ACCCE--American Coalition for Clean Coal Energy
 ADEQ--Arizona Department of Environmental Quality
 AMA--Arizona Mining Association
 ANGA--America's Natural Gas Alliance
 ASARCO--American Smelting and Refining Company
 CPC--CalPortland Company
 Earthjustice \24\
---------------------------------------------------------------------------

    \24\ Comments were provided by Earthjustice on behalf of the 
National Parks Conservation Association, Sierra Club, San Juan 
Citizens Alliance, and Arizona Chapter of Physicians for Social 
Responsibility.
---------------------------------------------------------------------------

 EPNG--El Paso Natural Gas Company
 FMMI--Freeport-McMoRan Miami, Inc.
 LNA--Lhoist North America of Arizona
 NMA--National Mining Association
 NPS--National Park Service
 PCC--Phoenix Cement Company
 PSR--Physicians for Social Responsibility
 TEP--Tucson Electric Power
 TPMEC--Tucson Pima Metropolitan Energy Commission

B. Comments on State and EPA Actions on Regional Haze

    Comment: One commenter, a former member of the Technical Oversight 
Committee of the Western Regional Air Partnership (WRAP), recounted the 
history of the Grand Canyon Visibility Transport Commission and the 
WRAP, and their efforts under section 309 of the original RHR to 
develop emission reduction milestones through 2018 for SO2 
emissions from large industrial sources in the nine-state Commission 
Transport Region that affects the Colorado Plateau. The commenter noted 
that Arizona ultimately withdrew from the section 309 process, but 
asserted that the State's withdrawal should not negate the effort of 
setting the milestones and the agreements reached during that process. 
The commenter asserted that by rejecting Arizona's SIP and proposing a 
FIP, EPA has gone beyond what was agreed on as a reasonable expectation 
of BART for specific groups of sources, such as smelters, utilities, 
and cement plants. The commenter added that the new SO2 
NAAQS will require plants to make changes that go well beyond BART. 
Therefore, BART should be set at a level no more stringent than what 
WRAP proposed so as not to interfere with any plans for the 
nonattainment areas to come into compliance with the new SO2 
standard.
    Response: These comments largely pertain to EPA's partial 
disapproval of Arizona's 308 RH SIP and are therefore untimely, as EPA 
has already taken final action on the SIP.\25\ Furthermore, EPA has 
already disapproved the majority of Arizona's 309 RH SIP.\26\ As 
explained further below in response to similar comments regarding the 
Hayden and Miami Smelters, this FIP will not adversely impact the 
smelters' ability to come into compliance with the 1-hour 
SO2 NAAQS.
---------------------------------------------------------------------------

    \25\ 78 FR 46142.
    \26\ 78 FR 48326.
---------------------------------------------------------------------------

C. Comments on State and Federal Roles in the Regional Haze Program

    Comment: Several commenters (ADEQ, FMMI, AMA, ACCCE and NMA) do not 
agree with EPA's partial disapproval of Arizona's RH SIP, asserting 
that EPA has overstepped its boundaries by unnecessarily imposing a 
FIP. Some of the commenters contend that states are best suited to make 
BART determinations, not EPA.
    ADEQ noted that the RHR is not intended to protect public health, 
but to address visibility problems. In the commenter's opinion, EPA 
should have given the State of Arizona the

[[Page 52428]]

opportunity to correct specific issues in the SIP, instead of 
proceeding with a FIP. Citing to CAA section 110(c), ADEQ asserted that 
EPA should end this rulemaking and allow ADEQ a period of up to two 
years to correct any deficiencies in its RH SIP. ACCCE discussed the 
history of the regional haze program and emphasized the discretion 
provided to states under the CAA and the RHR. FMMI stated that EPA 
lacks the authority to disapprove a SIP and promulgate the proposed FIP 
based on its policy disagreements with a state. AMA and NMA asserted 
that EPA had overstepped its boundaries and should leave the decision 
of what constitutes BART and reasonable progress to the State of 
Arizona. NMA proceeded to argue that this is not the first example of 
EPA going beyond its authority as it relates to regional haze, since it 
has replaced the regional haze determinations of 14 states with its own 
federal requirements. NMA went on to say that in the case of the 
Arizona RH SIP, EPA disapproved parts of the plan due to its own 
subjective opinion and not because the SIP was inconsistent with the 
requirements of the CAA.
    Response: To the extent these comments pertain to EPA's partial 
disapproval of the Arizona RH SIP or other previous SIP actions, they 
are untimely. To the extent that the comments are relevant to the 
proposed FIP, we do not agree with their substance. While it is our 
strong preference that state plans implement CAA requirements, there 
are circumstances in which a FIP is required by the Act. As explained 
in response to comments on the Phase 1 Final Rule \27\ and our legal 
brief responding to petitions for review of that rule,\28\ we are 
required by the CAA to issue a FIP to meet all requirements of the RHR 
not addressed by an approved SIP revision. In particular, CAA section 
110(c) requires EPA to promulgate a FIP at any time within two years of 
(1) finding that a State has failed to make a required submission, or 
(2) disapproving a State submission in whole or in part. This 
obligation is eliminated only if ``the State corrects the deficiency, 
and the Administrator approves the plan or plan revision, before the 
Administrator promulgates such Federal Implementation plan.'' In this 
instance, two different triggering events under section 110(c) have 
occurred: EPA has made a finding that the State failed to make a 
required submission and has partially disapproved the submissions that 
the State subsequently made.
---------------------------------------------------------------------------

    \27\ 77 FR 72568-69 (December 5, 2012).
    \28\ Brief of Respondent, Arizona v. EPA, No. 13-70366 (9th Cir. 
Dec. 12, 2013) (EPA Phase 1 Brief) at 66-77.
---------------------------------------------------------------------------

    EPA found that Arizona had failed to submit a comprehensive 
regional haze SIP in January 2009, which triggered an obligation for 
EPA to promulgate a FIP within two years, unless the State first 
submitted and EPA approved a regional haze SIP.\29\ When EPA failed to 
either approve a SIP or promulgate a FIP by the January 2011 deadline, 
we were sued by a group of conservation organizations.\30\ In order to 
resolve this lawsuit, EPA entered into a Consent Decree that 
established deadlines for action on regional haze plans for various 
states, 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.\31\ Under the terms of the Consent Decree, as 
amended, EPA was subject to three sets of deadlines for taking action 
on the Arizona RH SIP as listed in Table 4. The specific deficiencies 
that commenters claim to have identified in EPA's proposal are 
addressed in subsequent responses.
---------------------------------------------------------------------------

    \29\ 74 FR 2392-93 (January 15, 2009).
    \30\ National Parks Conservation Association v. Jackson (D.D.C. 
Case 1:11-cv-01548).
    \31\ Nat'l Parks Conservation Ass'n 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), Minute Order 
(February 15, 2013), Order (September 6, 2013), and Stipulation to 
Amend Consent Decree (November 14, 2013). On appeal, the D.C. 
Circuit upheld the District Court's finding that it lacked 
jurisdiction over Arizona's objections. Nat'l Parks Conservation 
Ass'n v. EPA, 43 ELR 20266 (D.C. Cir. 2013).

                 Table 4--Consent Decree Deadlines for EPA To Act on the Arizona RH SIP and FIP
----------------------------------------------------------------------------------------------------------------
              EPA actions                   Proposed rule signature date          Final rule signature date
----------------------------------------------------------------------------------------------------------------
Phase 1--BART determinations for        July 2, 2012 \a\...................  November 15, 2012.\b\
 Apache, Cholla and Coronado.
Phase 2--All remaining elements of the  December 8, 2012 \c\...............  July 15, 2013.\d\
 Arizona RH SIP.
Phase 3--FIP for disapproved elements   January 27, 2014 \e\...............  June 27, 2014.
 of the Arizona RH SIP.
----------------------------------------------------------------------------------------------------------------
\a\ Published in the Federal Register on July 20, 2012, 77 FR 42834.
\b\ Published in the Federal Register on December 5, 2012, 77 FR 72512.
\c\ Published in the Federal Register on December 21, 2012, 77 FR 75704.
\d\ Published in the Federal Register on July 30, 2013, 78 FR 46142. Also addresses supplemental proposal
  published in the Federal Register on May 20, 2013, 78 FR 29292.
\e\ Published in the Federal Register on February 18, 2014.

    In Phase 1, EPA approved in part and disapproved in part Arizona's 
BART determinations for Apache Generating Station, Cholla Power Plant, 
and Coronado Generating Station, and promulgated a FIP addressing the 
disapproved portions of the SIP.\32\ In our initial Phase 2 proposal, 
EPA proposed to approve in part and disapprove in part the remainder of 
the Arizona RH SIP.\33\ In May 2013, ADEQ submitted a SIP Supplement 
that addressed some of the elements that EPA had proposed to 
disapprove. We then proposed to approve in part and disapprove in part 
the SIP Supplement.\34\ We finalized our partial approval and partial 
disapproval on July 30, 2013.\35\ We have also disapproved the majority 
of Arizona's submittal under Section 309 of the RHR.\36\ Given these 
disapprovals, and our previous finding of failure to submit, EPA is 
required under CAA section 110(c) to promulgate a FIP for the 
disapproved portions of the SIP. Indeed, even if we had not previously 
found that Arizona failed to submit a comprehensive regional haze SIP, 
we nonetheless would be authorized to promulgate a partial FIP 
following our partial disapprovals of Arizona's 308 and 309 RH 
SIPs.\37\ As noted above, however,

[[Page 52429]]

EPA remains willing to work with ADEQ on a SIP that would be designed 
to replace this FIP once such a SIP was submitted and approved by us.
---------------------------------------------------------------------------

    \32\ 77 FR 72512 (December 5, 2012).
    \33\ 77 FR 75704 (December 21, 2012).
    \34\ 78 FR 29292 (May 20, 2013).
    \35\ 78 FR 46142 (July 30, 2013).
    \36\ 78 FR 48326 (August 8, 2013).
    \37\ See EPA v. EME Homer City Generation, 134 S. Ct. 1584 
(2014), Slip. Op. at 16 (``After EPA has disapproved a SIP, the 
Agency can wait up to two years to issue a FIP . . . But EPA is not 
obliged to wait two years or postpone its action even a single day: 
The Act empowers the Agency to promulgate a FIP `at any time' within 
the two-year limit.'').
---------------------------------------------------------------------------

VI. Responses to Comments on EPA's Proposed BART Determinations

A. Comments on Sundt Generating Station Unit 4

1. BART Eligibility
    Comment: Three commenters (ADEQ, TEP, and ACCCE) argued against 
EPA's proposed finding that Sundt Unit 4 is BART-eligible, and two 
commenters (Earthjustice and NPS) supported EPA's finding. ADEQ 
asserted that EPA has no authority to impose BART on Sundt Unit 4 
because ADEQ determined that the unit is not BART-eligible. ADEQ noted 
that under CAA section 169(b)(2)(A), major sources that existed as of 
August 7, 1962, are considered BART-eligible. However, the statute does 
not address sources that existed during that time, but were 
reconstructed after 1977 (Sundt Unit 4 was reconstructed in 1987). 
According to ADEQ, ``EPA filled that gap by adopting regulations 
treating `reconstructed' units as `new' units.''
    ADEQ further noted that the BART Guidelines provide that ``any 
emissions unit for which a reconstruction `commenced' after August 7, 
1977, is not BART-eligible'' and argued that ADEQ's determination that 
Sundt Unit 4 is not BART-eligible was consistent with EPA's 
regulations. ADEQ asserted that EPA rejected the determination on the 
basis that EPA is not bound by its own guidelines and argued that that 
it was inappropriate for EPA to fault ADEQ for following guidance that 
EPA maintains is ``persuasive'' evidence of the requirements of the 
CAA. The commenter further argued that the BART Guidelines are clear 
that any unit that was reconstructed after 1977 is not BART-eligible, 
but that despite this, EPA has indicated that it does not interpret the 
BART Guidelines to apply to Sundt Unit 4 because the unit never went 
through prevention of significant deterioration (PSD) permitting. ADEQ 
argued that ``EPA is not authorized, in the guise of `interpreting' its 
BART Guidelines, to engage in what amounts to post-hoc rulemaking, by 
amending its BART Guidelines to make units that are reconstructed after 
1977, but which did not obtain PSD permits BART-eligible.''
    ADEQ also commented that EPA has ignored the policy reasons that 
Congress had for excluding reconstructed units such as Sundt Unit 4 
from PSD and other requirements. The commenter noted that the Power 
Plant and Industrial Fuel Use Act of 1978 (FUA), which amended the 
Energy Supply and Environmental Coordination Act of 1974 (ESECA), 
authorized the Department of Energy (DOE) to require electric utilities 
to convert generating stations using oil and natural gas to using coal 
to reduce the Unites States' dependency on foreign oil and increase its 
use of indigenous energy resources. ADEQ stated that because Congress 
wished to ensure the conversion took place, these units were exempted 
from ``environmental requirements.'' Therefore, BART should not be 
required for Sundt Unit 4.
    TEP, the owner of the Sundt facility, incorporated by reference the 
comments it submitted on EPA's proposed partial disapproval of the 
Arizona RH SIP, in which the commenter opposed EPA's position that 
Sundt Unit 4 is BART-eligible, and reiterated its position that Sundt 
Unit 4 is not BART-eligible. Similarly, ACCCE asserted that, ``ADEQ's 
determination that Sundt Unit 4 was reconstructed in the 1980s, and 
therefore is not BART-eligible was reasonable and should not have been 
disapproved by EPA.'' In contrast, Earthjustice and NPS expressed 
support for EPA's finding that Sundt Unit 4 is BART-eligible because it 
did not go through PSD review when it was reconstructed in 1987. 
Earthjustice asserted that a source reconstructed after 1977 must 
install either BART controls under the regional haze program or Best 
Available Control Technology (BACT) controls under the PSD program.
    Response: To the extent that the comments concern EPA's partial 
disapproval of the Arizona RH SIP, they are untimely, as EPA has 
already taken final action on the SIP.\38\ Further, we have already 
addressed many of the commenters' assertions in our proposed and final 
actions on the SIP and in the Sundt Memo,\39\ all of which are included 
in the docket for this action. To the extent the comments raise new 
issues, we address them here.
---------------------------------------------------------------------------

    \38\ 78 FR 46142.
    \39\ 78 FR 75722 and TEP Sundt Unit I4 BART Eligibility Memo 
(November 21, 2012) (Sundt Memo).
---------------------------------------------------------------------------

    Contrary to ADEQ's assertion, the RHR does not indicate that 
``reconstructed'' units are to be treated as ``new'' units for all 
purposes. In particular, the RHR does not indicate that a source that 
is reconstructed after 1977 is considered BART-ineligible. Likewise, 
nothing in the preamble to the 1980 rule regarding Reasonably 
Attributable Visibility Impairment (RAVI), in which EPA promulgated the 
definition of ``BART-eligible,'' or the preamble to the 1999 RHR itself 
suggests that a post-1977 reconstruction would exempt a source from 
BART.\40\ The BART Guidelines do state that ``any emissions unit for 
which a reconstruction `commenced' after August 7, 1977, is not BART-
eligible.'' \41\ However, this statement in the BART Guidelines must be 
read in the context of the applicable regulatory requirements and 
associated preambles, none of which even mention such an exemption for 
post-1977 reconstructions. In particular, the preamble to the BART 
Guidelines indicates that the post-1977 reconstruction exemption set 
out in the BART Guidelines is limited to ``sources reconstructed after 
1977, which reconstruction had gone through NSR/PSD permitting.'' \42\ 
Although not binding, this statement in the preamble confirms that EPA 
did not intend to create a blanket exemption for all post-1977 
reconstructions in the BART Guidelines. Indeed, it would only make 
sense to exempt a reconstructed unit from BART if that unit had gone 
through NSR/PSD permitting to ensure that its emissions were subject to 
modern-day pollution controls. Sundt Unit 4 never went through such 
permitting. Thus, we do not agree that we are effectively amending the 
BART Guidelines or engaging in post hoc rulemaking by applying an 
interpretation that is consistent not only with the CAA and RHR, but 
also with the preamble to the BART Guidelines themselves.
---------------------------------------------------------------------------

    \40\ See 45 FR 80084, 64 FR 35714.
    \41\ 70 FR 39160.
    \42\ 70 FR 39111.
---------------------------------------------------------------------------

    We also do not agree that Congress intended to provide a general 
exemption from all ``environmental requirements'' for units that were 
converted to coal under the FUA and ESECA. The relevant section of FUA, 
codified in CAA section 111(a)(8), provides that ``[a] conversion to 
coal . . . by reason of an order under section 2(a) of the [ESECA] or 
any amendment thereto, or any subsequent enactment which supersedes 
such Act . . . shall not be deemed to be a modification for purposes of 
paragraphs (2) and (4) of [CAA subsection 111(a)].'' \43\ Paragraphs 
(2) and (4), in turn, contain the definitions of ``new source'' and 
``modification'' that apply to the Act's new source performance 
standards (NSPS) requirements.\44\ The definition of ``modification'' 
in paragraph 111(a)(4) also applies for purposes of the PSD

[[Page 52430]]

provisions of the Act.\45\ However, nothing in the Act indicates that 
Congress intended the exemption in section 111(a)(8) to extend to other 
provisions of the Act, such as the visibility protection provisions of 
Section 169A. If Congress had intended to provide such an exemption 
from BART eligibility for units that were converted to coal under the 
FUA and ESECA, it could have added such an exemption to section 169A. 
It did not do so. Thus, for the reasons set out in the Sundt Memo, in 
our Phase 2 proposed and final rulemakings, and in this response, we 
are finalizing our proposed determination that Sundt 4 is BART-
eligible.
---------------------------------------------------------------------------

    \43\ 42 U.S.C. 7411(a)(8) (emphasis added).
    \44\ 42 U.S.C. 7411(a)(2) and (4).
    \45\ 42 U.S.C. 7479(2)(C).
---------------------------------------------------------------------------

2. BART Analysis and Determination for NOX
    Comment: ADEQ indicated that it does not support EPA's proposed 
limit for NOX that is based on SNCR control technology. ADEQ 
asserted that the significant cost of installing and operating SNCR ($3 
million in construction and $1 million in annual operating costs) does 
not justify the limited visibility improvement that would result from 
adding this control technology. ADEQ said that EPA's analysis, which 
ADEQ described as suspect, shows an improvement of only 0.5 dv. ACCCE 
also objected to EPA's decision to require SNCR, arguing that it is 
costly and results in no perceptible improvement in visibility. ACCCE 
discussed the installation costs and the cost-effectiveness of SNCR on 
Unit 4, and stated that none of the Class I areas affected by Sundt 
Unit 4 will experience a greater than a 1.0 dv improvement from the 
installation of SNCR. This ``modest'' improvement is inconsistent, 
ACCCE said, with EPA's position that considers 1.0 dv change or more 
from an individual source as causing visibility impairment and a 0.5 dv 
change as contributing to impairment.
    Response: We disagree with these comments. Regarding the costs of 
compliance, although the installation and operation of SNCR will result 
in TEP incurring certain initial investments and ongoing operational 
costs, we consider the total annualized cost warranted based on the 
amount of NOX removed and the expected visibility benefits. 
As noted in our proposed rule, SNCR at this source has a cost-
effectiveness of about $3,200/ton, which we consider very cost-
effective. With regard to visibility improvement, we do not agree that 
only visibility improvements that by themselves result in humanly 
perceptible changes are relevant. The CAA and RHR require, as part of 
each BART analysis, consideration of ``the degree of improvement in 
visibility which may reasonably be anticipated to result from the use 
of such technology.'' \46\ The Act and RHR do not require that the 
improvement from a single source be perceptible in order to be 
meaningful. As EPA explained in the preamble to the BART Guidelines: 
``Even though the visibility improvement from an individual source may 
not be perceptible, it should still be considered in setting BART 
because the contribution to haze may be significant relative to other 
source contributions in the Class I area.'' \47\ Thus, we disagree that 
the degree of visibility improvement should be contingent upon 
perceptibility.
---------------------------------------------------------------------------

    \46\ CAA section 169A(g)(2), 40 CFR 51.308(e)(1)(ii)(A).
    \47\ 70 FR 39129.
---------------------------------------------------------------------------

    In our visibility improvement analysis, we have not considered 
perceptibility as a threshold criterion for considering improvements in 
visibility. Rather, we have considered visibility improvement in a 
holistic manner, taking into account all reasonably anticipated 
improvements in visibility expected to result at all Class I areas 
within 300 kilometers of each source. Improvements smaller than 0.5 dv 
may be warranted considering the number of Class I areas involved and 
the baseline contribution to impairment of the source in question. For 
example, a source with a 0.5 dv impact at a Class I area 
``contributes'' to visibility impairment and must be analyzed for BART 
controls. Controlling such a source will not result in perceptible 
improvement in visibility, but Congress nevertheless determined that 
such contributing sources should nevertheless be subject to the BART 
requirement. In the aggregate, small improvements from controls on 
multiple BART sources and other sources will lead to visibility 
progress. As a result, although we described the anticipated visibility 
benefits from the installation of SNCR as ``modest,'' we still consider 
those benefits sufficient to justify SNCR as BART in light of the fact 
that SNCR will be highly cost-effective and has no substantial adverse 
energy or non-air quality environmental impacts. This has been EPA's 
consistent interpretation in many regional haze determinations.
    Comment: ADEQ indicated that it supports EPA's rejection of an 
emission limit equivalent to SCR as BART for NOX at Sundt 
Unit 4 due to costs. In contrast, Earthjustice asserted that EPA should 
have set a BART emission limit that reflects the use of SCR at Sundt 
Unit 4, rather than the less effective SNCR technology. Earthjustice 
stated that EPA erred when it concluded that the visibility benefits of 
SCR were not worth the costs after EPA acknowledged that SCR provides 
substantially greater visibility improvements than SNCR. Earthjustice 
stressed that EPA's calculated cost-effectiveness value of $5,176 per 
ton of NOX removed for SCR is within the range of what has 
been deemed cost-effective in many other instances, based on examples 
provided in Exhibit 33 submitted with the comments. Earthjustice added 
that EPA provided no justifiable rationale for rejecting the overall 
cost-effectiveness value and relying on the incremental cost-
effectiveness value for the rejection. Earthjustice also contended that 
EPA improperly rejected SCR based on numerous erroneous assumptions in 
its cost analysis that increased the cost-effectiveness values (i.e., 
$/ton) for SCR. In particular, Earthjustice asserted that EPA used an 
unreasonably low capacity factor of 0.49, even though a higher and more 
appropriate capacity factor would have made the SCR controls more cost-
effective. Earthjustice also noted that EPA used a retrofit factor for 
SCR of 1.5, instead of the standard retrofit factor of 1.0, but 
asserted that EPA did not provide a sufficient reason to enhance the 
retrofit factor. According to Earthjustice, correcting these two 
assumptions would make SCR cost-effective to control NOX at 
Sundt Unit 4 at an emission rate of 0.05 lb/MMBtu.
    Response: We disagree that we improperly rejected SCR. In reaching 
our BART determination, we have considered both average and incremental 
costs as well as expected visibility benefits.\48\ In particular, we 
estimate the average cost-effectiveness of SCR to be $5,176/ton. EPA 
has not previously required installation of controls with an average 
cost-effectiveness value this high for purposes of BART.\49\ Similarly, 
the estimated incremental cost-effectiveness for SCR (compared to SNCR) 
of $6,174/ton is on the high end of what we have required for purposes 
of BART.\50\ Such cost values might be warranted if the expected 
visibility benefits were very high (i.e., over one deciview at a single 
Class I area or several cumulative deciviews across multiple affected 
Class

[[Page 52431]]

I areas). However, we do not consider this level of cost to be 
justified here by the expected visibility benefits for SCR of 0.78 dv 
for the most improved Class I area and 1.6 dv cumulative for all 
affected Class I areas.
---------------------------------------------------------------------------

    \48\ See 79 FR 9329.
    \49\ See, e.g., BART EGU FIP Summary.
    \50\ Id. The only example with a higher incremental cost-
effectiveness value is Dave Johnston Unit 3 in Wyoming ($7,583/ton 
based on a remaining useful life of 20 years).
---------------------------------------------------------------------------

    The information provided by Earthjustice regarding the range of $/
ton values considered cost-effective is derived from other regulatory 
programs such as Best Available Control Technology (BACT) 
determinations for construction of new sources in attainment areas, and 
Lowest Achievable Emission Rate determinations for construction of new 
sources in nonattainment areas. The statutory requirements, calculation 
methodology, and regulatory drivers that may inform a determination of 
emission reductions appropriate for these programs are not necessarily 
comparable to those of the Regional Haze program, which is a retrofit 
program where older sources are required to add pollution controls. We 
therefore do not consider it appropriate simply to conclude that costs 
found to be acceptable in other programs are necessarily appropriate in 
a BART determination.
    We also disagree with Earthjustice's assertion that our cost 
analysis for SCR is based on faulty assumptions. We recognize that a 
higher capacity factor would result in an increase in the calculated 
amount of NOX reduced. We also recognize that, historically, 
Sundt Unit 4 operated at higher capacity factors, ranging from 0.60 to 
0.75. However, a review of data from EPA's Clean Air Markets Division 
(CAMD) Acid Rain Program database indicates that, starting in 2009 and 
continuing into the present, Sundt Unit 4 has consistently operated at 
substantially lower capacity factors.\51\ Our use of a 0.49 capacity 
factor is therefore not based on a single, abnormal year of low 
capacity, but rather represents an average of multiple, recent years of 
low capacity at Sundt Unit 4. Given the length of time that Sundt Unit 
4 has operated at these low capacity levels, we consider our use of a 
0.49 capacity factor in emission calculations to be a ``realistic 
depiction of anticipated annual emissions.'' \52\
---------------------------------------------------------------------------

    \51\ This emission and generation data was contained in the 
docket for our proposal, E-45--TEP Sundt4 2001-12 Emission Calcs 
2014-01-24.xlsx.
    \52\ See 70 FR 39167.
---------------------------------------------------------------------------

    Moreover, we disagree with the Earthjustice's assertion that our 
use of a 1.5 retrofit factor is unsupported in the record. Although the 
factors contributing to retrofit difficulty were summarized as 
``certain difficulties'' in our TSD, this information is described in 
detail in the modeling and cost information provided by TEP on May 10, 
2013.\53\ Our cost calculations specifically noted the changes we made 
to account for these factors.\54\ Specifically, a detailed description 
of these issues is contained on page 6, Attachment C, in TEP's letter 
dated May 10, 2013. These issues include interference from existing 
boiler structures and material handling equipment that makes the most 
common SCR reactor impractical, the need for substantial modifications 
to the existing air preheater, and site congestion around the boiler 
that complicates siting of an SCR system. We consider these issues 
sufficient to warrant a higher retrofit factor.
---------------------------------------------------------------------------

    \53\ TEP's May 10, 2013 letter describing this information was 
contained in the docket for our proposal, C-37 Letter from Erik 
Bakken, TEP, to Greg Nudd, EPA, re TEP Sundt Modeling & Cost 
Information.pdf.
    \54\ Our cost calculations, which note these upward revisions, 
were contained in the docket for our proposal, E-05 TEP Sundt4 
Control Costs (final for NPRM docket).xlsx.
---------------------------------------------------------------------------

    Comment: In response to EPA's request for comment on whether EPA 
should use a less stringent SCR emission limit in its NOX 
BART analysis for Sundt Unit 4, Earthjustice responded in the negative. 
According to the commenter, EPA's use of a 0.05 lb/MMBtu limit for SCR 
is consistent with EPA's BART determinations for other coal-fired power 
plants for which EPA has repeatedly concluded that a 0.05 to 0.055 lb/
MMBtu emission limit is BART. In addition, citing reports submitted 
with the comments, Earthjustice asserted that SCRs often achieve more 
stringent emission rates and control efficiencies than EPA assumed SCR 
would achieve at Sundt Unit 4. Earthjustice stated that because a 0.05 
lb/MMBtu emission rate is achievable with SCR at Sundt Unit 4, EPA 
should not use a less stringent emission limit in its BART analysis.
    Response: We agree that our use of a 0.05 lb/MMBtu annual average 
design value for SCR is consistent with other BART determinations for 
coal-fired power plants.
    Comment: Earthjustice stated that if EPA does not revise its BART 
determination to require SCR, it should set a more stringent emission 
limit that more accurately reflects the emission reductions achievable 
with SNCR. Earthjustice quoted the BART Guidelines as requiring EPA to 
``take into account the most stringent emission control level that the 
technology is capable of achieving,'' which Earthjustice said EPA has 
not done in this case. Earthjustice asserted that EPA should select a 
level of NOX reduction for SNCR in the range of 50 percent 
over and above the existing combustion controls, rather than the level 
of 30 percent above current controls that was selected. As support, 
Earthjustice noted that SNCR is required by the pending SIP revision 
(prepared by ADEQ to replace the FIP) for Apache Unit 3 to reduce 
NOX from 0.43 lb/MMBtu down to 0.23 lb/MMBtu, or roughly 50 
percent. Earthjustice recommended that EPA set an emission limit for 
SNCR in the range of 0.22 lb/MMBtu, reflecting 50 percent reduction 
from the baseline level of 0.445 lb/MMBtu of NOX in 2011. In 
addition, Earthjustice disagreed with EPA's inflation of the 
NOX emission limit by 17 percent to account for variability. 
According to Earthjustice, EPA assumed without justification that the 
observed variability without SNCR would be the same as variability with 
SNCR.
    Response: We disagree with this comment. The Apache Unit 3 example 
cited by Earthjustice does not support a 50 percent SNCR control 
efficiency. The 0.43 lb/MMBtu emission rate on Apache Unit 3 noted by 
Earthjustice reflects the use of over fire air (OFA) only. The 0.23 lb/
MMBtu emission rate on Apache Unit 3 noted by Earthjustice reflects the 
use of LNB with OFA and SNCR. The approximate 50 percent reduction from 
0.43 to 0.23 is not solely attributable to SNCR, but rather is the 
result of the application of LNB and SNCR. Since Sundt Unit 4 already 
operates with LNB and OFA, we do not consider it appropriate to assume 
that application of SNCR will result in an additional 50 percent 
NOX reduction.
    With regard to our upward revision to the annual emission rate to 
develop a rolling 30 day emission limit, we acknowledge that observed 
variability without SNCR might not be the same as variability with 
SNCR. We note, however, that even emission units with well-operated 
controls will experience some degree of emissions variability. As noted 
in our proposed rule, we developed this upward revision based on site-
specific emission data reported to the CAMD for Sundt Unit 4. Given the 
site-specific basis for our upward revision, we consider it a 
reasonable estimate of emission variability. We acknowledge that there 
might be other methods of accounting for this variability. However, we 
did not receive any comments that described or proposed any such 
alternate methodology. Accordingly, we are finalizing the emission 
limit as proposed.

[[Page 52432]]

    Comment: NPS indicated that it agrees with the design emission rate 
of 0.050 lb/MMBtu that EPA used to estimate the control effectiveness 
of SCR. However, NPS did not agree with the cost of catalyst for SCR of 
$8,000 per cubic meters (m\3\), and cited to a recent report indicating 
the costs are around $5,000/m\3\. NPS also said that EPA did not 
consider using regenerated catalyst at a cost of $5,500/m\3\, which it 
did in the recent Wyoming RH FIP.
    NPS also stated that instead of relying only on the Integrated 
Planning Model (IPM) to estimate the costs of SCR, NPS used a method 
similar to what EPA Region 8 used for Colstrip in Montana. In NPS's 
opinion, using IPM to calculate capital costs and EPA's Control Cost 
Manual (CCM) to calculate operating costs provides more flexibility, 
provides greater transparency and is more in line with the BART 
Guidelines that recommend following EPA's CCM as much as possible.
    Response: We disagree with the NPA's assertion that $8,000/m\3\ is 
an unreasonable cost estimate for catalyst. Since catalyst prices 
fluctuate, we recognize that recent prices may be lower than the value 
used in our cost calculations. However, given that catalyst is an 
operating cost that will be periodically incurred over the entire 
useful life of the equipment,\55\ we consider it appropriate to use a 
catalyst price that reflects more than just recent price levels. The 
BART Guidelines state, ``In order to maintain and improve consistency, 
cost estimates should be based on the OAQPS Control Cost Manual, where 
possible'' and that ``[w]e believe that the Control Cost Manual 
provides a good reference tool for cost calculations, but if there are 
elements or sources that are not addressed by the Control Cost Manual 
or there are additional cost methods that could be used, we believe 
that these could serve as useful supplemental information.'' \56\ As 
noted in our proposed rule and TSD,\57\ EPA has used IPM in multiple 
regulatory actions, and considers it an appropriate source of 
supplemental information.
---------------------------------------------------------------------------

    \55\ As opposed to capital costs, which are incurred only once, 
at the start of the project.
    \56\ BART Guidelines, 40 CFR Part 51, Appendix Y, section 
IV.D.4.a.
    \57\ TSD for the Proposed Phase 3 FIP, January 27, 2013, Page 19 
of 233.
---------------------------------------------------------------------------

3. BART Analysis and Determination for SO2
    Comment: ACCCE opposed EPA's proposal to require DSI for the 
control of SO2 emissions at Sundt Unit 4. The ACCCE asserted 
that this requirement will have no humanly perceptible visibility 
improvement, so the proposal must be withdrawn. According to ACCCE, the 
highest visibility improvement expected from this requirement is 0.20 
dv at Saguaro National Park. At the other nine affected Class I areas, 
the visibility improvement is expected to range from only 0.04 to 0.10 
dv. ACCCE contended that requiring costly controls with no humanly 
perceptible visibility improvement is unjustified.
    Response: As noted in our response to a similar comment regarding 
our NOX BART determination, we have not considered 
perceptibility as a threshold criterion for considering improvements in 
visibility. Rather, we have considered visibility improvement in a 
holistic manner, taking into account all reasonably anticipated 
improvements in visibility expected to result at all Class I areas 
within 300 kilometers of each source. Improvements smaller than 0.5 dv 
may be warranted considering the number of Class I areas involved and 
the initial contribution to impairment of the source in question. For 
example, a source with a 0.5 dv impact at a Class I area 
``contributes'' to visibility impairment and must be analyzed for BART 
controls. While controlling such a source will not result in 
perceptible improvement in visibility, Congress determined that such 
contributing sources should nevertheless be subject to the BART 
requirement. In the aggregate, small improvements from controls on 
multiple BART sources and other sources will lead to visibility 
progress. As a result, although the anticipated visibility benefit 
attributable to DSI is not humanly perceptible, we consider those 
benefits sufficient to justify DSI as BART in light of the fact that 
DSI will be highly cost-effective and has no substantial adverse energy 
or non-air quality environmental impacts.
    Comment: Earthjustice stated that EPA should revise its BART 
analysis for SO2 to reflect more stringent emission rates 
achievable with wet flue gas desulfurization (FGD) and dry FGD because 
the BART Guidelines require EPA to analyze the most stringent emission 
control level that the technology is capable of achieving. According to 
Earthjustice, EPA assumed that wet FGD would achieve a 0.06 lb/MMBtu 
emission rate (92 percent control efficiency) and dry FGD would achieve 
a 0.08 lb/MMBtu emission rate (89 percent control efficiency). 
Earthjustice argued that these figures were cited despite EPA's 
acknowledgment that both wet FGD and dry FGD are capable of achieving 
more stringent emission rates. Earthjustice added that reports 
submitted with its comments show that both wet and dry FGD can achieve 
emission rates of 0.04 lb/MMBtu or lower along with control 
efficiencies of 95 to 99 percent.
    Response: We disagree that we underestimated the SO2 
emission reductions achievable with dry or wet FGD. In our proposed 
rule, and in the TSD for our proposed rule, we stated that:

    [B]oth dry and wet FGD have very high incremental cost-
effectiveness values, indicating that while they are more effective 
than the preceding control, this additional degree of effectiveness 
comes at a substantial cost.

    The incremental cost-effectiveness of dry FGD, in relation to DSI, 
is approximately $17,000/ton. Assuming a more stringent dry or wet FGD 
emission rate of 0.04 lb/MMBtu, the incremental cost-effectiveness of 
FGD, relative to DSI, is approximately $13,000/ton, which is still not 
within a range that EPA or states have considered cost-effective, 
especially given that FGD (dry or wet) is expected to result in less 
visibility improvement than DSI.\58\ As a result, a more stringent FGD 
emission rate would not alter our SO2 BART determination.
---------------------------------------------------------------------------

    \58\ See 79 FR 9332-33.
---------------------------------------------------------------------------

    Comment: Earthjustice asserted that EPA improperly raised the 
proposed SO2 limit (based on use of DSI) from 0.21 to 0.23 
lb/MMBtu. Earthjustice said that this increase was inappropriate, as it 
was based on SO2 emission data that did not account for 
controls. Since proper controls dampen the variability of emissions, 
Earthjustice said that the emission limit should not be raised to 
account for variability.
    Response: As noted in a response to a similar comment regarding our 
NOX BART determination, we acknowledge that observed 
emissions variability at Sundt Unit 4 without SO2 controls 
may not be the same as its emissions variability when operating with 
DSI. We note, however, that even emission units with well-operated 
controls will experience some degree of emissions variability. As noted 
in our proposed rule, we developed this upward revision based on site-
specific emission data reported to EPA's CAMD for Sundt Unit 4. Given 
the site-specific basis for our upward revision, we do not consider it 
as an unreasonable estimate of emissions variability. We acknowledge 
that there might be other methods of accounting for this variability. 
However, we did not receive any comments that described or proposed any 
such alternate methodology. Therefore, we are finalizing the 
SO2 emission limit of 0.23 lb/MMBtu as proposed.

[[Page 52433]]

4. BART Analysis and Determination for PM10
    Comment: ADEQ indicated that it supports EPA's decision to require 
BART for particulate matter (PM) in terms of a PM10 limit of 
0.03 lb/MMBtu. While agreeing that fabric filter baghouses are the best 
technology for PM reductions from Sundt Unit 4, Earthjustice asserted 
that EPA should set a lower emission limit as BART. According to 
Earthjustice, stack test results for PM10 show that the 
existing baghouses at Sundt Unit 4 can achieve lower emission rates 
than the 0.03 lb/MMBtu rate that EPA proposed as BART (citing the TSD 
at 23). Earthjustice stated that there are hundreds of instances of 
coal units with baghouses achieving emission rates lower than 0.03 lb/
MMBtu, citing the docket for the Mercury Air Toxics Standards (MATS).
    Response: We disagree that the proposed 0.030 lb/MMBtu emission 
limit for filterable PM10 is too high. The 0.022 lb/MMBtu 
emission rate summarized on page 23 of the TSD is the average of 
multiple test runs that range from 0.016 lb/MMBtu to 0.039 lb/
MMBtu.\59\ Emission limitations under the CAA must be continuous and 
BART must be an emission limitation that is achievable.\60\ Thus, a 
BART emission limitation should be one that a facility can continuously 
achieve. The performance test data indicate that a PM emission limit of 
0.030 lb/MMBtu is achievable by the facility, and will also result in 
actual emission reductions. In addition, the BART limit is 
substantially lower than the PM limit contained in the facility's 
current operating permit,\61\ substantially decreasing the PM emissions 
authorized at the facility.
---------------------------------------------------------------------------

    \59\ The original Method 5 test results are included as Docket 
Item F-28--TEP Sundt4 Test Results.pdf.
    \60\ 42 U.S.C. 7602(k) (definition of ``emission limitation''); 
40 CFR 51.301 (definition of ``BART'').
    \61\ 233 lb/hour, per page 2 of the TSD. The BART limit would be 
equivalent to approximately 41 lb/hour.
---------------------------------------------------------------------------

    MATS establishes an emission limit of 0.030 lb/MMBtu for filterable 
PM (as a surrogate for toxic non-mercury metals) as representing MACT 
for coal-fired electric generating units (EGUs). The BART Guidelines 
provide that ``unless there are new technologies subsequent to the MACT 
standards which would lead to cost-effective increases in the level of 
control, you may rely on the MACT standards for purposes of BART.'' 
\62\ We consider baghouses to be the most stringent PM control 
technology for coal-fired EGUs. Moreover, the commenter has not 
identified a new or more stringent technology. As a result, we consider 
0.030 lb/MMBtu to be an appropriate continuously achievable BART limit 
for Sundt Unit 4.
---------------------------------------------------------------------------

    \62\ BART Guidelines, Section IV.C. ``How does a BART review 
relate to Maximum Achievable Control Technology (MACT) Standards 
under CAA section 112, or to other emission limitations required 
under the CAA?''
---------------------------------------------------------------------------

5. Better-than-BART Alternative
    Comment: Multiple commenters expressed support for the ``better-
than-BART alternative'' for Sundt Unit 4. Sierra Club stated that 
overall, EPA has done an excellent job in its FIP. However, Sierra Club 
also asserted that substituting coal with natural gas is not the 
ultimate solution. The fuel substitution will address the pollution 
problem associated with coal combustion, but Sierra Club argued that 
TEP should transition toward renewable energy sources, and be a leader 
in developing solar, wind, and other renewable sources for the purpose 
of energy generation.
    TEP noted that a fuel change to natural gas meets the RHR's 
requirements for alternative measures in lieu of BART in that it will 
achieve greater reasonable progress than the implementation of BART. 
TEP added that because emissions under BART or the alternative would 
emanate from the same stack (and therefore the distribution of 
emissions is not significantly different), the alternative achieves 
greater reasonable progress simply because it will result in greater 
emissions reductions. In addition, TEP noted that EPA's finding that 
``natural gas provides better visibility improvement than the proposed 
BART determination'' is consistent with the results of modeling 
performed by a contractor (AECOM) for TEP. Several other commenters 
(ADEQ, ANGA, Earthjustice, NPS, TPMEC, Friends of Saguaro National Park 
and a private individual) expressed general support for the better-
than-BART alternative.
    Response: We acknowledge the commenters' support of the proposed 
BART alternative. Today's final rule provides TEP with the option to 
comply either with the BART limits within three years of publication of 
the final rule or with the requirements of the BART alternative by 
December 31, 2017. With regard to the comments concerning renewable 
energy, we note that the BART Guidelines indicate that ``[w]e do not 
consider BART as a requirement to redesign the source when considering 
available control alternatives.'' \63\ We therefore consider a 
requirement for TEP to transition to renewable energy to be beyond the 
scope of what the RHR requires.
---------------------------------------------------------------------------

    \63\ BART Guidelines, Section IV.D.1.5.
---------------------------------------------------------------------------

    Comment: ACCCE said that the BART alternative should be rejected 
because it does not lead to an improvement in humanly perceptible 
visibility. According to ACCCE, EPA stated that switching from coal to 
natural gas under the better-than-BART alternative will lead to a 
higher visibility improvement than the combination of SNCR and DSI 
together. Yet, with one exception, the areas affected by Sundt Unit 4 
will not see a greater than 1.0 dv improvement. Again, ACCCE made the 
case that it is up to the states to make BART-eligibility 
determinations, but if it is determined that EPA has correctly 
classified Sundt Unit 4 as BART-eligible, it is Arizona, not EPA, that 
must finalize a BART determination for the unit. However, if this does 
not occur, ACCCE reiterated that it disagrees with EPA's analysis to 
require BART, since it does not result in humanly perceptible 
visibility improvement.
    Response: As explained in response to similar comments on our BART 
analyses above, visibility improvement is not required to be humanly 
perceptible in order for a control to be required as BART. Arizona did 
not include a BART analysis and determination for TEP Sundt 4 in any of 
its RH SIP submittals. If Arizona submits such a determination in the 
future, we will give it due consideration under the requirements of the 
CAA and EPA's implementing regulations.
    Comment: TEP stated that the facility has been co-firing landfill 
gas in the Sundt Unit 4 boiler since 1999, and that this has been an 
integral part of the company's strategy for complying with Arizona's 
Renewable Energy Standard and Tariff, as it is among the most cost-
effective renewable resources in its portfolio. TEP added that, through 
the direct displacement of heat input otherwise provided by coal, co-
firing landfill gas has resulted in significant avoided emissions of 
carbon dioxide, SO2, PM, and other pollutants. TEP asserted 
that it must be allowed to continue an environmentally beneficial 
program.
    TEP further stated that its current tariff agreement with El Paso 
Natural Gas Company for natural gas deliveries to Sundt Unit 4 does not 
meet the fuel-sulfur specification in the definition of ``pipeline 
natural gas'' in 40 CFR 72.2, but the tariff agreement does meet the 
sulfur specifications in the definition of ``natural gas'' in 40 CFR 
72.2. TEP indicated that it has no direct control over the sulfur 
content of the natural gas delivered to Sundt, and limiting the fuel 
burned at Sundt Unit 4 to ``pipeline

[[Page 52434]]

natural gas'' would prohibit TEP's ability to select the alternative to 
BART, which TEP and many other stakeholders view as the preferred 
choice. Accordingly, TEP recommended several revisions to the 
regulatory language for the better-than-BART alternative that would 
revise the SO2 emission limit and fuel restriction to 
correspond to the definition of ``natural gas'' rather than ``pipeline 
natural gas'' and provide for co-firing of landfill gas. TEP noted that 
regardless of the SO2 emission limit that EPA selects for 
the alternative to BART, or the method identified to demonstrate 
compliance with that limit, SO2 emissions from Sundt Unit 4 
under the alternative to BART will be orders of magnitude lower than 
SO2 emissions would be through the application of BART.
    Response: We agree that the continued co-firing of landfill gas 
does not adversely affect whether the fuel switch to natural gas 
achieves greater emissions reductions than the aggregate BART 
determinations for Sundt Unit 4. We are therefore revising the 
regulatory language to provide for the co-firing of landfill gas. In 
addition, we are revising the SO2 emission limit in the 
better-than-BART alternative (and the emissions value used to evaluate 
whether the alternative is better-than-BART) to correspond to the 
definition of ``natural gas'' per 40 CFR 72.2. These revised emission 
calculations are contained in our docket, and are summarized in our 
response to the following comment.\64\
---------------------------------------------------------------------------

    \64\ See spreadsheet titled ``Revised BART Alternative Emission 
Calculations.xls.'' Specifically, the SO2 emission factor 
for natural gas was revised from 0.00064 lb/MMBtu to 0.057 lb/MMBtu.
---------------------------------------------------------------------------

    Comment: TEP stated that stack testing to demonstrate compliance 
with the PM10 limit while burning natural gas is 
unnecessary. According to TEP, the PM10 emission limit of 
0.010 lb/MMBtu that EPA proposed under the alternative to BART was 
developed based on a calculation using an AP-42 emission factor, but 
the proposal requires a compliance demonstration by conducting 
performance stack testing using EPA Method 201A and Method 202, per 40 
CFR part 51, Appendix M. TEP stated that stack testing is a suitable 
method of determining compliance with an emission limit when either (1) 
it is necessary to verify that required controls are in place and 
operating correctly, or (2) to verify that a source is designed and 
constructed (in the case of a new unit) to meet a particular 
performance standard. However, according to TEP, neither of those 
situations applies to implementation of the alternative to BART on 
Sundt Unit 4, which is essentially a fuel-use limitation. TEP indicated 
that, while it has no reason to conclude that Sundt Unit 4 could not 
meet the standard, it has no experience measuring PM10 
emission levels while burning natural gas. Thus, the inclusion of 
Method 202 for condensable PM10 presents some risk. TEP 
encouraged EPA to modify the compliance demonstration requirement for 
PM10 to a calculation using AP-42 (as EPA did to set the 
standard), combined with a demonstration that natural gas is the 
primary fuel.
    Response: We partially agree with this comment. The BART 
alternative PM10 emission limit in the proposed rule (0.01 
lb/MMBtu) is based on AP-42 emissions factors for natural gas usage. 
This factor is based on information that might not represent the 
emission characteristics of Sundt Unit 4 (i.e., a coal-burning unit 
that is converted to natural gas). We do not agree, however, that it is 
appropriate to eliminate entirely the performance test requirement, but 
recognize that there is a lack of experience and history regarding 
condensable PM10 test results at the Unit. As a result, we 
are revising the PM10 compliance determination to a ``test 
and set'' approach. An initial performance test for PM10, 
based on the results of Method 202 plus either Method 5 or Method 201A, 
is still required along with subsequent performance tests if requested 
by the Regional Administrator. The results of the initial performance 
test will establish the PM10 limit with which subsequent 
performance tests must demonstrate compliance. For purposes of 
evaluating the better-than-BART alternative, our estimate of 
PM10 emissions is based upon this 0.30 lb/ton 
PM10 BART limit. Although this results in PM10 
emissions equivalent to BART, the natural gas fuel switch still results 
in a net decrease in both NOX and SO2 relative to 
the respective BART determinations. As a result, this approach does not 
alter our determination that the natural gas fuel switch is better-
than-BART. A comparison of emissions between the BART determination and 
the revised better-than-BART alternative is summarized in Table 5.

                    Table 5--Comparison of BART Determination to Better Than BART Alternative
----------------------------------------------------------------------------------------------------------------
                                                                               BART alternative      Emission
            Parameters                    Units          BART determination   (natural gas fuel      reduction
                                                                                   switch)             (tpy)
----------------------------------------------------------------------------------------------------------------
Heat Duty........................  MMBtu/hour.........  1,371..............  1,820..............  ..............
Capacity Factor..................  Percentage.........  0.49...............  0.37...............  ..............
NOX..............................  Control Technology.  SNCR+LNB+OFA.......  LNB+OFA............  ..............
                                   lb/MMBtu...........  0.31...............  0.25...............  ..............
                                   TPY................  912................  737................             175
SO2..............................  Control Technology.  Dry Sorbent          None...............  ..............
                                                         Injection.
                                   lb/MMBtu...........  0.18...............  0.057..............  ..............
                                   TPY................  530................  169................             361
PM...............................  Control Technology.  Fabric Filter......  None...............  ..............
                                   lb/MMBtu...........  0.03...............  0.03...............  ..............
                                   TPY................  88.................  88.................               0
----------------------------------------------------------------------------------------------------------------

6. Other Comments on Sundt Unit 4
    Comment: TEP stated that it generally supports EPA's BART 
determinations for Sundt Unit 4 because the control technologies 
selected as BART are available and technically feasible for the control 
of the respective pollutants. Furthermore, while TEP asserts that the 
level of visibility improvement achieved by application of these 
technologies is marginal, they conclude that the identified controls 
can be installed and operated at Sundt Unit 4 without a significant 
impact on reliability or customer rates.

[[Page 52435]]

    Response: We acknowledge TEP's support.
    Comment: TEP agreed with EPA's selection of 2011 as the baseline 
year for Sundt Unit 4's emissions and operating characteristics. In 
contrast, Earthjustice stated that EPA's BART analyses are flawed due 
to errors in EPA's emissions baseline and baseline capacity factor. 
Earthjustice noted that EPA considered Sundt Unit 4's historical 
emissions from 2008 to 2012, and selected 2011 as the baseline because 
Sundt Unit 4 predominantly burned coal that year. However, according to 
Earthjustice, Sundt Unit 4 also burned large amounts of coal in 2008, 
making it unclear why EPA did not use 2008 instead of, or in addition 
to, 2011 when determining the baseline (e.g., by creating a baseline 
averaging 2008 and 2011 emissions).
    Response: We disagree with Earthjustice's comment. In 2008, Sundt 
Unit 4 operated at a much higher capacity factor than in subsequent 
years. As discussed in a response to a previous comment, we do not 
consider the higher capacity factors observed during the pre-2009 
period to be a realistic depiction of anticipated annual emissions. As 
a result, we do not consider it appropriate to incorporate 2008 annual 
emissions into the development of baseline emissions.
    Comment: Earthjustice stated that EPA should set a one-year 
compliance deadline to install BART controls, rather than the proposed 
three-year deadline. Earthjustice noted that the CAA requires sources 
to install BART controls as ``expeditiously as practicable,'' and 
judicial opinions interpreting similar compliance deadlines in the CAA 
read this language to require compliance as soon as possible. According 
to Earthjustice, EPA set a three-year compliance deadline to install 
both DSI and SNCR based on EPA's conclusion that it will take three 
years to install DSI. The commenter asserted that DSI can be installed 
in just one year based on the record established for the MATS 
rulemaking and the rulemaking docket for this action. Earthjustice also 
noted that EPA has recognized that typical SNCR retrofits take ten to 
13 months. Earthjustice stated that it is not aware of any 
circumstances at Sundt that would require additional time to install 
DSI and SNCR. Accordingly, the commenter suggested that because the CAA 
requires BART to be installed as quickly as possible and the record 
shows that both DSI and SNCR can be installed in one year, EPA should 
set a one-year compliance deadline for both controls.
    Response: We disagree with this comment. Although we agree that 
either control technology can be installed in as little as one year, we 
do not consider it reasonable to require installation of both 
technologies, in parallel, within a single year. The CAA and the RHR 
require compliance with the BART emission limit as expeditiously as 
possible, but in no event later than five years after promulgation of 
the FIP.\65\ The three-year time frame in our proposed rule is 
consistent with this requirement.
---------------------------------------------------------------------------

    \65\ CAA section 169A(g)(4), 42 U.S.C. 7491(g)(4), 40 CFR 
51.308(e)(1)(iv).
---------------------------------------------------------------------------

    Comment: A private citizen indicated support for the proposal to 
end coal burning at the Sundt facility by the end of 2017 and requested 
that Sundt implement the requirement sooner. Specifically, the 
commenter recommended that TEP, the owner of the Sundt facility, use up 
the existing supply of coal and not purchase any additional coal. TPMEC 
similarly asked that TEP use up the coal it has on site and not buy any 
more, but proceed with the conversion. In contrast, TEP stressed that 
the timing of the elimination of coal is an integral part of the 
alternative to BART and should not be adjusted. TEP stated that because 
EPA may not consider a fuel switch as a control option for determining 
BART for a source (citing section IV.D.1.5 of the BART Guidelines), the 
decision whether to implement the alternative to BART is at the sole 
discretion of TEP. TEP added that because (1) the alternative was 
originally developed by TEP and (2) it clearly meets the requirements 
for ``better than BART,'' EPA is limited in its ability to make changes 
to certain aspects of TEP's approach.
    TEP asserted that it will need until December 31, 2017, to burn the 
existing fuel on site, ensure an adequate natural gas supply, and make 
the operational and mechanical changes necessary to achieve the 
proposed NOX emission rate. According to TEP, since the 
alternative to BART results in lower emissions on an annual basis, the 
timing for implementation is inconsequential relative to the long-term 
visibility goals of the RHR and should remain as originally outlined by 
TEP. TEP added that EPA has no obligation or authority to arbitrarily 
make a better-than-BART alternative even better by adjusting the timing 
for implementation, and therefore the timing for implementation of the 
alternative should not be adjusted.
    Response: We have considered TEP's request to revise the compliance 
deadline to December 31, 2017. We agree with TEP that this deadline is 
reasonable, given that the alternative results in greater emission 
reductions than BART on a lb/MMBtu basis for NOX, 
SO2, and PM and meets the other requirements for a better-
than-BART alternative under 40 CFR 51.308(e)(2) and (3). Therefore, we 
are setting a compliance deadline of December 31, 2017.
    Comment: TEP asserted that EPA underestimates the costs of 
controlling NOX and SO2 emissions from Sundt Unit 
4. TEP indicated that it hired a professional engineering and 
construction firm, Burns and MacDonnell (BMD), to review the cost 
estimates developed by EPA as part of its five-factor BART analysis and 
to provide new cost estimates for the installation and operation of 
various control technologies on Sundt Unit 4. The results of BMD's 
analysis are in Table 6. TEP further noted that the BART Guidelines 
provide for incorporation of site-specific factors or ``elements . . . 
that are not addressed by the Cost Control Manual,'' and stated that 
the most significant site-specific factors for Sundt Unit 4 have been 
identified by BMD in the report attached to the comments. TEP asserted 
that these factors should be incorporated into the final BART 
determination for the facility.

                          Table 6--Comparison of EPA's and BMD's Bart Analysis Results
                                 [All values are in $/ton of pollutant removed]
----------------------------------------------------------------------------------------------------------------
                                                                                                    Difference
                       Control technology                         EPA (proposed)        TEP          (percent)
----------------------------------------------------------------------------------------------------------------
                                             NOX Control Technology
----------------------------------------------------------------------------------------------------------------
Selective Non-Catalytic Reduction...............................          $3,222          $3,637              13

[[Page 52436]]

 
Selective Catalytic Reduction...................................           5,176           7,874              52
----------------------------------------------------------------------------------------------------------------
                                             SO2 Control Technology
----------------------------------------------------------------------------------------------------------------
Dry Sorbent Injection...........................................           1,857           3,088              66
Dry Flue Gas Desulfurization....................................           5,090           9,359              84
Wet Flue Gas Desulfurization....................................           5,505           8,229              50
----------------------------------------------------------------------------------------------------------------

    Response: As noted in our proposed rule and TSD, we revised upwards 
our contractor's original control cost estimates based on certain site-
specific factors noted by TEP in its letter dated May 10, 2013. We 
incorporated many, but not all, of the factors raised in that letter. 
In its comment letter on our proposed rule, TEP raised additional 
factors and asserted that the cost estimates for each of the control 
options is underestimated. In the case of SCR, dry FGD, and wet FGD, we 
stated in our proposed rule that we consider these control options to 
not be cost-effective, either in general or in relation to their 
anticipated visibility benefits. In the case of SNCR and DSI, even if 
we were to accept all of TEP's revisions included in the comment 
letter, we would still consider these options to be cost-effective 
generally and to be BART based on our consideration of costs and 
visibility benefits.
    Comment: NPS commented that that although EPA has not stated the 
reasonable level of cost-effectiveness, it assumes that the Agency 
typically uses $5,000/ton and 0.5 deciviews (dv) as thresholds. Yet, 
NPS has seen higher cost-effectiveness thresholds from EPA and other 
states. While NPS commends EPA for its presentation of cumulative 
visibility impacts and cumulative visibility benefits of reducing 
emissions, NPS also requested that EPA work with NPS to develop a 
consistent and transparent method to relate cost to visibility 
improvement.
    Response: As noted in responses to other comments, we have not 
established specific thresholds for the cost and visibility factors for 
BART. NPS is therefore correct to note that BART determinations made by 
EPA may not precisely align along a specific set of $/ton or deciview 
improvement values. Further, even where the costs of compliance and 
expected degree of visibility improvement are similar at two different 
sources, consideration of other statutory factors may result in 
different outcomes.\66\ With regard to determinations made by state 
agencies, we note that the RHR provides states with significant 
discretion in considering and weighing the five BART factors, so long 
as the factors are appropriately evaluated and the state's 
determination is supported by reasoned explanations for adopting the 
technology-based limits selected as BART. As a result, while a direct 
comparison of $/ton and deciview improvement values associated with 
BART determinations from multiple state agencies and EPA is informative 
and should carry weight in the ultimate decision, such comparisons are 
not outcome determinative.
---------------------------------------------------------------------------

    \66\ We also note that it is unusual for controls at two 
different sources to have similar visibility benefits across all 
affected Class I areas.
---------------------------------------------------------------------------

    Comment: NPS indicated that it has collected and reviewed close to 
100 BART determinations for EGUs and has found that the average cost 
per deciview for NOX reductions at EGUs is $14 million and 
the maximum cost per deciview is $34 million based on the Class I area 
with highest visibility improvement. NPS asserted that the $14 million 
figure is a good indication of the value states have placed upon 
reducing NOX for visibility purposes.
    Response: We agree with NPS that cost per deciview improvement is 
informative as a cost-effectiveness metric, including comparing the 
effect of controls on sources located in different parts of the 
country. We provided calculations of this metric in our proposal for 
this action. However, consistent with the BART Guidelines,\67\ we have 
relied more heavily on cost-effectiveness calculated as cost per 
pollutant ton reduced and related visibility improvements in deciviews 
(both at individual areas and as a cumulative sum over all affected 
areas) as opposed to the cost per deciview metric.
---------------------------------------------------------------------------

    \67\ See e.g. 70 FR 39167 (``For purposes of air pollutant 
analysis, `effectiveness' is measured in terms of tons of pollutant 
emissions removed, and `cost' is measured in terms of annualized 
control costs.'')
---------------------------------------------------------------------------

    Comment: NPS expressed support for EPA's inclusion of the 
cumulative visibility impacts and improvements associated with the 
control scenarios that were considered, noting that the EGUs evaluated 
are unusual because they impact from ten to 15 Class I areas within 300 
kilometers (km).
    Response: We agree with NPS that it is important to account for 
visibility impacts at multiple Class I areas, given that the goal of 
the visibility program is to remedy visibility impairment at all Class 
I areas.\68\ The cumulative sum, while not the only means of analyzing 
benefits across multiple Class I areas, is an easily understood and 
objective method of weighing cumulative visibility improvement, and is 
useful as part of the overall BART determination.
---------------------------------------------------------------------------

    \68\ CAA section 169A(a)(1).
---------------------------------------------------------------------------

    Comment: TEP stated that EPA should adopt version 6.42 of CALPUFF 
as the approved regulatory version for modeling regional haze, since 
this version corrects deficiencies in the chemistry and the dispersion 
functions of CALPUFF version 5.8. TEP indicated that several studies 
conducted over the last few years demonstrate that the deficiencies in 
version 5.8 result in over-estimation of the visibility impacts of 
NOX emissions in Class I areas. This causes erroneous over-
estimation of the visibility improvements from proposed BART controls 
leading to biased cost-benefit values.
    Response: We disagree with TEP for two reasons. First, CALPUFF 5.8 
is approved as a regulatory model for use by EPA in regional haze 
determinations. CALPUFF version 5.8 has been thoroughly tested and 
evaluated, and has been shown to perform consistently with the initial 
2003 version in the analytical situations for which CALPUFF has been 
approved. CALPUFF 6.42 is not an approved regulatory model because 
CALPUFF 6.42 has not yet undergone adequate review. We relied on 
version 5.8 of

[[Page 52437]]

CALPUFF because it is the EPA-approved version in accordance with the 
Guideline on Air Quality Models (``GAQM'', 40 CFR part 51, Appendix W, 
section 6.2.1.e). We updated the specific version to be used for 
regulatory purposes on June 29, 2007, including minor revisions as of 
that date. Second, EPA took into account limitations with Version 5.8 
when it suggested use of the 98th percentile day versus the maximum 
day.\69\
---------------------------------------------------------------------------

    \69\ Memorandum in docket, ``Full Technical Response to Modeling 
Comments for June 2014 Final Arizona Regional Haze FIP (Phase 
III),'' Colleen McKaughan and Scott Bohning, EPA, June 16, 2014.
---------------------------------------------------------------------------

    Comment: TEP commented that the background ammonia concentration 
used in visibility modeling is critical because ammonia is a precursor 
to particulate ammonium nitrate. EPA's use of 1.0 parts per billion 
(ppb) for ammonia background concentration for all months of the year 
will tend to overestimate the visibility benefits associated with 
reductions of NOX, particularly in the winter months. TEP 
noted that monthly ammonia measurement data from the IMPROVE monitoring 
network site in southern Arizona (Chiricahua) indicate that ammonia 
concentrations below 1.0 ppb (e.g., 0.5 ppb) are present at this site 
during the winter months. TEP asserted that use of those values will 
more accurately predict the visibility improvements expected from the 
reductions in NOX emissions. Although TEP did not perform 
any new modeling for comparison to EPA's results in the proposal, TEP 
sent a letter to EPA in May 2013 that provided clarification regarding 
certain modeling parameters and the results of modeling performed by 
TEP's contractor (AECOM). According to TEP, the modeling performed by 
AECOM included a BART control scenario involving SNCR and DSI, similar 
to EPA's proposed BART determination for Sundt Unit 4. The results of 
AECOM's modeling was a maximum visibility improvement of 0.16 dv at 
Saguaro National Park East compared to the baseline case. The TEP noted 
that EPA's modeling representing the same control configuration (SNCR 
and DSI) reported a maximum visibility improvement of 0.49 dv. TEP 
acknowledged that these differences in modeling results have little 
practical effect, as EPA has proposed that its results support a BART 
determination involving application of SNCR and DSI on Sundt Unit 4, 
and TEP does not dispute that overall finding. However, should EPA find 
a need to do additional modeling to support its final BART 
determination for Sundt Unit 4, TEP recommended that EPA incorporate 
the modeling improvements suggested in TEP's letter of May 10, 2013.
    Response: We disagree that the 1.0 ppb ammonia background we 
assumed for CALPUFF modeling is too high. It is consistent with EPA 
guidance given that some ammonia measurements are higher than 1.0 ppb, 
and the available ammonia data is variable over the areas included in 
the visibility modeling. The uncertainty over appropriate ammonia 
values leaves us without a reasonable basis for choosing a different 
constant value, or a more complex monthly varying scheme as recommended 
by the commenter. Ambient ammonia measurements for use as input to 
modeling are scarce, and measurements that include it in the form of 
ammonium still scarcer. In the absence of compelling ammonia background 
estimates, the EPA Interagency Work Group on Air Quality Modeling 
(IWAQM) Phase 2 guidance recommends the use of a 1.0 ppb ammonia 
background for arid lands, which includes Arizona.\70\ This is the only 
guidance available on this issue. It is worth noting that there are 
measurements of gaseous ammonia (NH3) that by themselves are 
close to or greater than 1.0 ppb, even in winter.\71\ Therefore, we 
consider the 1.0 ppb ammonia background that we used to be appropriate 
for this action. Finally, we agree with the commenter that the 
recommended modeling changes would have little practical effect on the 
BART determination for Sundt Unit 4.
---------------------------------------------------------------------------

    \70\ Interagency Work Group on Air Quality Modeling (IWAQM) 
Phase 2 Summary Report And Recommendations For Modeling Long Range 
Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998, 
http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
    \71\ Memorandum in docket, ``Full Technical Response to Modeling 
Comments for June 2014 Final Arizona Regional Haze FIP (Phase 
III),'' Colleen McKaughan and Scott Bohning, EPA, June 16, 2014.
---------------------------------------------------------------------------

B. Nelson Lime Plant Kilns 1 and 2

1. Subject to BART Determination
    Comment: ADEQ asserted that EPA improperly disapproved ADEQ's 
finding that Nelson Lime Plant is not subject to BART. ADEQ argued that 
ADEQ's use of a three-year average 98th percentile value 
``appropriately recognizes the highly variable visibility conditions 
that prevail in western states due to periodic wildfires that can 
result in short-term spikes in visibility impairment'' and is 
consistent with how EPA determines compliance with certain NAAQS.
    Response: These comments largely pertain to EPA's partial 
disapproval of the Arizona RH SIP and are therefore untimely, as EPA 
has already taken final action on the SIP.\72\ To the extent that the 
comments dispute EPA's proposed determination that the Nelson Lime 
Plant is subject to BART under the FIP, we disagree with the substance 
of their argument. The BART Guidelines recommend use of the 98th 
percentile modeled visibility impact across multiple years of modeling 
in order to identify sources that cause or contribute to visibility 
impairment in a Class I area.\73\ There are at least three different 
ways to determine the 98th percentile impact across three years of 
modeling: The maximum 8th high in any one year, the 22nd high impact 
over all three years, or the three-year average of the 8th high impacts 
from each year. Of these three methods, the three-year average is the 
least conservative way of determining the 98th percentile impact. 
Depending on the yearly distribution of the results, the most 
conservative 98th percentile impact may come from the maximum 8th 
highest value for each of the three years or the 22nd highest value for 
all years merged. While the BART Guidelines do not specify which value 
to use, given that the subject-to-BART determination is a screening 
test, EPA's position is that a more conservative approach, i.e., the 
22nd high of three merged years or the maximum 8th high of any one 
year, is more appropriate for this screening test. The FLMs also 
recommend a more conservative approach and have noted that other states 
have used such an approach.\74\
---------------------------------------------------------------------------

    \72\ 78 FR 46142.
    \73\ 40 CFR part 51, appendix Y, section III.A.3.
    \74\ Federal Land Managers' Air Quality Related Values Work 
Group (FLAG) Phase I Report--Revised (2010) (FLAG 2010) at 23; 
National Park Service Comments on EPA Review of Arizona Department 
of Environmental Quality (ADEQ) Determinations of Best Available 
Retrofit Technology (BART) at 2-3, and Reasonable Progress (RP) 
March 6, 2013.
---------------------------------------------------------------------------

    We also do not agree with ADEQ that a three-year average approach 
``appropriately recognizes the highly variable visibility conditions 
that prevail in western states due to periodic wildfires that can 
result in short-term spikes in visibility impairment.'' The visibility 
impacts of individual sources, including the Nelson Lime Plant, are 
determined by calculating the change in deciviews caused by the source 
compared to natural visibility conditions.\75\ While natural conditions 
could include short-term spikes from wildfires, the effect of such a 
spike in the background level of pollution is to decrease the relative 
deciview impact of

[[Page 52438]]

a given source.\76\ Thus, the possibility of short-term spikes from 
wildfires would, if anything, argue for a more conservative approach to 
evaluate an individual source's contribution. Moreover, we do not agree 
that the use of a three-year average is appropriate here simply because 
certain NAAQS use a three-year averaging period. Thus, consistent with 
the FLMs' recommendation and with the approach used by EPA and other 
states for making subject-to-BART determinations, we find that use of 
the 98th percentile impact of any one year is appropriate for making 
subject-to-BART determinations for purposes of this action.
---------------------------------------------------------------------------

    \75\ 40 CFR part 51, appendix Y, section III.A.3.
    \76\ See 70 FR at 39124 (``as a Class I area becomes more 
polluted, any individual source's contribution to changes in 
impairment becomes geometrically less'').
---------------------------------------------------------------------------

    With regard to the modeling performed for the Nelson Lime Plant, 
ADEQ's comments refer to three different modeling analyses: (1) The 
initial modeling performed by LNA; (2) the refined modeling analysis 
performed by LNA using the revised IMPROVE equation; and (3) an 
additional analysis referred to by LNA in its comments on the Phase 2 
proposal. ADEQ included the results of the first two analyses in the 
Arizona RH SIP. Both sets of results showed that for a single year, 
2003, the Nelson plant's 8th high visibility impact exceeded 0.5 
dv.\77\ Under EPA's interpretation of the 0.5 dv threshold, this makes 
the facility subject to BART. The complete results of the third 
analysis performed by LNA were not submitted to EPA.\78\ However, more 
recent modeling performed by LNA shows that the 98th percentile impact 
of the facility exceeds 0.5 dv in each of the three years modeled.\79\ 
Thus, even under the three-year averaging approach preferred by the 
State, the Nelson Lime Plant is subject to BART, according to the most 
recent modeling performed by the facility's owner. As explained above, 
under EPA's interpretation of the 0.5 dv threshold, the Nelson Lime 
Plant is subject to BART based on prior modeling. Therefore, for the 
reasons set out in our Phase 2 proposed and final rulemakings and in 
this response, we are finalizing our determination that the Nelson Lime 
Plant is subject to BART.
---------------------------------------------------------------------------

    \77\ Arizona Regional Haze SIP at 152-53, Table 10.9 and Table 
10.10.
    \78\ See 78 FR at 46154.
    \79\ BART Five Factor Analysis, Lhoist North America Nelson Lime 
Plant; Prepared by Trinity Consultants in conjunction with Lhoist 
North America of Arizona, Inc. (Public version dated September 27, 
2013), Table 4-7. As explained in our proposal, these results are 
conservative (i.e., tending to overestimate rather than 
underestimate the impacts), but appropriate for purposes of a 
subject-to-BART determination.
---------------------------------------------------------------------------

2. BART Analysis and Determination for NOX
    Comment: NPS indicated that it agrees with EPA that visibility 
improvements expected as a result of applying SNCR support this 
technology as BART for NOX.
    Response: We agree with NPS, and acknowledge its support on this 
issue.
    Comment: ADEQ asserted that the three-year compliance time provided 
in the rule does not provide enough time to retrofit SNCR on Kilns 1 
and 2 because of the difficulty of installing such controls. In 
contrast, Earthjustice argued that EPA should set a one-year compliance 
deadline for the installation of SNCR at the plant. According to 
Earthjustice, EPA recognized in the proposal that SNCR can be installed 
in one year, but speculated without any support that it might take 
longer at the Nelson Lime Plant because of a ``lack of information 
regarding SNCR installation schedules on lime kilns.'' The commenter 
stated that allowing an extra two years without any supporting record 
violates the CAA's requirement that BART be installed as expeditiously 
as practicable.
    Response: We disagree with ADEQ's assertion that a three-year 
compliance schedule is too short and with Earthjustice's assertion that 
it is too long. ADEQ has not provided any support for its assertion 
that three years is an insufficient period of time for installation, 
nor has the facility's owner made such an assertion. Regarding 
Earthjustice's contention that a shorter deadline is required, we note 
that the examples cited are for SNCR installations on cement kilns. 
There are multiple operational and design differences between cement 
and lime production.\80\ Cement and lime production processes are 
sufficiently different that it is not appropriate to assume that SNCR 
installation times for cement kilns are directly transferable to the 
application of SNCR on lime kilns. To our knowledge, SNCR has never 
been installed on a lime kiln. Given that this control technology will 
be retrofitted to a new source category for the first time, it is not 
unreasonable to expect unforeseen challenges and delays. EPA's timeline 
is conservative and takes into account this possibility. Therefore, we 
find that a requirement to install SNCR within three years is 
consistent with the provisions of the CAA and the RHR requiring 
compliance with BART emission limits as expeditiously as practicable.
---------------------------------------------------------------------------

    \80\ ``Comments on Draft NOX Control Measure Summary 
for Lime Kilns'', National Lime Association, March 30, 2006; AP-42, 
Section 11.6, Portland Cement Manufacturing; AP-42, Section 11.17, 
Lime Manufacturing.
---------------------------------------------------------------------------

    Comment: Earthjustice agreed that SNCR is a technically feasible 
control technology at the Nelson Lime Plant, but disagreed that the 
control efficiency for SNCR should be limited to 50 percent. 
Earthjustice stated that EPA's analysis must include the most stringent 
emissions reductions possible with SNCR (citing the BART Guidelines), 
and asserted that SNCRs can achieve control efficiencies significantly 
higher than 50 percent for the reasons discussed by Earthjustice in 
relation to the Clarkdale and Rillito cement plants. Earthjustice added 
that higher NOX reductions are especially appropriate at 
Nelson Lime Plant given the facility's high baseline NOX 
emissions. Earthjustice also noted that EPA provided no support in the 
record for the CEMS emissions data used in the development of the 
NOX emissions baseline.
    Response: We disagree with this comment. The information provided 
by Earthjustice consists of examples of SNCR on cement kilns. There are 
substantial differences between cement kilns and lime kilns that do not 
allow for direct comparisons of technical feasibility or control 
effectiveness. As noted previously, neither we nor the commenter were 
able to identify an instance of a lime kiln operating with SNCR in the 
United States. In addition, Earthjustice has not provided any 
information supporting an SNCR control efficiency more stringent than 
50 percent on a lime kiln.
    LNA has provided a summary of CEMS emission data, but considers it 
CBI since it also includes lime production data. We have included a 
summary of the lb/ton values from the testing period in our docket for 
the final rule because the BART limit is established in terms of lb/
ton.\81\ We have not included the mass emission rates from the testing 
period, since including both the lb/hour and lb/ton data in the docket 
would allow for the back-calculation of the lime production data.
---------------------------------------------------------------------------

    \81\ Non CBI--Summary of LNA Nelson March, May and June 2013 
CEMS Testing.xlsx.
---------------------------------------------------------------------------

3. BART Analysis and Determination for SO2
    Comment: Earthjustice disagreed with EPA's rejection of DSI 
technology based on cost considerations, and with EPA's BART reduction 
approach that relies on a change in fuels. Earthjustice disagreed with 
what it considers EPA's uncritical agreement with the company (i.e., 
DSI at 40 percent reduction) and asserted that, given the almost 4,000 
tpy of SO2

[[Page 52439]]

emitted from the two kilns, EPA's determination of the most stringent 
control efficiencies achievable should have been more thorough and 
technically grounded. Earthjustice asserted that a DSI can be optimized 
and can achieve far greater than 40 percent reduction, as the company's 
own tests show (i.e., short-term efficiencies ranging from 17 to 84 
percent). Earthjustice also asserted that even with what it considers a 
flawed analysis, the calculated cost-effectiveness value of about 
$4,000/ton reduced is well within acceptable ranges. As a result, 
Earthjustice disagreed with the weight that EPA gave to the incremental 
cost-effectiveness values and urged EPA to reconsider its 
SO2 BART determination for the Nelson Lime Plant in the 
final rule.
    By contrast, NPS said that it supports EPA's conclusion, noting 
that it is most important to reduce process emissions before adding 
expensive emissions controls. NPS indicated support for EPA's decision 
because it generally favors moving toward cleaner fuels. After changing 
the fuel at the plant, however, NPS noted that it may be appropriate to 
revisit requiring emissions controls at that time.
    Response: We acknowledge NPS's support on this issue. We disagree 
with Earthjustice that a more stringent DSI control efficiency is 
appropriate. Although the commenter notes that site-specific test data 
suggest short-term control efficiencies as high as 84 percent, there is 
no evidence that the upper range of short-term control efficiencies is 
sustainable over longer periods. As a result, when calculating annual 
emissions reductions in tpy, which is performed on an annual average 
basis, we do not consider it appropriate to use a control efficiency 
achieved over a short-term period because it might not achievable over 
a long-term annual average. Although Earthjustice asserted that the 
determination of a DSI control efficiency in our proposed rule should 
be more thorough and technically grounded, it has not provided any 
information regarding how, specifically, we should revise our analysis 
or that supports a more stringent control efficiency.
    Furthermore, as explained in more detail in a response to a comment 
from LNA below, the total cost figures in our proposed rule 
inadvertently omitted annual indirect costs. Correcting this error 
results in approximate average and incremental cost-effectiveness 
values of $4,800/ton and $10,200/ton for Kiln 1 and $4,500/ton and 
$9,500/ton for Kiln 2.\82\ The largest incremental visibility benefit 
of DSI relative to the visibility benefit of the proposed fuel mixture 
change at a single Class I area is 0.11 dv at Grand Canyon National 
Park.\83\ We do not consider this level of incremental cost to be 
warranted by the incremental visibility benefit of DSI relative to the 
fuel mixture change. However, additional controls for the Nelson Lime 
Plant, such as DSI, should be considered for purposes of ensuring 
reasonable progress in future planning periods.
---------------------------------------------------------------------------

    \82\ ``LNA Nelson Control Costs (revised for Final Rule).xlsx.''
    \83\ See 79 FR 9341, Table 26.
---------------------------------------------------------------------------

    Comment: LNA determined that compliance with the SO2 
emission limits within six months after the effective date of the final 
rule in the Federal Register, likely in July 2014, is not feasible. 
Therefore, the proposed six-month compliance window is unreasonable. 
Compliance with the SO2 emission limits is based on a two-
step process: (1) Use of a CEMS to determine actual SO2 
emissions from each kiln; and (2) use of daily production tonnage. LNA 
estimated that an 18-month period is a more reasonable compliance 
timeframe for a system that supports both NOX and 
SO2 CEMS as well as new weigh scales on lime storage silo 
transfer belts.
    Response: We agree that a six-month time period is an insufficient 
amount of time for the design, installation, and optimization of an 
SO2 CEMS in this case. In other cases in which compliance 
with a BART limit does not involve construction of add-on controls, but 
does involve installation of CEMS, we have provided a twelve-month 
window for compliance.\84\ In this case, taking into account that 
multiple CEMS (NOX and SO2) will need to be 
installed, and the fact that the facility does not currently operate 
with CEMS, may not have existing systems or infrastructure in place, 
and is replacing lime weigh scales, we consider an 18-month compliance 
time frame to be as expeditious as practicable. Therefore, we are 
revising the compliance deadline for SO2 at Nelson Lime 
Plant to eighteen months from the effective date for the final rule in 
the Federal Register.
---------------------------------------------------------------------------

    \84\ 77 FR 72578. The Cholla Power Plant SO2 BART 
limit required installation of inlet CEMS, with a twelve-month 
compliance deadline.
---------------------------------------------------------------------------

    Comment: LNA stated that in its BART analysis submitted to EPA, the 
fuel mixture control option was based upon a maximum of 6.5 percent ash 
content in the proposed fuel mixture. LNA asserted that it did not 
choose this value arbitrarily, but based the value on operational 
knowledge and on information provided by the manufacturer of the kilns, 
Kennedy Van Saun (KVS).
    Response: As noted in the proposed rule, we used a fuel mixture 
consistent with a maximum 6.5 percent ash content in the SO2 
BART analysis. We have not received any other comments regarding this 
issue, and the final SO2 limits finalized in today's rule 
reflect this maximum ash content.
    Comment: LNA asserted that EPA's estimate of the costs for DSI is 
unrealistic because EPA did not use site-specific input values. In 
addition, LNA said that there are errors in EPA's cost calculations. 
LNA noted various issues with EPA's cost analysis for DSI and asserted 
that the value of $4,200/ton of SO2 removed is too low.
    Response: We agree that our cost calculations contain an error in 
the ``cost summary'' tab, which is also reflected in the TSD and in the 
Federal Register preamble to our proposed rule. The total annual cost 
for DSI should represent the sum of annual direct and annual indirect 
costs, but did not include the annual indirect cost. We corrected this 
error in a new version of the spreadsheet for today's final rule.\85\ 
As a result, the average cost-effectiveness values for DSI on kilns 1 
and 2 increase to about $4,800/ton and $4,500/ton (from $4,174/ton and 
$4,085/ton, respectively). The incremental cost-effectiveness values of 
DSI, relative to the fuel mixture change, are about $10,200/ton and 
$9,500/ton (from $8,803/ton and $8,576/ton, respectively). As noted in 
the proposed rule, we did not consider DSI to be cost-effective on an 
incremental basis relative to the fuel mixture change, given the 
relatively small visibility benefits expected from DSI (0.10 dv at the 
most improved class I area and 0.29 dv cumulative). Therefore, we do 
not consider DSI to be cost-effective, relative to the fuel mixture 
change, based on these revised and even higher dollar/ton values.
---------------------------------------------------------------------------

    \85\ ``LNA Nelson Control Costs (revised for Final Rule).xlsx''.
---------------------------------------------------------------------------

    LNA provided EPA with a detailed version of DSI cost calculations 
that was designated as CBI along with a public version with most of the 
calculations redacted. Because we are generally prohibited from 
disclosing CBI, we relied on the publicly available information to 
develop a separate set of calculations for the proposed rule. While 
there are several elements of our cost estimates that differ from LNA's 
CBI-protected cost calculations, these differences are immaterial in 
light of our finding that DSI is not a cost-effective control option 
relative to the fuel

[[Page 52440]]

mixture change. Therefore, we have not further revised our cost 
analysis for DSI based on LNA's comments because the changes suggested 
by LNA would not alter our determination that DSI is not cost-effective 
for either kiln on an incremental basis.
4. BART Analysis and Determination for PM10
    Comment: ADEQ expressed support for EPA's determination that the 
existing baghouse at the Nelson Lime Plant is BART for PM10.
    Response: We acknowledge ADEQ's support on this issue.
5. Other Comments
    Comment: LNA asserted that EPA's BART proposal does not provide for 
differing emission rates during startup, shutdown, and malfunction 
(SSM), and stated that EPA should reconsider this decision that is not 
supported by the available information. The CEMS data for 
NOX and SO2 that LNA submitted in its BART 
analysis is based on periods of steady-state operation that does not 
include periods of startup and shutdown. Since the CEMS data do not 
include these emissions, LNA did not consider it appropriate for the 
proposed limits to include emissions from startup and shutdown. LNA 
proposed that the rolling 30-day limits in the proposed rule should 
apply only during periods of normal operation, and proposed 
establishing separate emission limits during periods of startup and 
shutdown. LNA provided emissions data for each of the various types of 
startup and shutdown events.
    Response: We agree that the emission limits in the proposed rule 
did not account for emissions from periods of startup and shutdown and 
we agree that the emission limits should include such periods. Because 
Section 302(k) of the CAA requires emission limits such as BART to be 
continuous,\86\ BART emission limits must apply at all times, including 
during periods of startup, shutdown, and malfunction. We therefore 
consider it appropriate to revise the proposed emission limits for 
NOX and SO2 to account for emissions from periods 
of startup and shutdown. In order to revise the emission limits to 
appropriately account for startup and shutdown emissions, we sought 
additional information from LNA following the close of the public 
comment period.\87\ In response, LNA suggested retaining the rolling 
30-day limits that would apply at all times, but revising them upward 
to accommodate startup and shutdown emissions.\88\ Following further 
discussions between EPA and LNA,\89\ LNA proposed revising the rolling 
30-day limit to an annual average limit that would apply at all 
times.\90\ LNA also proposed establishing short-term ton/day limits for 
the Kilns, which would correspond to the short-term 24-hour average 
emission rates used in the visibility modeling.\91\
---------------------------------------------------------------------------

    \86\ 42 U.S.C. 7602(k).
    \87\ Phone call between Colleen McKaughan, EPA, and Ed Barry, 
LNA, on April 10, 2014.
    \88\ Letter from Ed Barry, LNA, to Colleen McKaughan, EPA (April 
29, 2014).
    \89\ Conference calls between EPA and LNA, May 2 and 7, 2014.
    \90\ Letter from Ed Barry, LNA, to Colleen McKaughan, EPA (May 
9, 2014).
    \91\ Id.
---------------------------------------------------------------------------

    Based on our evaluation of the additional information provided by 
LNA, we are making the following revisions to the proposed emission 
limits. First, we are revising the lb/ton limits from a rolling 30-day 
basis to a rolling 12-month basis. As described in LNA's comments, 
periods of startup can exhibit substantial emissions, but with little 
to no lime production. While these startup emissions are not higher 
than those observed during normal operation on a simple mass basis 
(e.g., lb/hour, or ton/day), the fact that there is no production 
associated with these emissions complicates their inclusion when 
determining compliance with a lb/ton limit. As a result, the particular 
day(s) during which a startup event occurs will appear as a short-term 
spike in the kiln's emission rate (lb/ton). When combined with the 
preceding 29 days of emission data, this emission spike has the effect 
of driving the rolling 30-day emission rate (lb/ton) upwards. It may 
then be necessary for the unit to operate at a much lower rate of 
emissions over the next 29 days in order to ensure compliance with the 
30-day limit, which may not be technically feasible. By establishing 
the limit on a rolling 12-month basis, such short-term spikes are 
averaged with data values from over an entire year, making its impact 
on the rolling emission rate less pronounced.
    Second, in order to ensure that performance of the SNCR system 
installed at the Nelson Lime Plant is optimized, we are including in 
the final rule a series of control technology demonstration 
requirements. In particular, LNA is required to prepare and submit to 
EPA: (1) A design report describing the design of the ammonia injection 
system to be installed as part of the SNCR system; (2) data collected 
during a baseline period; (3) an optimization protocol; (4) data 
collected during an optimization period; (5) an optimization report 
establishing optimized operating parameters; and (6) a demonstration 
report including data collected during a demonstration period. While 
this type of control technology demonstration is not typically required 
as part of a regional haze plan, we consider it to be appropriate here, 
given the minimal data available about the performance of SNCR at lime 
kilns. Based upon the data collected during this process, EPA may 
revise the rolling 12-month average for the NOX emission 
limit in a future notice-and-comment rulemaking action.
    Third, we are establishing short-term 24-hour average emission 
limits (ton/day) consistent with the emission rate used in the 
visibility modeling for each respective control option. As noted above, 
revising the averaging period to an annual basis minimizes the effect 
of short-term spikes in emissions over a greater data set. In effect, 
this allows the Nelson Plant greater short-term emissions variability 
while still demonstrating compliance with the BART limit. To ensure 
that this variability does not interfere with the modeled visibility 
benefit, which is based upon reductions from the highest 24-hour 
average emission rate, we are establishing short-term ton/day emission 
limits. These limits are combined limits that apply across both Kiln 1 
and 2, on a rolling 30-kiln operating day basis. We are finalizing a 
combined Kilns 1 and 2 NOX limit of 3.20 tons/day and 
SO2 limit of 10.10 tons/day.

C. Comments on the Hayden Smelter

1. General Comments
    Comment: ASARCO agreed with the BART Guidelines ``that BART is not 
`to redesign the source,' '' and stated this understanding is inherent 
in Congress' denomination of the technology as ``best available 
retrofit technology.''
    Response: We agree that BART does not require redesign of the 
source.
    Comment: ASARCO noted that the BART Guidelines are not 
``mandatory'' as applied to the Hayden Smelter, and that EPA must 
depart from them if presented with sound technical justification.
    Response: We agree that the BART Guidelines are not binding with 
respect to the Hayden Smelter, but note that the BART Guidelines serve 
as persuasive guidance for all BART sources.
    Comment: ASARCO stated that, as further changes to air pollution 
controls at the Hayden Smelter will be required to demonstrate 
attainment of the 1-hour SO2 NAAQS, ASARCO supports EPA's 
proposal to promulgate ``a performance standard as BART rather than

[[Page 52441]]

prescribing a particular method of control,'' if EPA determines 
additional controls are needed. ASARCO stated that reconfiguration of 
the smelter might be required to attain the 1-hour SO2 NAAQS 
in the form of a ``converter retrofit project'' or CRP. ASARCO argued 
that while detailed engineering of the CRP is substantially completed, 
details must be worked out before the final project can be permitted. 
Thus, ASARCO concluded that it is critical for EPA not to finalize a 
BART FIP for SO2 that interferes with the Hayden area's 
attainment of the SO2 NAAQS. Similarly, ADEQ urged EPA to 
reevaluate its SO2 BART decision for the Hayden Smelter and 
align it with controls that ASARCO has to implement in order to comply 
with the 1-hour SO2 NAAQS.
    Response: Following the close of the public comment period, ASARCO 
provided us with additional information concerning the CRP, including a 
description of plans to replace the BART-eligible Peirce-Smith 
converters with new converters. If the BART-eligible converters are 
replaced prior to the BART compliance deadline, then the BART 
requirements would no longer apply. Accordingly, there is no basis to 
expect that the RH FIP will interfere with ASARCO's ability to ensure 
attainment of the SO2 NAAQS. We also agree that a 
performance standard rather than a particular method of control is 
appropriate for BART. As explained further below and in a revised BART 
determination included in the docket for this final rule, ASARCO has 
demonstrated that separate levels of control are necessary for the 
primary and secondary capture systems. Therefore, we are setting the 
level of control to 99.8 percent (equivalent to the existing double 
contact acid plant) for the primary capture system and 98.5 percent for 
the secondary capture system. These limits only apply if ASARCO does 
not replace the BART-eligible converters prior to the BART compliance 
deadline.
2. BART Analysis and Determination for SO2 From Converters
    Comment: ADEQ said that EPA's disapproval of ADEQ's SO2 
BART determination for the Miami and Hayden Smelters is unsupported. 
Similarly, AMA requested that EPA reconsider its decision to disapprove 
parts of the Arizona RH SIP because the State should make a BART 
determination for the smelters according to the CAA.
    Response: These comments concern EPA's partial disapproval of the 
Arizona RH SIP and are therefore untimely, as EPA has already taken 
final action on the SIP.\92\ The commenters have provided no legal 
basis for EPA to reconsider that action.
---------------------------------------------------------------------------

    \92\ 78 FR 46142.
---------------------------------------------------------------------------

    Comment: NPS expressed support for EPA's decisions based on the 
expected substantial visibility improvements associated with installing 
a new acid plant as BART for SO2 at the Hayden Smelter. In 
particular, NPS agreed with EPA's decisions to protect many Class I 
areas.
    Response: We appreciate NPS's support and note that the BART level 
of control for the converters is a performance standard and not any 
particular method of control.
    Comment: ASARCO, ADEQ, and AMA expressed doubt over the technical 
feasibility of a double contact acid plant for controlling secondary 
ventilation gases. ASARCO asserted that acid plants are not an 
``applicable'' technology, and therefore, not an ``available'' 
technology for controlling secondary ventilation gases because of low 
concentrations of SO2 and high variability in the exhaust 
gas stream. ASARCO stated that EPA failed to evaluate the technical 
feasibility of double contact acid plants when applied to these low-
strength gases, which is the second step of a BART analysis. ASARCO 
argued that, had EPA conducted an adequate analysis, it would have 
concluded that double contact acid plants are not an ``applicable'' 
technology because they do not have a ``practical potential for 
application'' to the secondary ventilation gases and hence are not an 
``available'' technology. ADEQ and AMA echoed ASARCO's comments, urging 
EPA to look at the information submitted by ASARCO and reconsider its 
proposal.
    Response: We do not agree that a double contact acid plant is 
technically infeasible for the secondary gas stream at the Hayden 
Smelter. As explained in the BART Guidelines, control technologies are 
technically feasible if either (1) they have been installed and 
operated successfully for the type of source under review under similar 
conditions, or (2) the technology could be applied to the source under 
review.\93\ The BART Guidelines further explain that the regulatory 
authority must exercise technical judgment in determining whether a 
control alternative is applicable to the source type under 
consideration. In most cases, a commercially available control option 
is presumed applicable if it has been used on the same or a similar 
source type. Absent a showing of this type, one must evaluate technical 
feasibility by examining the physical and chemical characteristics of 
the pollutant-bearing gas stream, and comparing them to the gas stream 
characteristics of the source types to which the technology had been 
applied previously.\94\ In this instance, a double contact acid plant 
is already in use at the Hayden Smelter. Therefore, it is presumed to 
be an applicable technology, absent a demonstration that specific 
circumstances preclude its application to a particular emission unit. 
Generally, such a demonstration involves an evaluation of the 
characteristics of the pollutant-bearing gas stream and the 
capabilities of the technology.\95\ No such demonstration of technical 
infeasibility has been made here. On the contrary, the record 
establishes that a double contact acid plant is feasible for the 
secondary gas stream at the Hayden Smelter.
---------------------------------------------------------------------------

    \93\ 40 CFR part 51, appendix Y, section IV.D.2.
    \94\ Id.
    \95\ See Id.
---------------------------------------------------------------------------

    In particular, while the secondary gas stream has a lower 
SO2 concentration and higher volumetric flow rate than the 
primary gas stream, these differences do not render a double contact 
acid plant technically infeasible. Indeed, EPA concluded more than 30 
years ago that ``[i]t is technically feasible . . . to design acid 
plants that will operate auto-thermally on feed streams that exhibit 
SO2 concentrations below the 3.5 to 4.0 percent range.'' 
\96\ The commenters have offered no evidence to refute this conclusion. 
Contrary to the commenters' suggestions, ASARCO's contractors, Gas 
Cleaning Technologies (GCT) and MECS,\97\ have not stated that use of a 
double contact acid plant is technically infeasible.\98\ Rather, they 
have indicated that use of this technology would present additional 
technical challenges that would make it more costly and less effective 
than estimated by EPA. In particular, GCT states that ``[a] more 
realistic 60 ppmv [parts per million by volume] outlet concentration 
would mean only 96 [percent] SO2 removal efficiency by such 
an acid plant at ASARCO. . . . when a realistic capital cost and 
removal efficiency is used for the acid plant, the $/ton SO2 
removed estimate will be more than double the $872/ton

[[Page 52442]]

SO2 indicated by EPA.'' \99\ However, as explained in the 
BART Guidelines, where the resolution of technical difficulties is 
merely a matter of increased cost, you should consider the technology 
to be technically feasible.\100\ Therefore, in this instance, EPA 
considers a double contact acid plant to be a technically feasible 
option for control of the secondary gas stream. ASARCO's assertions 
regarding cost-effectiveness are addressed below.
---------------------------------------------------------------------------

    \96\ 1984 NSPS Review at 4-3.
    \97\ This is the name of the company.
    \98\ See Letter from Steven Puricelli, MECS, to Matt Russell, 
GCT (March 5, 2014)(``MECS Letter'') (``A double acid plant could 
operate with this low secondary gas concentration . . .''); Letter 
from Matt Russell, GCT, to Jack Garrity, ASARCO (``GCT 
Letter'')(February 12, 2014) at 2 (``it may be technically feasible 
to operate an acid plant on the converter secondary gases . . .'').
    \99\ GCT Letter at 2 (``A more realistic 60 ppmv outlet 
concentration would mean only 96% SO2 removal efficiency 
by such an acid plant at ASARCO . . . when a realistic capital cost 
and removal efficiency is used for the acid plant, the $/ton 
SO2 removed estimate will be more than double the $872/
ton SO2 indicated by EPA.'').
    \100\ 40 CFR part 51, appendix Y, section IV.D.2.
---------------------------------------------------------------------------

    Comment: ASARCO stated that there are deficiencies in EPA's cost 
analysis for an acid plant. First, ASARCO asserted that EPA cannot rely 
upon the cost formula from the 1984 NSPS Review for an acid plant 
without validating current costs and, as a result, has substantially 
underestimated the cost of the proposed acid plant for the secondary 
ventilation gases. ASARCO stated that the equation that EPA used was 
derived from double-contact acid plants that were processing primary 
ventilation gases with significantly higher SO2 
concentration (4.5 percent to 8.0 percent) and flow rates up to 140,000 
standard cubic feet per minute (scfm). This compared to rates for 
secondary ventilation gases at 0 to1 percent SO2 and 275,000 
scfm.\101\ ASARCO stated that EPA's extrapolation to lower 
concentrations cannot be justified because none of the data points 
included double-contact acid plants treating secondary ventilation 
gases, for which MECS gave a significantly higher cost estimate.
---------------------------------------------------------------------------

    \101\ The original comment referred to a ``0-0.1'' percent 
concentration for secondary ventilation gases. ASARCO Comment Letter 
at 9. However, this appears to be an error, as the same letter also 
states that ``[a]t the Hayden Smelter, the SO2 content of 
secondary ventilation gas ranges from 0 to 1 [percent] 
SO2 or approximately 0 to 10,000 ppm, and averages 1580 
ppm.'' ASARCO Commenter Letter at 5.
---------------------------------------------------------------------------

    Second, ASARCO stated that supplemental heating of the acid plant 
influent gas is required, but there is no supplemental heat available 
to reduce heat load requirements as suggested by EPA. ASARCO noted that 
GCT evaluated the potential for using existing sources for heat and 
concluded that it ``does not expect any available heat source to be 
able to provide more than a small percentage of the heat required.'' 
ASARCO added that EPA does not appear to have accounted for the 
additional heat required after the interpass absorption process, nor 
the additional electrical energy associated with handling this larger 
volume of secondary ventilation gases.
    Third, ASARCO stated that EPA failed to account for other costs 
including dehumidification, which is expensive due to equipment 
installation and maintenance costs as well as the energy required to 
run the refrigeration system. ASARCO also stated that the incoming gas 
stream will require added compensatory preheating of the gas stream, 
which is an additional energy requirement that EPA does not appear to 
have addressed. Finally, ASARCO stated that EPA cannot reduce the cost 
to control secondary ventilation gas by shifting additional gas to the 
primary acid plant because the existing plant does not have the 
capacity to take any secondary gases without converter retrofit.
    Based on the foregoing, ASARCO and ADEQ asserted that EPA had 
underestimated the cost of a new acid plant by at least a factor of 
two.
    Response: We do not agree that the cost estimates provided by MECS 
and GCT are more accurate than EPA's cost estimates because both 
contractors characterized their estimates as ``ballpark,'' 
``approximate,'' and ``order-of-magnitude.'' \102\ Nonetheless, we note 
that, even if our original cost estimate for an acid plant of $872/ton 
is increased by a factor of two, as suggested by the commenter, this 
would result in control costs of about $1,800/ton of SO2. We 
consider $1,800/ton of SO2 to be very cost-effective, 
especially in light of the large visibility benefits that are expected 
to result from these controls. However, based on additional information 
provided by ASARCO, we have revised our BART analysis in several 
respects, including the addition of an amine scrubber as a third 
control option. As explained in a revised BART analysis included in the 
docket for the final rule,\103\ we find that an amine scrubber would 
result in greater emission reductions and would be even more cost-
effective than an acid plant. Therefore, we are revising our BART 
determination to reflect use of an amine scrubber rather than an acid 
plant for the secondary stream.
---------------------------------------------------------------------------

    \102\ MECS Letter at 1; GCT Letter at 2.
    \103\ Revised BART Analysis for SO2 at ASARCO 
Hayden--Converters 1, 3, 4, and 5 (June 2014).
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA underestimated the costs of wet 
scrubbing. For example, ASARCO asserted that the TSD does not address 
the technical feasibility of applying caustic wet scrubbing to the 
characteristics of the secondary ventilation gases at the Hayden 
Smelter compared to other applications for caustic wet gas scrubbing. 
ASARCO asserted that these differences affect the design basis and 
capital and operating costs associated with caustic wet scrubbing. 
ASARCO further noted that EPA omitted the cost of treating or 
landfilling the sludge from the caustic wet scrubbers, installing and 
operating a booster fan, and possible stack modifications. ASARCO 
stated that its own estimates for treating and landfilling the sludge 
are more than double EPA's total annual cost estimate.
    Response: In the proposed FIP, we estimated an annual cost of $972/
ton to control SO2 from the secondary gas stream using a 
caustic wet scrubber. This estimate is based on cost information 
provided by ASARCO. If we increase the sludge disposal costs to the 
degree that ASARCO proposes while simultaneously increasing the control 
efficiency from 85 to 90 percent as ASARCO suggested,\104\ our estimate 
of annual costs range from $909/ton, if the sludge is treated as solid 
waste, to $1,291/ton, if all sludge is treated as hazardous waste. We 
consider any cost in this range to be highly cost-effective. However, 
as explained in our revised BART analysis, use of a wet scrubber is 
more expensive on a $/ton basis and would result in fewer emissions 
reductions than an amine scrubber. Therefore, we consider a control 
efficiency of 98.5 percent, achievable with an amine scrubber, to 
constitute BART.
---------------------------------------------------------------------------

    \104\ GCT Letter at 4.
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA failed to properly consider the 
energy and non-air quality environmental impacts of compliance, which 
is the second BART factor. ASARCO asserted that the energy requirements 
for the proposed acid plants for the secondary ventilation gases are 
excessive and would require additional heat supplementation and 
additional electrical energy associated with handling the larger volume 
of secondary ventilation gases compared to primary ventilation gases. 
ASARCO also stated that the collateral emissions from preheating would 
be excessive. ASARCO provided a table using AP-42\105\ for large 
boilers and assuming low NOX burners, which shows that the 
acid plant will cause a net increase in pollutants. This increase, 
according to ASARCO, would be greater than the actual NOX 
emissions from the BART-eligible units.
---------------------------------------------------------------------------

    \105\ ``AP 42'' refers to EPA's Compilation of Air Pollutant 
Emission Factors. See http://www.epa.gov/ttnchie1/ap42/.

---------------------------------------------------------------------------

[[Page 52443]]

    Response: We do not agree that we failed to properly consider the 
energy and non-air quality environmental impacts of compliance. We have 
weighed these impacts along with the other four BART factors in 
reaching a BART determination. In particular, we do not agree that the 
energy requirements for the proposed double contact acid plant for 
secondary ventilation gases are excessive. On the contrary, we consider 
these impacts to be reasonable given the significant emission 
reductions and associated visibility benefits. Finally, we expect that 
any new combustion equipment required to heat the secondary stream will 
emit well below the AP-42 levels, which were published in 1998. 
However, if they were to emit at the levels claimed by the commenter, 
these emissions would have a far lower impact on visibility than the 
thousands of tons of SO2 presently emitted annually through 
the annular stack. In particular, the increases in the major 
visibility-impairing pollutants cited by the commenter (68.5 tpy of 
NOX, 0.29 tpy of SO2 and 3.7 tpy of PM) are quite 
modest in comparison to the projected reductions in SO2 of 
about 20,000 tpy resulting from these controls.
    Comment: ASARCO stated that the volume of wet scrubber sludge 
creates collateral environmental impacts, such as increased truck 
emissions, truck traffic, risks of accidents, and consumption of 
landfill space.
    Response: Most of the impacts noted by ASARCO are either air 
impacts (e.g., increased truck emissions) or non-environmental impacts 
(e.g., risk of accidents), and therefore do not fall within the scope 
of ``energy and non-air quality environmental impacts.'' With regard to 
the consumption of landfill space, we consider this impact to be 
reasonable in relation to the large visibility benefits and modest 
costs of control. As noted above, even if we were to double the sludge 
disposal costs, our estimate of annualized costs would not increase 
significantly.
    Comment: ASARCO stated that EPA has not demonstrated that its 
proposed SO2 removal rate (52.145(l)(4)(i)) is achievable in 
practice by the existing primary acid plant. ASARCO asserted that EPA 
cannot use a 365-day average performance estimate as a 30-day limit 
because the 99.8 percent estimate is based on what the acid plant will 
achieve on average over the course of a year. ASARCO stated that a 30-
day limit forces the existing acid plant to perform better than an 
annual limit even though EPA did not undertake a BART analysis to 
support the lower 30-day limit. Further, ASARCO stated that the 
proposed removal rate applies to periods that contain SSM events, which 
typically are not included in annual acid plant performance estimates 
or vendor guarantees. Therefore, ASARCO concluded that no data exists 
to support EPA's inclusion of SSM emissions in the proposed limit. ADEQ 
also suggested that EPA may have misinterpreted information provided by 
ASARCO concerning the performance of the primary acid plant, converting 
the annual design value to a rolling 30-day limit.
    Response: We agree that the control efficiency was determined using 
annual production and emissions data. Based on this information, we 
have modified the final determination so that the limit on the double 
contact acid plant is a rolling 365-day average rather than a rolling 
30-day average. This revision also addresses ASARCO's concern regarding 
SSM emissions because the 99.81 percent control efficiency estimate 
provided by ASARCO includes all emissions going to the acid plant and 
therefore accounts for startup and shutdown emissions.\106\ 
Furthermore, excess emissions from malfunctions are, by definition, 
unforeseeable and therefore cannot be accounted for within an emission 
limit.
---------------------------------------------------------------------------

    \106\ Letter from Jack Garrity, ASARCO to Thomas Webb, EPA, July 
11, 2013 at 15.
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA's proposed method for the 
determination of compliance with the proposed limit is subject to 
significant error. Specifically, ASARCO stated that the measurement 
error in its tailstack CEMS is ``sufficient to vary calculated results 
a full 0.1 [percent]'' and ``[t]he measurement error on the strong gas 
analyzer is nearly as great as the span of the tail gas CEMS.'' ASARCO 
added that its measurements of sulfuric acid production also ``lack the 
precision and accuracy needed for continuous demonstration of 
compliance.'' AMA also asserted that it is not technically feasible to 
continuously measure SO2 in order to demonstrate compliance 
with the requirement contemplated by EPA.
    Response: We do not agree with these comments. Because compliance 
with the emission limit is determined on a cumulative mass basis over a 
rolling 365-day period, it is measurable as a practical matter. The 
difference in scale between the inlet and outlet CEMS is not relevant 
because control efficiencies are calculated based on the ratio of the 
data from the two CEMS, not the difference.
    For example, consider a situation where 1,000 pounds of 
SO2 enters the acid plant and is controlled by 99.8 percent, 
resulting in emissions of 2 pounds of SO2. The inlet 
measurement could vary by 10 percent (i.e., the CEMS could read 
anything from 900 to 1,100 pounds, which is +/- 100 pounds) without 
affecting the compliance measurement, which is rounded to the tenths 
place. The following sample calculations with varying inlet CEMS 
readings demonstrate this concept:
    The control efficiency is calculated using the following equation:

(1 - (SO2-out/SO2-in)) * 100 percent = Control 
efficiency as a percent

    If the inlet CEMS provides a true measurement, the control 
efficiency would be:

(1 - (2/1000)) * 100 percent = 99.8 percent

    If the inlet CEMS reads 100 pounds low, the control efficiency 
would be:

(1 - (2/900)) * 100 percent = 99.778 percent, which rounds to 99.8 
percent

    If the inlet CEMS reads 100 pounds high, the control efficiency 
would be:

(1 - (2/1100)) * 100 percent = 99.818 percent, which rounds to 99.8 
percent

    Therefore, even if the inlet measurement varied by 100 pounds (10 
percent), it would not affect the control efficiency. Thus, the 
difference in scale between the acid plant inlet CEMS and tailstack 
CEMS is not relevant. Finally, we note that, while the FIP provides for 
an alternative compliance demonstration using acid production rates, we 
are not requiring the use of this method. Therefore, ASARCO may use the 
CEMS rather than acid production rates to demonstrate compliance.
    Comment: ASARCO expressed concern that EPA incorrectly 
characterized ASARCO as using ``limited cesium catalyst,'' and may not 
recognize that ASARCO has already installed cesium-promoted catalyst to 
the extent recommended by MECS.
    Response: Our characterization of ASARCO's use of cesium catalyst 
as ``limited'' was not intended to suggest that additional cesium-
promoted catalyst is necessary or appropriate for the existing double 
contact acid plant at the Hayden Smelter. Rather, we noted the 
``limited'' use of cesium catalyst at the existing double contact acid 
plant as evidence that the 99.8 percent control efficiency achieved by 
the existing double contact acid plant is a reasonable estimate of the 
efficiency achievable at a new double contact acid plant.
    Comment: ASARCO stated that the proposed limit should be adjusted 
to

[[Page 52444]]

reflect the realities of metallurgical acid plant operation. ASARCO 
added that a simpler measure, similar to the NSPS for Primary Copper 
Smelters' use of a limit on SO2 in the tail gas, is likely a 
better solution, which would accommodate the process variation and 
measurement error that will be encountered. Until such a standard is 
developed, ASARCO asserted that the work practice standard in paragraph 
(l)(12) and the existing NSPS limit of 650 ppmv, six-hour average, 
under which the smelter already achieves substantial emission 
reductions, provides a workable limitation to ensure existing emission 
reductions are maintained.
    Response: We recognize the variable nature of the process and the 
difficulty involved in measuring a high control efficiency. For these 
reasons, we are proposing a rolling 365-day average calculated on a 
cumulative mass basis. Furthermore, because the amount of 
SO2 emitted by the converters is constantly varying, a 
simple concentration-based limit cannot be used to demonstrate that the 
process is under control.
    Comment: ASARCO stated that caustic wet scrubbing of the acid plant 
tail gas is not cost-effective for BART.
    Response: We agree that adding a wet scrubber to scrub the acid 
plant tail gas is not cost-effective for BART.
    Comment: Earthjustice stated that its primary concern with EPA's 
SO2 BART determination for the Hayden Smelter is the fate of 
the ``uncaptured'' or fugitive emissions which, while a large amount 
estimated at 1,209 tpy, are not addressed by EPA. Earthjustice 
indicated that EPA should require an analysis of shop ventilation using 
a computational fluid dynamic (CFD) model that, according to 
Earthjustice, is a common technique used to enhance capture of fugitive 
emissions in older shops. Earthjustice stated that requiring 
implementation of the resulting recommendations would enhance the 
capture system for the shop so that fugitive emissions are captured by 
a modified primary or secondary system, which would allow for treatment 
in the current/proposed emissions control systems (such as the PM 
controls and the acid plant).
    Response: We recognize that there is uncertainty in the 
determination of fugitive emissions from the Hayden Smelter. Therefore, 
rather than specify a capture efficiency, we have established a work 
practice standard that requires ASARCO to design and operate a 
secondary capture system optimized to capture the maximum amount of 
process off-gas vented from each converter at all times. In order to 
demonstrate compliance with this requirement, ASARCO must submit a 
written operation and maintenance plan to EPA for approval 180 days 
prior to the applicable compliance date and must comply with this plan 
thereafter, once it is approved by EPA. Since ASARCO has performed CFD 
analyses on the Hayden Smelter, we would expect the company to submit 
such analyses for review by EPA in determining whether the secondary 
capture system is optimized to capture the maximum amount of process 
off-gas.
    Comment: Earthjustice stated that EPA's decision to split emissions 
between the baseline primary, secondary, and uncontrolled, uncaptured 
streams might not be accurate, because EPA does not provide any support 
for these emissions levels other than noting that they are based on 
estimates by the company.
    Response: We disagree with this comment, which refers to emissions 
calculations in the Arizona RH SIP and a comment letter from ASARCO 
regarding the SIP.\107\ Our BART analysis did not rely on these 
emissions calculations. Rather, we relied upon emissions data reported 
by ASARCO to ADEQ, which we consider to be the best emissions 
information available for the Hayden Smelter. The data for the primary 
and secondary emissions is based on CEMS. While there is uncertainty 
inherent in any calculation of uncaptured emissions, Earthjustice has 
not provided any more credible emissions information or provided a 
mechanism for decreasing uncertainty in the quantification of 
uncaptured emissions. We do not have a copy of the 1994-1995 fugitive 
emissions study and did not rely directly on this study to estimate 
uncaptured emissions.
---------------------------------------------------------------------------

    \107\ See Earthjustice Comment Letter at 31, notes 53-56.
---------------------------------------------------------------------------

    Comment: Earthjustice stated that EPA proposed to require a 99.81 
percent reduction of the Hayden Smelter's SO2 emissions from 
the primary and secondary capture systems apparently based on the fact 
that the existing plant is capable of achieving that level of control. 
However, Earthjustice asserted that greater control efficiencies are 
achievable, and that EPA must therefore revise its BART analysis to 
incorporate the most stringent emission control level that the 
technology is capable of achieving (citing the BART Guidelines). 
Earthjustice, citing a paper regarding the Kennecott Smelter, stated 
that 99.95 percent control efficiency is achievable. Based on another 
report by the technology vendor Cansolv, Earthjustice suggested that a 
99.93 percent reduction is achievable. Earthjustice noted that the 
latter report also states that the CANSOLV[supreg] SO2 
Scrubbing System can achieve an outlet SO2 concentration as 
low as 0.15 lb SO2/ton acid, as opposed to EPA's proposed 
BART level of 2.49 lb/ton acid. Earthjustice urged EPA to increase the 
requirement for control at the acid plant(s) to 99.93 percent or 
greater.
    Response: We do not agree that our proposal to require a 99.8 
percent control efficiency is insufficiently stringent. The examples 
cited by Earthjustice are not directly comparable to the Hayden 
Smelter. The Kennecott Smelter uses a flash copper converting 
technology that produces copper on a continuous basis, unlike the 
Hayden Smelter's batch-process system. Replacing the batch-process 
converters at the Hayden Smelter with continuous converters would 
require a redesign of the system, which is not within the scope of 
BART.\108\ Therefore, we do not consider the 99.95 percent control 
efficiency achieved at the Kennecott Smelter to be appropriate for 
determining BART at the Hayden Smelter.
---------------------------------------------------------------------------

    \108\ 70 FR 39164 (``We do not consider BART as a requirement to 
redesign the source when considering available control 
alternatives.'')
---------------------------------------------------------------------------

    The report on the Cansolv system provided by Earthjustice is a 
presentation given by Cansolv representatives at a trade show for 
fertilizer manufacturers. The figure of 0.15 lbs SO2 per ton 
of acid produced (10 ppmv SO2) is a low-end estimate and is 
lower than any of the outlet concentrations in the table of results 
provided by Earthjustice. The report did not provide enough information 
to allow us to determine whether any of the facilities listed in the 
table operate a process similar enough to batch process copper smelting 
to be directly comparable to the Hayden Smelter. However, as explained 
above, ASARCO's contractors have stated that, ``for this application, 
Cansolv has indicated that they can achieve close to 99 [percent] 
removal efficiency with a 20 ppmv outlet gas stream.''\109\ Therefore, 
we consider 98.5 percent to be a reasonable estimate of the control 
efficiency achievable with Cansolv for treatment of the secondary 
stream at the Hayden Smelter.
---------------------------------------------------------------------------

    \109\ GCT Letter at 3.
---------------------------------------------------------------------------

    Comment: Earthjustice stated that EPA should have considered DSI 
for the control of the acid plant tailstack.
    Response: We disagree with this comment. DSI is commonly used to 
control SO2 at combustion sources such as coal-fired power 
plants and

[[Page 52445]]

incinerators. DSI requires particulate control (e.g., a baghouse or 
electrostatic precipitator) in order to collect the used sorbent. Thus, 
DSI may be a cost-effective technology when sorbent can be injected 
upstream of a particulate control device that either is already in 
service or otherwise required to meet a particulate matter limit. 
However, we are not aware of any facilities in any industry that use 
DSI downstream of an acid plant. Therefore, we do not consider it a 
technically feasible technology in this case.
3. BART Analysis and Determination for SO2 From the Anode 
Furnaces
    Comment: Earthjustice asserted that the 38 tpy of SO2 
emissions from the anode furnaces are significant, and that EPA has 
routinely controlled sources with this level of SO2 
emissions in many other instances. Accordingly, Earthjustice urged EPA 
to require DSI for SO2 controls for the anode furnaces, 
which typically achieves emissions reductions in the range of 50 to 70 
percent or greater depending on process conditions. Earthjustice 
indicated that EPA should fully evaluate this option. According to 
Earthjustice, EPA suggested a work practice standard requiring the use 
of blister copper or higher purity copper. Earthjustice stated that it 
is unclear how this work practice standard will help reduce emissions 
(because presumably the anode furnaces are currently charged with the 
98 to 99 percent pure blister copper), or how it will be enforced.
    Response: At the Hayden Smelter, the anode furnaces are charged 
only with blister copper, which is nearly 98 percent pure copper. While 
the estimated 38 tpy of SO2 emissions from the anode 
furnaces may not be ``insignificant,'' they are undoubtedly small 
compared to the more than 20,000 tpy of uncaptured emissions from the 
converters. Moreover, while Earthjustice asserted that ``EPA has 
routinely controlled sources with this level of SO2 
emissions in many other instances,'' it has not provided any examples 
of controls on emissions of this level under the RHR. Because the 
potential SO2 emissions from the anode furnaces are quite 
low relative to the airflow, DSI would not be cost-effective for 
SO2 removal at roughly $25,000/ton.\110\ We have included 
work practice standards and recordkeeping requirements in the FIP to 
assure that only blister copper is used in the anode furnace.
---------------------------------------------------------------------------

    \110\ See ``Anode Furnace--DSI Cost Calculations.'' We note that 
these capital costs in these calculations are based upon a much 
lower flowrate than that of the anode furnaces, Therefore, we 
consider these estimates to be very conservative (i.e., tending to 
underestimate rather than overestimate in this instance).
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA should clarify that the requirement 
for ``charging'' only high quality copper does not preclude fluxes and 
reducing agents such as natural gas and steam. ASARCO is concerned that 
the proposed language in 40 CFR 52.145(l)(4)(v) could be misinterpreted 
to prevent the company from poling (i.e., reducing the metal in the 
furnace to remove oxides) or adding any final fluxing agents to achieve 
anode casting chemistry requirements. ASARCO explained that while the 
bulk of converting occurs in the converters, some final refining occurs 
in the anode furnaces prior to anode casting. Therefore, ASARCO must be 
able to ``pole'' or reduce the furnace (using natural gas and/or steam) 
and add flux agents to achieve final chemistries. ASARCO suggested the 
following revision:

    Anode furnaces 1 and 2 shall only be charged 
with blister copper or higher purity copper. This charging 
limitation does not extend to the use or addition of poling or 
fluxing agents necessary to achieve final casting chemistry.

    Response: We are including this language in the final regulatory 
text because we base our cost calculations for controlling 
SO2 emissions from the anode furnaces on the current use of 
the anode furnaces, which do not process concentrates or matte with 
significant sulfur content. We have modified the regulatory language 
explicitly to allow the use of poling and fluxing agents. We expect any 
SO2 emissions resulting from the use of such agents to be de 
minimis because of the very low SO2 content of natural gas 
and steam.
4. BART Analysis and Determination for NOX
    Comment: ADEQ asserted that EPA's disapproval of ADEQ's 
determination that the Hayden and Miami Smelters are not subject to 
BART for NOX has no statutory basis, and that EPA's 
imposition of BART for NOX emissions on smelters is 
arbitrary and capricious. ADEQ argued that it had correctly determined 
that the smelters are not subject to BART for NOX because:
    (1) EPA's regulations provide that a facility whose potential to 
emit (PTE) a particular pollutant is below a certain ``significance'' 
threshold--40 tpy for NOX --is automatically not subject to 
BART; and
    (2) the units' NOX emissions do not cause or contribute 
to regional haze, because the modeled impacts for each facility's 
NOX emissions are less than 0.5 dv.
    ADEQ said that EPA argued that the PTE for the smelters should be 
calculated assuming continuous operation at maximum capacity. In ADEQ's 
opinion, this was inconsistent with EPA's acknowledgement of the 
smelters' batch process which precludes continuous operation. ADEQ 
further reasoned that even if the NOX emissions from the 
smelters were above the 40 tpy threshold and considered significant, 
the emissions still would not contribute to regional haze because their 
impact is less than 0.5 dv from each of the facilities. The estimated 
visibility impacts from NOX emissions are expected to be 
0.11 dv for the Miami Smelter and 0.01 dv from the Hayden Smelter, 
according to ADEQ.
    Response: To the extent that these comments concern EPA's partial 
disapproval of the Arizona RH SIP, they are untimely. EPA has already 
taken final action on the SIP.\111\ To the extent that that comments 
dispute EPA's proposed determination that the copper smelters are 
subject-to-BART for NOX, we disagree with their substance. 
Under the RHR, a BART determination is required for each ``BART-
eligible source'' in the State that emits ``any air pollutant'' which 
may cause or contribute to any impairment of visibility in any Class I 
area. All such sources are subject to BART.\112\ Thus, EPA and states 
``must look at SO2, NOX, and direct PM 
emissions'' in determining whether sources cause or contribute to 
visibility impairment.\113\ When all of these emissions are accounted 
for, the Hayden Smelter has a total visibility impact greater than 0.5 
dv at multiple Class I areas, and is therefore subject to BART.\114\
---------------------------------------------------------------------------

    \111\ 78 FR 46142.
    \112\ 40 CFR 51.308(e)(ii)(A).
    \113\ BART Guidelines, 40 CFR Part 51, appendix Y, section 
III.A.2.
    \114\ See, e.g. TSD at 68, Table III.D-4 (showing base case 
impact of greater than 0.5 dv at 11 Class I Areas).
---------------------------------------------------------------------------

    Once a source is determined to be subject to BART, the RHR allows 
for the exemption of a specific pollutant from a BART analysis only if 
the PTE for that pollutant is below a specified de minimis level, in 
this instance, 40 tpy for NOX.\115\ PTE is defined as the 
maximum capacity of a stationary source to emit a pollutant under its 
physical and operational design.\116\ Physical or operational 
limitations on emissions capacity (e.g., restrictions on hours of 
operation) may be taken into account, but only if those limitations are 
federally enforceable. 40 CFR 51.301. There are currently no federally

[[Page 52446]]

enforceable physical or operational limitations that would limit the 
PTE of the BART-eligible units at either the Hayden or Miami Smelters 
below the NOX de minimis threshold of 40 tpy. Therefore, we 
are finalizing our determination that both smelters are subject to BART 
for NOX.
---------------------------------------------------------------------------

    \115\ 40 CFR 51.308(e)(1)(ii)(C).
    \116\ 40 CFR 51.301.
---------------------------------------------------------------------------

    Comment: AMA disagreed with EPA's proposed NOX emissions 
cap. AMA asserted that EPA does not have the authority to finalize the 
proposed cap on NOX emissions. According to AMA, if the 
source has been determined to be subject to BART for a particular 
pollutant, EPA has, according to the CAA, the following two options: 
(1) Impose BART controls based on the outcome of the five-factor 
analysis or (2) determine that a source's emissions are de minimis and 
exempt them from the BART analysis.\117\ AMA said that the 
NOX emission caps are arbitrary and capricious and should 
not be included in the final rule.
---------------------------------------------------------------------------

    \117\ See Freeport-McMoRan Copper & Gold, Comments on Proposed 
Federal Implementation Plan for Arizona Regional Haze (EPA-R09-OAR-
2013-0588) and Request for Reconsideration of the Partial 
Disapproval of Arizona State Implementation Plan at 14.
---------------------------------------------------------------------------

    Response: We do not agree with this comment. Regional haze SIPs and 
FIPs must contain ``emission limitations representing BART'' for all 
subject-to-BART sources.\118\ In particular, either the State or EPA 
must establish an enforceable emission limit ``for each subject 
emission unit at the source'' and ``for each pollutant subject to 
review'' that is emitted from the source.\119\ This requirement applies 
even where BART is determined to be an emission limit consistent with 
existing controls. Otherwise, emissions could increase to a level where 
additional controls would be warranted for BART, but no mechanism would 
exist to require such controls.
---------------------------------------------------------------------------

    \118\ 40 CFR 51.308(e).
    \119\ BART Guidelines, 40 CFR part 51, appendix Y, section V.
---------------------------------------------------------------------------

    Comment: ASARCO commented that a traditional low-NOX 
burner does not have practical application to the converters. ASARCO 
noted that EPA cites ``AirControlNet, Version 4.1 documentation report 
by E.H. Pechan and Associates, Inc.'' dated May 2006, section III, page 
445, as support for its claimed 50 percent control efficiency for low-
NOX burners in the converters and/or anode furnaces. ASARCO 
asserted that this claim is erroneous because the report is based on 
NOX SIP Call data, which did not focus on the primary metals 
industry and is of questionable relevance. Further, ASARCO stated that 
EPA would need to demonstrate that low-NOX burner flame 
design and size constraints are appropriate for use in the converter 
and anode furnace architecture. ASARCO also stated that it is likely 
that low-NOX burners cannot achieve 50 percent control at 
the Hayden Smelter. Therefore, EPA has underestimated the cost of 
control and must recalculate.
    Response: ASARCO did not provide any documentation to support its 
claims regarding control efficiency and cost. Therefore, there is no 
basis in the record for EPA to revise our own estimates. In any case, 
any increases in the estimated cost-effectiveness of controls would not 
alter the ultimate outcome in this case, since we are finalizing our 
determination that BART for NOX is an emission limit 
consistent with no additional controls.
    Comment: ASARCO stated that BART does not authorize 
``precautionary'' limits or other limits to ``ensure the 
enforceability'' of a determination that no controls are required. 
ASARCO also stated that EPA must increase the limit to account for any 
NOX generated by EPA-mandated controls. ASARCO asserted that 
EPA does not cite, nor can it, any legal basis for imposing an 
``unqualified limit'' where the BART analysis concludes ``no further 
controls.''
    Response: We do not agree with this comment. RH SIPs and FIPs must 
contain ``emission limitations representing BART'' for all subject-to-
BART sources. In particular, either the State or EPA ``must establish 
an enforceable emission limit for each subject emission unit at the 
source and for each pollutant subject to review that is emitted from 
the source.'' This requirement applies even where BART is determined to 
be an emission limit consistent with existing controls. As explained 
elsewhere in this notice, we are finalizing our determination that the 
Hayden Smelter is subject-to-BART for NOX. Therefore, an 
emission limitation representing BART for NOX is required.
    We also do not agree that our proposed limit of 40 tpy effectively 
imposes controls. As explained in our proposal, the baseline emission 
rate of 50 tpy used for purposes of our BART analysis ``assumes that 
all of the converters are all operating simultaneously, which is not 
how they typically operate. Therefore, we expect actual emissions to be 
well below 40 tpy, which is consistent with ASARCO's own estimate.'' 
\120\ ASARCO has not retracted or modified its prior statement that 
actual NOX emissions from the Hayden Smelter are below 40 
tpy. Accordingly, ASARCO should be able to meet a limit of 40 tpy 
without installation of any new controls. Furthermore, setting an 
emission limit of 40 tpy NOX satisfies the requirements of 
40 CFR 51.308(e) for NOX and ensures that NOX 
emissions from the BART-eligible units will not contribute 
significantly to visibility impairment in the future.
---------------------------------------------------------------------------

    \120\ 79 FR 9347 (citing Letter from Krishna Parameswaran, 
ASARCO, to Gregory Nudd, EPA dated March 6, 2013, page 15).
---------------------------------------------------------------------------

    Comment: ASARCO stated that the long-term strategy does not require 
emission limits on the smelter, stating that NOX emissions 
from the smelter contribute 0.01 dv or less to regional haze. As such, 
ASARCO asserted that imposing limits on the smelter is not necessary to 
achieve the RPGs established by Arizona and, therefore, EPA has no 
legal basis for imposing a 40 tpy cap.
    Response: We do not agree with this comment. As noted above, the 
promulgation of NOX limits for the BART-eligible units at 
the Hayden Smelter is required under 40 CFR 51.308(e). With regard to 
the requirements of the long-term strategy, in addition to the 
requirement cited by ASARCO, 40 CFR 51.308(d)(3)(v)(F) requires 
consideration of the ``enforceability of emission limitations and 
control measures'' (including BART emission limitations) as part of the 
long-term strategy.
    Comment: Earthjustice asserted that EPA's analysis and conclusions 
regarding NOX emissions from the Hayden Smelter are flawed 
because EPA estimated the Hayden Smelter's NOX emissions 
based solely on the consumption of natural gas used as fuel in the 
converters and anode furnaces. EPA did not account for process 
emissions of NOX, such as thermal NOX. According 
to ASARCO, EPA did not evaluate thermal or process NOX 
emissions for any of the converters and anode furnaces at the Hayden 
Smelter, and did not address why there would not be thermal 
NOX generation at these sources. Earthjustice requested that 
EPA redo its entire NOX analysis, and start by requiring 
NOX test data from the smelters for their various sources. 
Earthjustice stated that EPA should then properly assess the baseline 
NOX emissions and proceed accordingly in terms of control 
technology evaluation and modeling, as needed.
    Earthjustice added that even if EPA maintains the proposed 12-month 
rolling cap of 40 tpy as BART in the final rule, it should require 
testing to demonstrate compliance with the BART limit. Earthjustice 
believes that such testing should not only ensure that the

[[Page 52447]]

Hayden Smelter's NOX emissions stay below 40 tpy, but would 
inform the analysis in 2018 for the second implementation period. 
Earthjustice stated that for the Hayden Smelter and all other sources, 
it is important to use actual emissions data based on site-specific 
testing, rather than rough emissions estimates based on AP-42 or other 
unsupported emissions factors.
    Finally, Earthjustice stated that in order to more accurately 
determine the Hayden Smelter's NOX emissions, EPA should 
also analyze NOX emissions from the flash furnaces which, 
although not BART-eligible, might also be significant sources of 
NOX emissions. Even though the flash furnaces are not BART-
eligible, Earthjustice stated that EPA should require reasonable 
progress controls at the flash furnaces to put Arizona's Class I areas 
closer to the 2064 glide path.
    Response: We agree that some NOX emissions might be 
formed in the converters, but we have no reliable means of estimating 
the quantity of such thermal NOX. We note that, because of 
the high activation energy of the reactions required to form 
NOX from oxygen and nitrogen, the rate of reaction is known 
to increase rapidly at temperatures above 1540 [deg]C. This is hotter 
than the temperatures found in a Peirce-Smith converter.\121\
---------------------------------------------------------------------------

    \121\ Alternative Control Techniques Document--NOX 
Emissions from Process Heaters (Revised), OAQPS (September 1993).
---------------------------------------------------------------------------

    Further, we do not consider an evaluation of NOX 
emissions from the flash furnaces to be necessary or appropriate for 
purposes of ensuring reasonable progress for this planning period. As 
explained in our proposal, we conducted a screening of point sources of 
NOX throughout Arizona to determine which sources would be 
potential candidates for RP controls.\122\ We did not identify the 
flash furnaces at the Hayden Smelter as a potentially affected source 
because they did not have any reported NOX emissions. This 
evaluation should be revisited in future planning periods.
---------------------------------------------------------------------------

    \122\ See 79 FR 9352.
---------------------------------------------------------------------------

5. Comments on Emission Limitations for PM10
    Comment: Earthjustice noted that EPA's BART analysis only focused 
on SO2 pollution for the various subject-to-BART units at 
the Hayden Smelter and suggested that EPA note the availability of 
superior fabric filter products that can provide increased PM control 
capabilities.
    Response: This comment is not timely. We previously approved ADEQ's 
determination that BART for PM10 at the Hayden Smelter is 
the existing controls. Therefore, we did not conduct a BART analysis 
for PM10.
    Comment: ASARCO stated that BART does not authorize 
``precautionary'' limits or other limits to ``ensure the 
enforceability'' of a no-control determination. ASARCO asserted that 
both ADEQ and EPA have determined that PM10 BART requires no 
more than existing controls. Therefore, EPA must rely on some legal 
basis for imposing a limit where BART establishes none. ASARCO stated 
that, at most, EPA can specify only the existing limits in the Hayden 
Smelter air permit.
    Response: We do not agree with this comment. Regional Haze SIPs and 
FIPs must contain ``emission limitations representing BART'' for all 
subject-to-BART sources.\123\ We previously approved Arizona's 
determination that existing controls constitute BART for 
PM10 at the Hayden Smelter. However, the SIP contained no 
emission limitation representing BART. Therefore, we are required to 
promulgate an emission limitation representing BART for 
PM10, as well as compliance requirements to ensure the 
enforceability of this emission limit as part of the FIP.\124\
---------------------------------------------------------------------------

    \123\ 40 CFR 51.308(e). Alternatively, plans may include an 
emissions trading program or other alternative that achieves greater 
reasonable progress toward natural visibility conditions than 
source-specific limits. No such alternative is at issue here.
    \124\ Id. See also CAA section 302(y), 42 U.S.C. 7602 (defining 
FIP 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.'').
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA's approval of the Arizona RH SIP's 
``demonstration'' that no additional PM10 controls are 
warranted is not based in any way on 40 CFR part 63, subpart QQQ 
(NESHAP) requirements. ASARCO asserted that the PM10 
demonstration and EPA's approval of it were based on the CALPUFF 
modeling and cost alone, and not in any way on 40 CFR part 63, subpart 
QQQ. Thus, ASARCO stated the final FIP should include a determination 
that 40 CFR part 63, subpart QQQ requirements are not necessary to 
enforce the PM10 BART determination and should exclude any 
40 CFR part 63, subpart QQQ requirements accordingly.
    AMA expressed similar opinions and asserted that the Arizona RH SIP 
was not based on 40 CFR part 63, subpart QQQ, but rather on the 
determination that there was no significant visibility impact from PM 
emissions. AMA asserted that for this reason, existing emission limits 
are all that are appropriate for the Hayden Smelter.
    Response: We do not agree with these comments. As explained in the 
previous response, enforceable emission limits are required to 
implement Arizona's BART determinations for PM10.\125\ ADEQ 
made the following BART determinations for PM10 at the 
Hayden Smelter:
---------------------------------------------------------------------------

    \125\ See 40 CFR 51.308(e) and BART Guidelines section V, 70 FR 
39172.

    Primary Off-gas System: The existing combination of cyclones, 
wet scrubbers, and double contact double absorption acid plant 
represents BART for the primary off-gas stream because it represents 
the best current technology. BART is therefore selected as no 
further control beyond the cyclones, wet scrubbers, double contact 
double absorption acid plant system.
    Secondary Off-gas System: The existing secondary hood baghouse 
is determined to be the best retrofit technology for the secondary 
off-gas. BART is therefore selected as no further controls beyond 
the secondary hood baghouse.
    Tertiary Ventilation System: Given the extremely small 
visibility impact and the magnitude of the costs incurred, ADEQ has 
determined that tertiary ventilation control as BART is not a 
feasible option.\126\
---------------------------------------------------------------------------

    \126\ SIP Supplement, Appendix D Section IX. This language 
appears to have been excerpted from ASARCO's own BART Demonstration. 
Compare id. with letter from Eric Hiser, Counsel for ASARCO, to 
Balaji Vaidyanathan, ADEQ dated March 20, 2013 (``ASARCO' BART 
Demonstration'') at 5.

ADEQ determined that the existing controls on the primary and secondary 
off-gas systems are the best available for PM10 and that 
tertiary ventilation control is not feasible for purposes of BART. ADEQ 
did not specify what emission limits would represent these existing 
controls. Thus, EPA must determine what emission limits reflect the 
``degree of reduction achievable'' \127\ by the selected control 
technology, in this case existing controls, to satisfy the regulatory 
requirements.
---------------------------------------------------------------------------

    \127\ 40 CFR 51.301.
---------------------------------------------------------------------------

    In making this determination, EPA considered ASARCO's own BART 
demonstration, which explicitly relies on the emission limits and 
compliance requirements in Subpart QQQ. In particular, for both the 
primary and secondary off-gas streams, ASARCO stated that, 
``[c]onsistent with the Guidelines, ASARCO has chosen to use the 
`streamlined approach' by relying on the particulate limit set for an 
acid plant in the National Emission Standard for Hazardous Air 
Pollutants (NESHAP) Subpart QQQ, Primary Copper Smelting . . .'' \128\ 
For the primary off-gas stream, ASARCO explained that Subpart QQQ 
``sets a limit of 6.2 milligrams per dry

[[Page 52448]]

standard cubic meter (mg/dscm) non-sulfuric acid particulate matter'' 
and that ``[c]ompliance with this limit would be determined by annual 
testing in accordance with Section 63.1450(b) and continuous monitoring 
of scrubbing liquid flow rate over the final two towers in the acid 
plant established, reestablished and maintained in accordance with 
Section 63.1444(h).''\129\ For the secondary off-gas stream, ASARCO 
explained that Subpart QQQ ``sets limit of 23 mg/dscm PM'' with annual 
compliance testing in accordance with Section 63.1450(a).\130\
---------------------------------------------------------------------------

    \128\ ASARCO BART Demonstration at 5 (citing BART Guidelines 
section IV.C).
    \129\ Id.
    \130\ Id.
---------------------------------------------------------------------------

    Given that ASARCO relied on the Subpart QQQ requirements as the 
basis for its own streamlined BART analysis for PM10, EPA 
considers it appropriate to include these requirements in the FIP. 
Incorporating these requirements into the FIP also fulfills the 
requirements of 40 CFR 51.308(e) for promulgation of BART emission 
limitations and is consistent with the BART Guidelines, which allow for 
streamlined BART analyses, such as the one EPA approved for 
PM10 at the Hayden Smelter, as long as the ``most stringent 
controls available are made federally enforceable for the purpose of 
implementing BART.'' \131\ Therefore, we are finalizing the 
incorporation of the requirements of Subpart QQQ into the FIP.
---------------------------------------------------------------------------

    \131\ BART Guidelines section IV.D, 70 FR 39165.
---------------------------------------------------------------------------

    Comment: ASARCO stated that the CAA's general SIP/FIP provisions do 
not support EPA's argument that sources for which there are no 
additional control requirements must nonetheless have emission limits 
established. ASARCO also stated that EPA's proposal is unacceptable 
because it suggests that where a state elects not to include a source 
in a SIP, it must include emission limits in the SIP that limit the 
non-included source's emissions to its baseline, a requirement not 
found in the CAA and unworkable as a practical matter.
    Response: We do not agree with this comment. First, we note that 
the statutory and regulatory provisions cited in footnote 179 of our 
proposed rule (CAA section 110(a)(2)(F) and 40 CFR 51.212(c), 
51.308(d)(3)(v)(C) and (F)) are not the only basis for including 
emission limitations and related compliance requirements for 
PM10 in the FIP. Several provisions of the CAA and EPA's 
regulations require the promulgation of enforceable emission 
limitations in SIPs and FIPs generally, and in regional haze plans 
specifically. In particular, CAA section 110(a)(2)(A) requires SIPs to 
``include enforceable emission limitations and other control measures, 
means, or techniques . . . as may be necessary or appropriate to meet 
the applicable requirements of [the CAA].'' \132\ One of the 
``applicable requirements'' of the CAA is that plans contain ``such 
emission limits . . . as may be necessary to make reasonable progress'' 
toward natural visibility conditions, including provisions for BART and 
a LTS.\133\ Under the RHR, plans must contain ``emission limitations 
representing BART'' for all subject-to-BART sources, as well as (1) a 
schedule for compliance with BART emission limitations for each source 
subject to BART; (2) a requirement for each BART source to maintain the 
relevant control equipment; and (3) procedures to ensure control 
equipment is properly operated and maintained.\134\ Furthermore, the 
LTS must include consideration of ``emission limitations and schedules 
for compliance to achieve the reasonable progress goal'' and the 
``enforceability of emission limitations and control measures.'' \135\ 
Among the measures needed to ensure the enforceability of emission 
limits (including BART limits) are requirements for monitoring, 
recordkeeping, and reporting, as authorized by CAA section 110(a)(2)(F) 
and 40 CFR 51.212(c).
---------------------------------------------------------------------------

    \132\ 42 U.S.C. 7410(a)(2)(A). See also Montana Sulphur & 
Chemical Co. v. EPA, 666 F.3d 1174, 1196 (9th Cir. 2012) (``EPA 
correctly reads 42 U.S.C. [ ] 7410(a)(2) as requiring states to 
include enforceable emission limits and other control measures in 
the plan itself.'').
    \133\ CAA section 169A(b)(2), 42 U.S.C. 7491.
    \134\ 40 CFR 51.308(e)(1)(iv), (v).
    \135\ Sec.  51.308(d)(3)(v)(C) and (F).
---------------------------------------------------------------------------

    Second, contrary to ASARCO's suggestion, the Hayden Smelter is 
included in the Arizona RH SIP. In particular, while the State 
erroneously found that the Hayden Smelter was not ``subject-to-BART'' 
for PM10, the SIP nonetheless included a BART determination 
for PM10 at the Hayden Smelter. EPA disapproved the State's 
not-subject-to-BART finding, but approved its BART determination that 
existing controls constitute BART for PM10. Thus, a BART 
determination for PM10 for the Hayden Smelter is part of the 
approved Arizona RH SIP. However, the SIP did not include any 
enforceable emission limitations or related compliance requirements to 
implement this determination. Therefore, we found that the SIP did not 
meet the requirements of 40 CFR 51.212(c) and 51.308(e)(1)(iv) and 
(v).\136\ We also disapproved the State's RPGs and portions of its LTS 
because the SIP did not include enforceable emission limits to 
implement the State's BART determinations.\137\ We are now required to 
promulgate a FIP to fill the gaps resulting from disapproved portions 
of the SIP. Thus, we are required to promulgate enforceable emission 
limitations to implement the State's BART determination for 
PM10 at the Hayden Smelter.
---------------------------------------------------------------------------

    \136\ 78 FR 46159.
    \137\ 78 FR 46171.
---------------------------------------------------------------------------

    Finally, we do not agree that the promulgation of enforceable 
emission limits where no new controls are required is ``novel.'' As 
explained above, inclusion of such limits is a requirement of the RHR, 
and EPA has previously promulgated such limits, even where no 
additional controls were required for BART.\138\ Even where existing 
controls represent BART, there must be an emission limitation that 
reflects ``the degree of reduction achievable'' \139\ by such controls.
---------------------------------------------------------------------------

    \138\ See, e.g. 77 FR 57884 (explaining that BART emission 
limits must be established for all pollutants subject to review, 
even where no new controls are required); id. at 57916 (establishing 
an SO2 BART limit for Holcim Cement Plant based on no new 
controls).
    \139\ 40 CFR 51.301.
---------------------------------------------------------------------------

    Comment: ASARCO stated that EPA has no legal basis for imposing 
additional limits on PM beyond the existing limits at the Hayden 
Smelter given that the PM emissions from the smelter contribute 0.04 dv 
or less to regional haze. Thus, further limits are not necessary to 
achieve the RPGs. ASARCO asserted that the LTS also does not require 
emission limits.
    Response: We do not agree with this comment. As explained above, 
the promulgation of PM10 limits for the BART-eligible units 
at ASARCO Hayden is required under 40 CFR 51.308(e). With regard to the 
requirements of the LTS, in addition to the requirement cited by the 
commenter, 40 CFR 51.308(d)(3)(v)(F) requires consideration of the 
``enforceability of emission limitations and control measures'' 
(including BART emission limitations) as part of the LTS.
6. Other Comments
    Comment: ASARCO stated that a CEMS on the bypass stack, as EPA has 
proposed at CFR 51.145(l)(6)(i), is impractical and that the stack is 
actually a shutdown ventilation duct used to redirect in-transit 
SO2 and other gases out of the work environment in the event 
that the primary ventilation system becomes unavailable. ASARCO stated 
that events leading to the use of the shutdown ventilation duct are 
always associated with the cessation of

[[Page 52449]]

smelting and converting and can be planned or unplanned.
    ASARCO explained that the estimated annual SO2 emissions 
resulting from 60 events per year (based on average process parameters 
measured during GCT's engineering study of the current system, assuming 
30 unplanned events at full calculated mass SO2 and 30 
planned events at reduced SO2 accounting for the clearing of 
the gas before shutdown) are 2.81 tons for the BART-eligible units. 
ASARCO considered this amount, less than 0.09 percent of the post-
improvement SO2 emissions, to be de minimis.
    ASARCO stated that it also considered deployment of a 
SO2 CEMS to quantify emissions resulting from use of the 
shutdown ventilation duct to be impractical because it would require 
ranging of the concentration analyzer and flow measurement 
instrumentation to enable quantification of the emissions during the 
infrequent and very brief events, while recording zero/near zero levels 
the majority of the time. The relative accuracy test audit (commonly 
called ``RATA'') required could only be done by passing representative-
strength SO2 gas past the analyzer for test periods totaling 
several hours, a situation that cannot occur (bypassing process gas 
while operating).
    Response: We agree with this comment. Because of the difficulties 
involved in operating a CEMS on a bypass stack, we have modified the 
BART determination to allow the Hayden Smelter to use test data to 
quantify emissions during normal startups and shutdowns, provided the 
facility is operated according to a startup and shutdown plan.
    Comment: AMA asserted that EPA should extend the compliance 
deadline in the rule, noting that if the rule continues as scheduled 
(promulgation by late June), the compliance date would be in June 2017. 
According to AMA, this is just months prior to the deadline of October 
4, 2018, for Arizona to comply with the 1-hour SO2 NAAQS, 
meaning that the smelters would have to have completed their projects 
to reduce SO2 emissions to prevent causing or contributing 
to violations of the NAAQS. AMA noted that the two smelters, as 
indicated by their owners ASARCO and FMMI, are already planning to 
substantially modify their plants resulting in large SO2 
reductions in order to prevent violations of the SO2 NAAQS, 
which will cost a significant amount of money, an amount higher than 
what EPA would consider reasonable under BART. AMA asked that EPA 
consider this significant undertaking by the two smelters and align the 
BART compliance deadline with the SO2 attainment deadline.
    AMA added that if nothing else, considering the projects the two 
smelters are undertaking, the EPA should consult with ASARCO and FMMI 
to ensure that the final rule does not interfere with plans the 
smelters have to reduce SO2 emissions in order meet the 1-
hour SO2 NAAQS. AMA stated that coordination of the BART 
requirements with the facilities' effort to comply with the new 
SO2 NAAQS is necessary to maintain the viability of these 
smelters, thereby preserving high-paying jobs and adding new jobs as 
the smelters install additional controls to comply with the CAA's 
visibility requirements and other programs.
    Response: We partially agree with this comment. The BART level of 
control in the FIP is a performance standard. We do not prescribe any 
particular method of control. As a result, we do not anticipate any 
incompatibility with any changes that may be needed to comply with any 
attainment plan required by the 1-hour SO2 NAAQS. With 
regard to the compliance deadline, we note that Arizona is required to 
develop a SIP that provides for attainment of the 1-hour SO2 
NAAQS as expeditiously as practicable, but no later than October 4, 
2018.\140\ Furthermore, as explained in EPA's Guidance for 1-hour 
SO2 Nonattainment Area SIP Submissions ``. . . EPA expects 
attainment plans to require sources to comply with the requirements of 
the attainment strategy at least 1 calendar year before the attainment 
date.'' \141\ Therefore, the Hayden and Miami Smelters would be 
required to comply with the attainment strategy by January 1, 
2017.\142\ Accordingly, the expected source compliance date under the 
1-hour SO2 NAAQS actually precedes the proposed compliance 
date in the RH FIP of three years from promulgation of the final rule 
(i.e., about July 2017).
---------------------------------------------------------------------------

    \140\ 78 FR 47190, 47193.
    \141\ Memorandum from Stephen Page to Regional Air Division 
Directors, Guidance for 1-Hour SO2 Nonattainment Area SIP 
Submissions (April 23, 2014) at 10.
    \142\ Id.
---------------------------------------------------------------------------

    Furthermore, based on additional information received during the 
comment period, we have decided to extend the compliance deadline for 
the secondary control system at the Hayden Smelter by an additional 
year (i.e., to about July 2018). As explained elsewhere in response to 
comments and in our revised BART analysis for the Hayden Smelter, our 
BART determination for the secondary stream now reflects the use of an 
amine scrubber rather than acid plant. We are not aware of any 
instances of an amine scrubber being used at any similar facility in 
the United States. Therefore, we no longer consider three years to be 
sufficient time for design, construction, and a shakedown period. 
Accordingly, we are finalizing a compliance deadline of four years from 
publication of the final rule for the requirements applicable to the 
secondary stream. We are retaining the proposed compliance deadline of 
three years from publication of the final rule for the requirements 
applicable to the primary stream.
    Finally, we also note that, during the development of our proposed 
FIP, we requested and received information from ASARCO and FMMI 
regarding control upgrades planned for purposes of attaining the 1-hour 
SO2 NAAQS.\143\ During the comment period on the proposed 
FIP, we received more detailed additional information from both 
companies.\144\ We have also met with representatives from both 
companies.\145\ As described elsewhere in this document, we have made 
certain revisions to the regulatory text applicable to the smelters to 
ensure that there is no incompatibility between the requirements of the 
RH FIP and the smelters' plans to ensure attainment of the 1-hour 
SO2 NAAQS.
---------------------------------------------------------------------------

    \143\ See Letters from Colleen McKaughan, EPA, to Jack Garrity, 
ASARCO, and Derek Cooke, FMMI (June 27, 2013); Letter from Jack 
Garrity, ASARCO, to Thomas Webb, EPA (July 11, 2013); letter from 
Derek Cooke, FMMI, to Thomas Webb, EPA (July 12, 2013).
    \144\ See comment letters from ASARCO and FMMI.
    \145\ See Memo Regarding Communications with ASARCO on RH FIP; 
Memo Regarding Meeting with FMMI (April 28, 2014).
---------------------------------------------------------------------------

D. Comments on the Miami Smelter

1. General Comments
    Comment: ADEQ stated that EPA's disapproval of ADEQ's 
SO2 BART determinations for the Miami and Hayden Smelters is 
unsupported. Similarly, AMA, NMA and FMMI requested that EPA reconsider 
its decision to disapprove these BART determinations. In particular, 
FMMI asserted that once EPA accounts for the technical deficiencies in 
its own BART analysis, the Agency will conclude that additional 
controls at the Miami Smelter are not justified as BART.
    Response: We do not agree with these comments. Our action on the 
Arizona RH SIP is now final, and the commenters have cited no legal 
basis for EPA to reconsider that action. Moreover, the commenters have 
mischaracterized EPA's disapproval of Arizona's SO2 BART 
determinations for the copper smelters, which was based on multiple

[[Page 52450]]

deficiencies including the lack of any five-factor analysis and any 
enforceable emission limits. The commenters' assertions regarding 
purported deficiencies in EPA's own BART analysis are addressed in 
other responses.
    Comment: ADEQ asserted that EPA's disapproval of ADEQ's 
determination that the Miami Smelter is not subject to BART for 
NOX has no statutory basis, and that EPA's imposition of 
BART for NOX emissions is arbitrary and capricious.
    Response: To the extent this comment concerns our action on the 
Arizona RH SIP, it is untimely, as that action is now final. To the 
extent it concerns our proposed FIP, we do not agree with its substance 
for the reasons set forth in response to similar comments on the Hayden 
Smelter above.
2. BART Analysis and Determination for SO2 From the 
Converters
    Comment: FMMI noted that Converter 1 has been out of service since 
the mid-1980s, and the company has no plans to reactivate it. 
Therefore, all of the SO2 emissions from the converter aisle 
should be attributed to Converters 2-5, which are the BART-eligible 
units.
    Response: We appreciate the clarification regarding Converter 1. 
Because emissions from the different converters cannot be separated for 
technical reasons, we treated all converter emissions as BART-eligible. 
Thus, the fact that Converter 1, which is not a BART-eligible unit, is 
inoperable, does not affect our BART analysis. We have revised the 
regulatory text to clarify that the requirements of the FIP do not 
apply to Converter 1.
    Comment: FMMI asserted that the ``secondary hood'' required by 40 
CFR 63.1444(d)(2) does not apply to Miami Smelter's Hoboken converters 
because the Miami Smelter does not use Peirce-Smith converters. FMMI 
also requested that EPA structure the FIP in a way that will ensure 
consistency between any new BART requirements and the controls that 
FMMI intends to install to ensure that the emissions from the Miami 
Smelter do not interfere with attainment of the 1-hour SO2 
NAAQS. ADEQ, AMA and NMA echoed these comments.
    Response: We agree that 40 CFR 63.1444(d)(2) does not apply to the 
Miami Smelter converters. Our reference to that provision of the NESHAP 
in the proposed FIP was not intended to suggest otherwise. Rather, it 
was intended to ensure that FMMI install a secondary capture system to 
collect emissions that currently escape the existing primary capture 
system at the Miami Smelter's converters. This secondary system for the 
Hoboken need not be identical to the secondary capture system used for 
the Peirce-Smith converters. Rather the FIP provides FMMI with 
substantial flexibility to design a capture system appropriate for the 
unique configuration of its converters, provided that FMMI demonstrates 
that this system is designed and operated to maximize collection of 
process off-gases vented from the converters. In fact, the aisle 
capture system that FMMI plans to install is itself a type of secondary 
capture system that could meet the requirements of the FIP, provided 
that it is optimized to capture the maximum amount of process off-gases 
vented from the converters. We have revised the regulatory language to 
clarify this requirement by removing the reference to 40 CFR 
63.1444(d)(2) and defining ``capture system'' to reflect the broad 
range of components that could be included in the system.
    Comment: FMMI stated that it is not technically feasible to route 
additional captured SO2 from the converters to the acid 
plant. FMMI explained that while, in an earlier letter, it had stated 
that SO2 emissions collected by the roofline capture system 
would be routed to the acid plant, this was an error since the routing 
is not technically feasible. Specifically, FMMI asserted that ``the 
SO2 concentrations in this gas stream are much too low and 
the flow volume too high to allow the existing acid plant to handle 
this stream'' and that ``gases from the aisle capture system would also 
have significant heating requirements, and associated air emissions, if 
they were to be routed to the existing acid plant.'' ADEQ, AMA, and NMA 
echoed FMMI's concerns regarding the technical feasibility of the 
proposed requirements for SO2.
    Response: We do not agree that the FIP requirements for the Miami 
Smelter are technically infeasible. In particular, as explained in 
response to comments from ASARCO above, while higher flow volumes and 
lower SO2 concentrations may reduce the control efficiency 
and cost-effectiveness of a double contact acid plant, they do not 
render use of such an acid plant infeasible. Nonetheless, if FMMI 
determines that the existing double contact acid plant is not adequate 
to treat emissions captured by the secondary capture system, it may use 
an alternative approach to comply with the requirements of the FIP. In 
particular, because the FIP does not prescribe any particular method of 
control, any combination of control devices may be employed to meet the 
99.7 percent control requirement. For example, FMMI may continue to use 
the existing double contact acid plant and tailstack scrubber on the 
primary stream and construct a new scrubber to treat the secondary 
stream, as it currently plans to do. Because the control efficiency is 
calculated on a cumulative mass basis, it will be determined largely by 
the degree of control achieved by the existing double contact acid 
plant and tailstack scrubber, which treat the vast majority of 
emissions from the converter aisle.\146\
---------------------------------------------------------------------------

    \146\ FMMI previously estimated a capture efficiency of up to 98 
percent for the primary capture system. Letter from Derek Cooke, 
FMMI to Tom Webb, EPA (January 25, 2013) at 5. More recently, FMMI 
has indicated that this capture efficiency will be improved by 
installation of actuated mouth covers, Freeport-McMoRan Miami Inc. 
BART Analysis (March 2014) (FMMI BART Report), at 2-4, and could be 
as high as 99.57 percent. See Memorandum from J. Nikkari, Hatch to 
C. West, FMMI (November 14, 2013) (Hatch Memo), section 3.1.2.
---------------------------------------------------------------------------

    For example, consider a situation where 100,000 pounds of 
SO2 is emitted by the converters.\147\ Of this 100,000 
pounds, 99 percent is captured by the primary capture system and ducted 
to the acid plant system, which has a control efficiency of 99.8 
percent.\148\ The remaining 1 percent is captured by the secondary 
capture system and ducted to a caustic scrubber with a control 
efficiency of 90 percent.\149\
---------------------------------------------------------------------------

    \147\ Present emissions from the converter aisle are estimated 
to be 161,564. Id.
    \148\ The estimated control efficiency of the acid plant and 
tailstack scrubber system is currently 99.69 percent. Id. section 
3.4. This control efficiency could be increased through increased 
use of the tailstack scrubber, as described further below, and 
conversion of tail gas scrubber to utilize caustic (NaOH), to 
enhance the SO2 control efficiency, which FMMI intends to 
do. See ADEQ Significant Permit Revision Application, ADEQ Class I 
Permit Number 53592, Smelter Expansion & Enhanced Controls; (July 
2013) (FMMI Permit Application), section 4.1.1.
    \149\ Id. section 4.1.4 (``Captured SO2 emissions 
were assumed to be controlled by the scrubber with an average 
efficiency of roughly 90 [percent].''

Ducted to acid plant: 99 percent of 100,000 lbs = 99,000 lbs
Controlled by acid plant: 99.8 percent of 99,000 lbs = 98,802 lbs
Ducted to scrubber: 1 percent of 100,000 lbs = 1,000 lbs
Controlled by scrubber: 90 percent of 1,000 lbs = 900 lbs
Overall control efficiency: (98,802 + 900)/100,000 = 0.997 = 99.7 
percent

    Thus, FMMI can meet this overall control efficiency by improving 
the efficiency of the primary capture system, improving the efficiency 
of the primary control system (e.g., increasing the use of cesium 
promoted catalyst, increasing operation of the tailstack scrubber, or 
converting the tailstack scrubber from a magnesium oxide scrubber to a 
caustic or amine scrubber),

[[Page 52451]]

maximizing the efficiency of any new equipment installed to control 
emissions from the secondary capture system, or any combination of 
these options.
    Comment: FMMI asserted that by using a mass-balance approach to 
estimate SO2 emissions from the converter aisle, EPA had 
overestimated emissions and thereby overestimated the visibility 
improvement and underestimated the cost per ton of additional 
SO2 controls. FMMI described ``its own attempts to measure 
fugitive SO2 emissions'' (i.e., the Roofline Study) and 
asserted that EPA should have used emission estimates based on the 
Roofline Study, instead of emission estimates based on a mass-balance 
method, which FMMI characterized as ``highly imprecise'' and 
``unclear.'' FMMI further noted that ``EPA's calculation does not 
incorporate the effect of the new converter mouth covers, which reduce 
process fugitive emissions from the converters.'' Finally, FMMI 
concluded that EPA's use of a mass-balance approach is contrary to the 
BART Guidelines, which state that the baseline emission rate ``should 
represent a realistic depiction of anticipated annual emissions from 
the source.'' Similarly, Earthjustice and NMA both questioned EPA's 
estimate of uncollected SO2 emissions.
    Response: We disagree that we overestimated uncaptured baseline 
SO2 emissions.\150\ We estimated uncaptured baseline 
SO2 emissions from the converters using the following mass-
balance approach: (1) We calculated the amount of sulfur in the 
concentrate processed by the smelter using throughput and composition 
data provided by FMMI for the maximum production day and a baseline 
year (2010); (2) we assumed full conversion of sulfur to 
SO2; (3) we apportioned 65 percent of the SO2 to 
the smelter aisle and 35 percent to the converter aisle based on 
information provided by FMMI; \151\ and (4) We assumed 95 to 98 percent 
capture of emissions by the Hoboken converters' side flues.\152\ We 
consider this modified mass-balance approach to provide a more accurate 
depiction of emissions than the mass-balance approach in the Arizona RH 
SIP, which FMMI notes ``has proven to be unreliable.''
---------------------------------------------------------------------------

    \150\ FMMI describes uncaptured emissions from the converters as 
``fugitive emissions.'' However, under the RHR, ``fugitive 
emissions'' are defined as ``those emissions which could not 
reasonably pass through a stack, chimney, vent, or other 
functionally equivalent opening.'' 40 CFR 51.301\.\ Because FMMI is 
planning to capture a significant portion of these emissions and 
route them to a scrubber, they are, by definition, not fugitive.
    \151\ Letter from Derek Cooke, FMMI to Thomas Webb, EPA (July 
12, 2013).
    \152\ See Letter from Derek Cooke, FMMI to Tom Webb, EPA 
(January 25, 2013) at 5 (reporting a range of values of 87 percent 
to 98 percent). We used the high end of this range to ensure that 
our cost per ton estimates were conservative. That is, we assumed 
the baseline level of uncaptured emissions was lower and that there 
were therefore fewer emission reductions available, resulting in 
higher cost per ton values.
---------------------------------------------------------------------------

    With regard to the Roofline Study, while we encourage ongoing 
efforts by FMMI to increase understanding of emissions that bypass the 
existing capture systems, we do not agree that the results of the 
Roofline Study are more accurate than the values that we used in our 
emission calculations. The Roofline Study measured emissions at four 
points along the open roof.\153\ Given that the roof and sides of the 
building are not fully enclosed, it is very unlikely that these four 
points accurately reflect all of the emissions currently escaping from 
the converter aisle.\154\ Indeed, the authors of the Roofline Study 
acknowledge that the emission rates presented ``may not adequately 
measure the true value of the parameter'' and are presented for 
``illustration purposes.'' \155\ We also note that, following the close 
of the comment period, we received from FMMI a report summarizing the 
results of an ``extended roofline sampling campaign'' from 
approximately March 2013 through December 2013.\156\ While this 
extended sampling effort is intended to provide ``more representative, 
long-term roofline SO2 emission estimates for current 
operation,'' \157\ it still does not account for ``unmeasured fugitive 
emissions.'' \158\ Therefore, we do not agree that this the Roofline 
Study necessarily provides a more accurate estimate of SO2 
emissions than the mass-balance method we used.
---------------------------------------------------------------------------

    \153\ Roofline Study, prepared by Trinity Consultants for 
Freeport McMoRan, Inc. (November 2013).
    \154\ We note that the FMMI Permit Application indicates that 
the roofline capture system will collect 84 percent of ``process 
fugitives'' (i.e. currently uncaptured emissions) from the 
converters, meaning that the remaining 16 percent will escape 
elsewhere. Given that FMMI is not even attempting to capture any 
emissions at the roofline now, we expect that more than 16 percent 
of presently uncaptured emissions are bypassing the roofline 
monitors and are therefore not reflected in the results of the 
roofline study.
    \155\ Id. Section 5.1.
    \156\ Report: Extended Roofline SO2 Emissions Summary 
(March 2014).
    \157\ Id. section 1, page 2.
    \158\ Id. section 3.1, page 2.
---------------------------------------------------------------------------

    Furthermore, even assuming for the sake of argument that FMMI's 
revised emission estimates based on the Roofline Study are correct, 
uncaptured baseline emissions from the converters would be 547 
tpy.\159\ In order to reach the 109 tpy estimate of uncaptured 
SO2 emissions from the converters employed in its BART 
analysis, FMMI relies on an unverified and unenforceable 80 percent 
capture efficiency from improvements to the converter mouth 
covers.\160\ However, use of this ``expected'' capture efficiency does 
not provide an adequate basis for reducing baseline uncaptured 
emissions from the converters from the current emissions level, as 
measured estimated by the Roofline Study. As explained in the BART 
Guidelines, in the absence of enforceable limitations, you calculate 
baseline emissions based upon continuation of past practice.\161\ 
Although we support measures to increase the amount of emissions 
captured by the side flue and ducted to the acid plant, at present, 
there is no enforceable emission limitation that ensures that the mouth 
covers will achieve 80 percent capture of the existing uncaptured 
converter emissions. Therefore, even if the extended roofline study did 
provide an accurate estimate of uncaptured emissions and FMMI's 
allocation of those emissions among various emission units was correct, 
baseline uncaptured emissions from the converters would be at least 547 
tpy, not 109 tpy, as indicated by FMMI.
---------------------------------------------------------------------------

    \159\ FMMI BART Report, Appendix A (BART-Eligible Baseline 
Emissions Calculations), Table A-1 (BART Baseline Emissions).
    \160\ Id. note 4.
    \161\ 40 CFR part 51, appendix Y, section IV.D.4.d.2.
---------------------------------------------------------------------------

    Comment: FMMI stated that EPA's reliance on cost data from the 
Hayden Smelter underestimates the costs of additional controls because 
the Peirce-Smith Converters used at the Hayden Smelter are 
fundamentally different from the Hoboken Converters used by FMMI. FMMI 
asserted that this and other differences in the operational 
configuration of the two facilities means that the types of controls 
available and their respective costs are not transferrable between 
facilities. FMMI noted that it had prepared its own five-factor 
analysis, which FMMI stated relies upon the most up-to-date cost 
estimates that FMMI has received from Hatch Engineering, which designed 
the smelter project including the upgraded roofline capture system and 
the new aisle scrubber. FMMI asserted that this cost data presented in 
the FMMI BART Report is the best and most accurate cost information 
that is available to FMMI and EPA at this time and that EPA should rely 
upon this cost data in any BART analyses it conducts for the Miami 
Smelter.

[[Page 52452]]

    Response: In order to avoid potential disclosure of cost data for 
the Miami Smelter claimed as CBI by FMMI, we based our cost analysis 
for the construction of secondary hooding, wet scrubbers and similar, 
though not identical, equipment on non-confidential data provided by 
ASARCO for the Hayden Smelter. FMMI included additional non-
confidential cost information in the BART Report it submitted with its 
comments. In addition, following the close of the comment period, FMMI 
withdrew its CBI claim from its prior submittals, including Appendix B 
to the BART Report.\162\ We have reviewed the BART Report and found 
that it contains a number of incorrect or unsupported assumptions that 
improperly inflate the $/ton estimates for the various control options 
presented. First, it assumes capture of emissions at the roofline 
rather than in the converter aisle itself. This design does not attempt 
to capture or control emissions until after mixing with ambient air 
inside the building, resulting in very high volumes of very low-
concentration gases that are more costly to control. Second, the cost 
estimates include costs of control for non-BART units.\163\ Third, the 
cost estimates are not supported by sufficient documentation, such as 
vendor quotes.\164\ Finally, the cost estimates include costs not 
permitted by the CCM (e.g. owner's costs).\165\ Therefore, we do not 
consider the cost estimates provided in FMMI's BART Report to 
accurately reflect the cost of potential BART controls.
---------------------------------------------------------------------------

    \162\ Letter from Jay Spehar, FMMI, to Geoffrey Glass, EPA (May 
7, 2014).
    \163\ See, e.g., BART Report page 3-15 (``Annual scrubbing 
reagent costs were calculated from total estimated SO2 
design reductions (i.e., inclusive of emission units that are not 
BART-eligible).''
    \164\ See 70 FR 39166 ``The basis for equipment cost estimates 
also should be documented, either with data supplied by an equipment 
vendor (i.e., budget estimates or bids) or by a referenced source.''
    \165\ BART Report page 3-15 (``Owner's costs were likewise 
factored as a percentage of the total direct plus indirect cost. A 
value of 6.7 percent was applied for this analysis.'')
---------------------------------------------------------------------------

    Nonetheless, in order to further evaluate the cost-effectiveness of 
SO2 controls for the converters, we have conducted a 
supplemental cost analysis based on the cost information provided by 
FMMI. In this analysis, we have employed the cost estimates provided by 
FMMI, but revised the calculations to reflect the present level of 
uncaptured emissions from the converter aisle based on the mass-balance 
approach described above.\166\ According to the supplemental analysis, 
the cost-effectiveness of the control options evaluated by FMMI falls 
in the range of $2,386 to $5,478 per ton of SO2. The upper 
end of this range is higher than we have previously found reasonable 
for purposes of BART. However, for the reasons described in the 
preceding paragraph, this estimate significantly overstates the costs 
of controlling the BART-eligible emissions. Accordingly, we do not 
agree that we should employ these costs in our BART analysis.
---------------------------------------------------------------------------

    \166\ Memo regarding BART Cost Using FMMI Data, June 11, 2014.
---------------------------------------------------------------------------

    Comment: FMMI asserted that neither the 99.7 percent control 
efficiency nor the 99.8 percent alternative control efficiency proposed 
by EPA could be feasibly measured at FMMI for three reasons. First, 
differences in precision between the acid plant inlet (percent) and 
tailstack (ppm) CEMS ``mean that the two CEMS cannot be compared with 
an acceptable degree of accuracy . . .'' Second, ``the measurement of 
acid plant inlet and tail stack gas concentrations to determine control 
efficiencies contains an underlying assumption that there is a constant 
amount of time that it takes gases to pass through the acid plant.'' 
Third, an expected 2 percent measurement drift in the acid plant inlet 
CEMS exceeds the measured concentration of the tailstack CEMS 
measurement span.
    Response: We disagree that it is technically infeasible to measure 
the required 99.7 percent control efficiency. We recognize that the 
acid plant inlet CEMS will have a much greater span than the tailstack 
CEMS. However, as explained in response to similar comments on the 
Hayden Smelter, because the emission limit is a percent control on a 
cumulative mass basis, the measurement of the inlet CEMS can vary 
appreciably without affecting compliance status.
    In addition, the compliance method in the proposed regulatory text 
makes no assumptions about residence time in any control device because 
it does not rely on instantaneous control efficiencies. Instead, it 
compares uncontrolled and controlled total masses over a 30-day period. 
Since the control efficiency data provided by FMMI were based on annual 
data, however, we have modified the final determination to be a rolling 
365-day average rather than a rolling 30-day average.
    Finally, in response to a request from FMMI,\167\ we have added an 
additional option for measuring SO2 levels in the secondary 
stream. In particular, if FMMI chooses to control the secondary stream 
using an alkali scrubber, then it may calculate the pounds of 
SO2 entering the scrubber based on the amount of alkali 
added to the scrubber liquor, rather than installing an inlet CEMS.
---------------------------------------------------------------------------

    \167\ Phone call between FMMI and EPA, May 21, 2014.
---------------------------------------------------------------------------

    Comment: FMMI requested clarification concerning EPA's proposal to 
calculate control for a combination of controlled and uncontrolled 
emissions. FMMI noted that EPA's calculated control efficiency of 99.69 
percent excluded the bypass stack.
    Response: We calculated the acid plant's control efficiency based 
on annual SO2 emissions from the acid plant tailstack and 
annual production of sulfuric acid.\168\ This is a level of control 
that FMMI has demonstrated achieving in practice when emissions are 
ducted to the acid plant. Emissions from the bypass stack consist of 
uncontrolled emissions released during startup, shutdown, and 
malfunction events.\169\ Because BART emission limits apply at all 
times, including periods of startup, shutdown, and malfunction, the 
control efficiency requirement in the FIP includes uncontrolled 
emissions from the bypass stack. FMMI reported annual average 
SO2 emissions from the bypass stack of only 65 tpy in 2011 
to 2012, and projected zero SO2 emissions from the bypass 
stack following its planned control upgrades.\170\ Therefore, any 
emissions from the bypass stack will be de minimis and will not impair 
FMMI's ability to meet the 99.7 percent control efficiency requirement 
on a rolling 365-day basis.
---------------------------------------------------------------------------

    \168\ See appendices C and J to FMMI's Jan. 2013 letter. See 
also, Memorandum from J. Nikkari, Hatch to C. West, FMMI (November 
14, 2013) (Hatch Memo), section 3.4 (calculating 99.69 percent 
control efficiency for existing acid plant and tail stack scrubber 
system).
    \169\ Letter from Derek Cooke, FMMI, to Thomas Webb, EPA 
(January 25, 2013) at 7.
    \170\ ADEQ Significant Permit Revision Application, ADEQ Class I 
Permit Number 53592, Smelter Expansion & Enhanced Controls; (July 
2013) (FMMI Permit Application), Tables A-2 and A-b.
---------------------------------------------------------------------------

    Comment: FMMI stated that its own five-factor analysis demonstrates 
that existing controls meet BART, additional controls are not 
justified, and EPA's contrary finding is based on a technically flawed 
BART analysis.
    Response: We do not agree with this comment. As described above, 
FMMI's five-factor analysis relies on unrealistically low estimates of 
uncontrolled emissions and unrealistically high estimates of control 
costs, resulting in improperly inflated $/ton estimates. Based on these 
unrealistically high $/ton values, the FMMI BART Report improperly 
concludes that no additional controls are cost-effective. Because of 
the flaws

[[Page 52453]]

underlying these cost analyses, we do not agree with this conclusion.
    Comment: FMMI stated that EPA should consider FMMI's planned 
pollution controls as a better-than-BART alternative. FMMI asserted 
that EPA is aware that FMMI is in the process of obtaining a permit 
revision to install significant new controls to ensure the smelter does 
not cause or contribute to a violation of the 1-hour SO2 
NAAQS. ADEQ also noted that FMMI is currently working with ADEQ to 
revise its permit to accommodate a facility expansion, and is 
evaluating controls necessary to comply with the 1-hour SO2 
NAAQS.
    Response: EPA is willing to consider FMMI's planned pollution 
controls for 1-hour SO2 NAAQS compliance as a potential 
``better-than-BART'' alternative under 40 CFR 51.308(e)(2). However, 
FMMI's current proposal does not meet the requirements for a better-
than-BART alternative. First, in order to qualify as a better-than-BART 
alternative, FMMI's proposed alternative would have to achieve more 
emissions reductions than BART.\171\ FMMI estimates that its proposed 
control upgrades will result in an emission reduction of 6,054 tpy of 
SO2 (future PTE minus past two-year actual).\172\ The bulk 
of this reduction would come from smelter ``fugitives'' that FMMI 
estimates would be reduced from 4,836 tpy of SO2 (actual 
from 2011-2012) to 288 tpy (potential). However, this is inconsistent 
with FMMI's BART analysis, which estimated actual baseline 
SO2 emission from 2011 to 2012 as 1,033 tpy.\173\ In order 
to make a better-than-BART demonstration, FMMI should use a consistent 
estimate of baseline emissions, rather than using different estimates 
of baseline emissions for its BART and better-than-BART analyses.
---------------------------------------------------------------------------

    \171\ See 40 CFR 51.308(e)(2)(i)(E) and (3).
    \172\ ADEQ Significant Permit Revision Application, ADEQ Class I 
Permit Number 53592, Smelter Expansion & Enhanced Controls; (July 
2013) (FMMI Permit Application), Table A-4.
    \173\ FMMI BART Analysis Table A-1.
---------------------------------------------------------------------------

    Second, FMMI's proposal would have to include a schedule for 
implementation, enforceable emission limitations, and monitoring, 
recordkeeping and reporting requirements.\174\ FMMI's proposal, as set 
forth in its permit application and the draft permit developed by 
ADEQ,\175\ does not include all of these elements. Therefore, it does 
not meet the requirements for a better-than-BART alternative. If ADEQ 
wishes to submit a better-than-BART alternative as a SIP revision, we 
will work with FMMI and ADEQ to develop such a revision.
---------------------------------------------------------------------------

    \174\ See 40 CFR 51.308(e)(2)(iii).
    \175\ ADEQ Air Quality Class I Permit  53592 (As 
Amended by Significant Revision No. 58409) Freeport McMoRan Inc. 
Miami Smelter (Draft, April 22, 2014).
---------------------------------------------------------------------------

    Comment: NPS supports EPA's proposed requirements to control 
SO2 emissions from the Miami Smelter.
    Response: We acknowledge NPS's support.
    Comment: In response to EPA's request for comment on whether a 
control efficiency more stringent than 99.7 percent is warranted, 
Earthjustice asserted that a better control efficiency is achievable, 
and as a result Earthjustice does not support EPA's proposed control 
efficiency requirement. Earthjustice indicated that the proposed 
control efficiency requirement appears to be the stated (and 
unverified) level of control currently achieved at the Miami Smelter. 
However, the BART Guidelines require EPA to base its analysis on the 
most stringent control efficiency achievable. Noting that the proposed 
level is lower than that proposed for the Hayden Smelter, Earthjustice 
stated that the control efficiency of the Miami Smelter's acid plant 
should be 99.93 percent or greater for the same reasons that 
Earthjustice put forward for the Hayden Smelter.
    Response: We disagree with this comment for the reasons described 
in response to a similar comment regarding the Hayden Smelter. In 
particular, the examples of higher control efficiencies cited by the 
commenter are not directly comparable to the Miami Smelter because they 
are different types of operation.
3. BART Analysis and Determination for NOX
    Comment: AMA, FMMI, and NMA said that the proposed NOX 
limits for the Miami Smelter exceed EPA's authority. The commenters 
asserted that because NOX emissions from the BART-eligible 
sources at FMMI are below the exception threshold, the RHR provides 
that they may be excluded from BART analysis. The commenters indicated 
that they disagree with EPA's position that ``all visibility impairing 
pollutants will be subject-to-BART once a source is subject-to-BART for 
any pollutant unless the pollutant in question is emitted at a level 
below the exception threshold.'' NMA asserted that this was 
inconsistent with EPA's prior acknowledgment that ``it is reasonable to 
read [42 U.S.C 7491(b)(2)(a)] as requiring a BART determination only 
for those emissions from a source which are first determined to 
contribute to visibility impairment in a Class I area.'' \176\ FMMI 
added that nothing in the CAA grants EPA authority to establish 
emissions caps to ensure that facilities remain at or below the 
exception threshold. Even if EPA's position were justified, baseline 
NOX emissions from the smelter, which FMMI has submitted to 
EPA, indicate that the BART-eligible equipment only emits 21.7 tpy, 
which the commenters indicated is far below the BART exception 
threshold of 40 tpy. For these reasons, the commenters opposed EPA's 
proposal for NOX at the Miami Smelter.
---------------------------------------------------------------------------

    \176\ Regional Haze Regulations and Guidelines for Best 
Available Retrofit Technology (BART) Determinations, 70 Fed. Reg. 
39,104, 39,116 (July 6, 2005) (emphasis added).
---------------------------------------------------------------------------

    FMMI and NMA also stated that EPA's partial disapproval of the 
Arizona RH SIP does not affirmatively demonstrate that the smelter is 
subject-to-BART for NOX, and EPA's proposal to subject FMMI 
to a BART analysis for NOX is legally deficient. According 
to AMA, if the source has been determined to be subject to BART for a 
particular pollutant, EPA has the following two options: (1) Impose 
BART controls based on the outcome of the five-factor analysis or (2) 
determine that a source is de minimis and exempt it from a BART 
analysis. AMA said that the NOX emissions cap is arbitrary 
and capricious and should not be included in the final rule.
    Response: We acknowledge that we inadvertently omitted from our 
proposal a complete explanation of the basis for our proposed 
determination that the Miami Smelter is subject to BART for 
NOX. However, we do not consider this omission prejudicial 
because, as noted by FMMI, the rationale for this proposed 
determination is the same as the rationale for our disapproval of 
ADEQ's determination that the Miami Smelter was not subject to BART for 
NOX.\177\ FMMI commented extensively on this element of the 
SIP action and included these comments as an attachment to its FIP 
comments. EPA responded to these comments in the context of our SIP 
action.\178\ As explained in our final action on the SIP:
---------------------------------------------------------------------------

    \177\ See 79 FR 9347 (referring to disapproval of not-subject-
to-BART finding in the Arizona RH SIP); 77 FR 75721 (proposed 
disapproval of not-subject-to-BART finding in the 2011 RH SIP); 78 
FR 29301 (proposed disapproval of not-subject-to-BART finding in the 
RH SIP Supplement).
    \178\ See 78 FR 46156 (responses to FMMI comments regarding 
proposal on 2011 RH SIP) and 46170-71 (responses to FMMI comments 
regarding proposal on RH SIP Supplement).

    Once a source is determined to be subject to BART, the RHR 
allows for the exemption of a specific pollutant from a BART 
analysis only if the PTE for that pollutant is below a specified de 
minimis level. Although a small

[[Page 52454]]

pollutant-specific baseline visibility impact may be informative in 
determining what control option may be BART, a BART analysis is 
still required for any pollutant with a PTE that exceeds the de 
minimis threshold at an otherwise subject-to-BART source.\179\
---------------------------------------------------------------------------

    \179\ 78 FR 46156 (citing 40 CFR 51.308(e)(1)(ii)(C)).

    The preamble to the 2005 revisions to the RHR and BART Guidelines 
cited by FMMI does not conflict with this interpretation. When EPA 
revised the RHR, we proposed to interpret CAA section 169A(b)(2)(A) to 
require a BART analysis for all visibility-impairing pollutants emitted 
by a source, regardless of amount. However, in the final rule, we 
explained that there were two reasonable interpretations of the 
---------------------------------------------------------------------------
statutory text:

    Section 169A(b)(2)(A) of the Act can be read to require the 
States to make a determination as to the appropriate level of BART 
controls, if any, for emissions of any visibility impairing 
pollutant from a source. Given the overall context of this 
provision, however, and that the purpose of the BART provision is to 
eliminate or reduce visibility impairment, it is reasonable to read 
the statute as requiring a BART determination only for those 
emissions from a source which are first determined to contribute to 
visibility impairment in a Class I area.\180\
---------------------------------------------------------------------------

    \180\ 70 FR 39115-16.

    FMMI cites the emphasized language, but omits the surrounding 
discussion, which explains that section 169A(b)(2)(A) could reasonably 
be read either to require a BART analysis for emissions of any 
visibility impairing pollutant from a source or to require an analysis 
only for emissions first determined to contribute to visibility 
impairment. The preamble does not state which of these two 
interpretations EPA was adopting. However, in the RHR, EPA retained the 
requirement that States make a BART determination for each ``BART-
eligible source in the State that emits any air pollutant'' which may 
cause or contribute to any impairment of visibility in any Class I 
area.\181\ The only revision made to allow for exemption of specific 
pollutants from a BART analysis was the addition of the de minimis 
exemption in 40 CFR 51.308(e)(ii)(C). EPA's decision to include this 
particular exemption, but no other, in the regulatory text makes it 
clear that individual pollutants may be exempted only where emissions 
of those pollutants are below the de minimis threshold. Under the 
commenters' theory that sources are subject-to-BART on a pollutant-by-
pollutant basis, a source with an impact at a Class I area was 0.4 dv 
for SO2 and 0.4 dv for NOX would not be subject 
to BART at all, even though it clearly contributes to visibility 
impairment. EPA recognized the absurdity of this situation, and 
therefore chose to use the de minimis exceptions as the only means by 
which a state can avoid conducting a BART analysis for a given 
pollutant after the source as a whole has been deemed subject to BART.
---------------------------------------------------------------------------

    \181\ 40 CFR 51.308(e)(ii) (emphasis added).
---------------------------------------------------------------------------

    Moreover, the de minimis threshold is not based on historical 
emissions, as suggested by FMMI, but on the source's PTE.\182\ PTE is 
defined as ``the maximum capacity of a stationary source to emit a 
pollutant under its physical and operational design.'' \183\ Physical 
or operational limitations on emissions capacity (e.g., restrictions on 
hours of operation) may be taken into account, but only if those 
limitations are federally enforceable.\184\ For the Miami Smelter, the 
WRAP estimated an annual NOX emission rate of 156 tpy for 
the units constituting the BART-eligible source.\185\ FMMI has not 
identified enforceable physical or operational limitations that would 
limit potential emissions from these units to less than 40 tpy. While 
FMMI cites to various documents that it asserts demonstrate that the 
Miami Smelter's NOX emissions are below the de minimis 
threshold, these documents consist of historical records of emissions, 
fuel usage, and material throughput.\186\ They do not establish the 
maximum capacity of the BART-eligible source to emit NOX and 
therefore do not demonstrate that potential NOX emissions 
are less than 40 tpy. Likewise, the fact that EPA has estimated that 
the historic baseline emissions from the BART-eligible units are 38 tpy 
does not establish that potential emissions are less than 38 tpy. 
Unlike subject-to-BART determinations, which are made based on a 
source's PTE, emission rates for cost calculations in BART analyses are 
generally ``based upon actual emissions from a baseline period.'' \187\ 
The PTE for the BART-eligible units at the Miami Smelters remains above 
40 tpy, and the source is therefore subject-to-BART for NOX.
---------------------------------------------------------------------------

    \182\ 40 CFR 51.308(e)(1)(ii)(C).
    \183\ 40 CFR 51.301.
    \184\ Id.
    \185\ Summary of WRAP RMC BART Modeling for Arizona, 
Draft5, May 25, 2007.
    \186\ FMMI Comment Letter at 13, n.1.
    \187\ BART Guidelines, 40 CFR part 51, appendix Y, section 
IV.D.4.d.1.
---------------------------------------------------------------------------

    Based on our five-factor BART analysis for NOX emissions 
from the Miami Smelter, we proposed to determine that no additional 
controls are needed for purposes of BART. FMMI supports this 
conclusion, but argues that there is no need for an emission limitation 
to implement this determination. We do not agree. Regional haze 
implementation plans must contain ``emission limitations representing 
BART'' for all subject-to-BART sources.\188\ In particular, either the 
State or EPA must establish an enforceable emission limit for each 
subject emission unit at the source and for each pollutant subject to 
review that is emitted from the source.\189\ This requirement applies 
even where BART is determined to be consistent with existing controls. 
Otherwise, emissions could increase to a level where additional 
controls would be warranted for BART, but no mechanism would exist to 
require such controls. Contrary to FMMI's suggestion, additional BART 
controls could not be required by EPA in the next regional haze plan 
for Arizona, as BART is only required in the first regional haze plan 
and cannot be deferred to future planning periods.\190\ Thus, an 
emission limit for NOX is needed to comply with 40 CFR 
51.308(e).
---------------------------------------------------------------------------

    \188\ 40 CFR 51.308(e).
    \189\ BART Guidelines, section V.
    \190\ See 40 CFR 51.308(f) (requiring subsequent regional haze 
plans to ``evaluate and reassess all of the elements required in 
paragraph (d)'', i.e., RP and LTS requirements, but not BART).
---------------------------------------------------------------------------

    Comment: Earthjustice stated that EPA's NOX emissions 
analyses and BART determinations are fatally deficient because the 
estimate of BART-eligible NOX emissions is based on the 
combustion of natural gas alone, with no consideration of the formation 
of thermal NOX in the converters and the electric furnace.
    Response: We do not agree with this comment for the reasons 
provided in response to similar comments regarding the Hayden Smelter.
4. Comments on Enforceable Emission Limits for PM10
    Comment: FMMI asserted that ``EPA's current reliance on the NESHAP 
standards to ensure enforceability demonstrates that the Agency's 
criticism of Arizona's SIP as lacking `emissions limits and compliance 
requirements' was misplaced.''
    Response: We do not agree that our proposal to rely on the NESHAP 
provisions to ensure the enforceability of BART for PM10 at 
the Miami Smelter is inconsistent with our finding that the Arizona RH 
SIP lacked enforceable emission limits to implement BART. As explained 
in our actions on the Arizona RH SIP, ADEQ sought to rely on the NSPS 
requirements to ensure the enforceability of its SO2 BART 
determinations for both the Hayden and Miami Smelters.\191\ However, 
under the

[[Page 52455]]

State's interpretation, as set out in the two smelters' Title V 
permits, the NSPS requirements do not apply to all of the BART sources' 
emissions.\192\ The permits also contain ``permit shields'' that limit 
the independent enforceability of the NSPS requirements, except to the 
extent that they are specifically listed in the facilities' Title V 
permits.\193\ Therefore, NSPS provisions in the copper smelters' 
permits do not apply to all subject-to-BART emissions at the smelters 
and do not satisfy the requirements of the Act or the RHR. By contrast, 
the Miami Smelter's Title V Permit does not restrict the applicability 
of the NESHAP requirements to the acid plant.\194\ Nonetheless, in 
order to ensure that the requisite emission limits and enforceability 
requirements are included in the applicable implementation plan, we are 
incorporating the applicable NESHAP requirements by reference as part 
of the final FIP for the Miami Smelter.
---------------------------------------------------------------------------

    \191\ See 70 FR 46159.
    \192\ In particular, the Title V permit for the Miami Smelter 
makes the 0.065 percent NSPS limit applicable to emissions from the 
acid plant, but not the remainder of the facility's emissions. ADEQ 
Title V Permit 53592 for Miami Smelter (2012), Attachment B section 
IV.C.1.a.
    \193\ Id. section IV.C.4.
    \194\ See, e.g., id; section I.C (40 CFR Part 63 Subpart QQQ 
General Requirements), VI.A (Smelter Fugitives, Particulate Matter 
and Opacity).
---------------------------------------------------------------------------

5. Other Comments
    Comment: FMMI requested that EPA extend its proposed compliance 
deadline for the Miami Smelter until at least 2018. FMMI noted that 
``entities in many regulated industries anticipate undertaking 
significant engineering and construction projects in the near term to 
comply with regulations promulgated to implement new 1-hour NAAQs'' and 
that ``the high volume of this work could lead to a shortage of skilled 
laborers to complete the necessary construction to install pollution 
control equipment.'' Accordingly, FMMI asked that EPA extend the 
proposed compliance deadline to 2018. AMA also asserted that EPA should 
extend the compliance deadline in the rule for the Miami Smelter.
    Response: We partially agree with this comment. Following the close 
of the public comment period, FMMI submitted the construction schedule 
for its planned SO2 control upgrades. The schedule indicates 
that FMMI will conclude construction of the roofline capture system and 
aisle scrubber by March 2017.\195\ FMMI also indicated that a shakedown 
period is necessary to ensure that the capture system and scrubber can 
meet the requirements of the FIP.\196\ Based on the additional 
information provided by FMMI, we agree that additional time beyond the 
proposed compliance deadline of three years from promulgation (i.e., 
roughly July 2017) is needed. However, because the averaging period for 
the BART limit for SO2 has been increased from 30 days to 
365 days, we do not agree that a full additional year is needed to 
comply with the requirements of the FIP. Therefore, we are extending 
the BART compliance deadline to January 1, 2018.
---------------------------------------------------------------------------

    \195\ Miami Project Execution, schedule provided to EPA by FMMI, 
at a May 13, 2014 teleconference.
    \196\ Phone call between FMMI and EPA (May 28, 2014).
---------------------------------------------------------------------------

VII. Responses to Comments on EPA's Proposed Reasonable Progress 
Determinations

A. Comments on Phoenix Cement Clarkdale Plant

    Comment: NPS expressed support for EPA's proposal to require 
emission limits for RP equivalent to SNCR to reduce NOX at 
the Clarkdale Plant.
    Response: We acknowledge NPS's support for the proposed RP 
determination. The final rule contains two compliance options: a 2.12 
lb/ton emission limit calculated on a rolling 30-kiln-operating-day 
basis, and an 810 tpy limit calculated on a rolling 12-month basis. 
Both emission limits reflect the degree of emission reduction 
achievable with the installation and use of SNCR.
    Comment: Earthjustice argued that SNCR can reach higher control 
efficiencies for NOX than the 50 percent control efficiency 
assumed by EPA in the proposal. Earthjustice requested that EPA look 
more closely at the capabilities of SNCR and the specific performance 
of the control technology on other kilns, specifically those referenced 
by Earthjustice. Earthjustice asserted that such an examination would 
ensure that the final control efficiency selected to represent SNCR 
would be consistent with the actual performance of this technology at 
Kiln 4.
    Response: We partially agree with this comment. Although the 
commenter notes that SNCR is capable of achieving 80 to 90 percent 
control in certain site-specific instances, these results typically 
represent the highest end of the range of SNCR performance. In 
addition, while such levels of control are attainable on a short-term 
basis, they are not necessarily consistently sustainable over longer 
periods, such as on a 30-day or annual basis. We note that the reports 
provided by Earthjustice assumed much lower control efficiencies (35 to 
50 percent) for purposes of calculating cost-effectiveness, which is 
calculated on an annual average basis. Our use of 50 percent for the 
SNCR control efficiency in the BART analysis is not intended to 
indicate the maximum effectiveness of SNCR. Information submitted by 
the commenter, as well as information that we included in our proposed 
rulemaking, does indicate that SNCR technology is capable of achieving 
greater than 50 percent control efficiency at preheater/precalciner 
kilns under certain conditions. It is possible that a site-specific 
optimization program at Kiln 4 could identify operating parameters and 
conditions that could result in an SNCR control efficiency greater than 
50 percent. As noted in our proposed rulemaking, the optimization 
report from the CalPortland Mohave plant indicates a range of SNCR 
efficiency between 30 and 60 percent for a preheater/precalciner kiln 
(the same type as Kiln 4 at the Clarkdale Plant). However, site-
specific information is not available for the Clarkdale Plant. In the 
absence of information indicating the extent to which the design and 
operating conditions at higher performing kilns are similar to, or 
replicable at, the Clarkdale Plant, we do not consider it appropriate 
to base our analysis on the higher control efficiency values. In 
developing the SNCR control efficiency used in our analysis, we 
examined the most stringent level of control attributed to SNCR at 
other similar facilities (as a retrofit on preheater/precalciner kilns) 
in other regulatory actions. These results are summarized in our 
proposed rule, and indicate that a 50 percent control efficiency is the 
most stringent SNCR control efficiency that has been applied to a 
preheater/precalciner kiln in other actions. Accordingly, we have used 
a 50 percent control efficiency as the basis for cost and emission 
calculations for the Clarkdale Plant.
    However, in response to concerns raised by Earthjustice and in 
order to ensure that performance of the SNCR system installed at the 
Clarkdale Plant is optimized, we are including in the final rule a 
series of control technology demonstration requirements.\197\ In 
particular, PCC is required to prepare and submit to EPA: (1) A design 
report describing the design of the ammonia injection system to be 
installed as part of the SNCR system; (2) data collected during a 
baseline period; (3) an optimization protocol; (4) data collected

[[Page 52456]]

during an optimization period; (5) an optimization report establishing 
optimized operating parameters; and (6) a demonstration report 
including data collected during a demonstration period. While this type 
of control technology demonstration is not typically required as part 
of a regional haze plan, we consider it to be appropriate here, given 
the significant variability in control efficiencies achievable with 
SNCR at cement kilns. Based upon the data collected, EPA may revise the 
lb/ton emission limit in a future notice and comment rulemaking action.
---------------------------------------------------------------------------

    \197\ These requirements apply only if PCC chooses to comply 
with 2.12 lb/ton rolling 30-kiln operating day limit for 
NOX, rather than the 810 tpy 12-month rolling limit.
---------------------------------------------------------------------------

    Comment: PCC said that it supports the alternative of a cap on 
NOX emissions for Kiln 4 of 810 tpy on a rolling 12-month 
basis, effective December 31, 2018. However, PCC conditioned its 
support on the final FIP expressly providing PCC with the option to 
select either the cap or the output-based emission limit by the 
deadline of December 31, 2018. Otherwise, PCC opposed a cap on 
NOX emissions for Kiln 4 on the grounds that EPA is not 
authorized by law to impose a mass cap in lieu of an emission limit. 
PCC also requested that the FIP provide PCC with the option to switch 
compliance scenarios after December 31, 2018, pursuant to either an 
alternative compliance scenario provision in the FIP or a similar 
provision in the facility's Title V permit. PCC stated that this 
approach would best address the continuing fiscal impacts on the SRPMIC 
that will result from the FIP.
    Response: As explained in an earlier response, we disagree that the 
RHR precludes EPA from establishing a source-specific annual emission 
cap for the purpose of achieving emission reductions to ensure 
reasonable progress. In the final rule, we are including provisions for 
both mass cap and an output-based emission limit, and are providing PCC 
with a deadline of June 30, 2018, to decide on the emission limit with 
which it will demonstrate compliance by December 31, 2018.
    Comment: PCC and ADEQ asserted that EPA's assessment of baseline 
visibility impacts attributable to PCC is based on inappropriate 
assumptions. In particular, PCC commented that EPA's CALPUFF modeling 
is based on a NOX emission rate calculated using the maximum 
rated capacity of PCC's Schenck feeder, a backup feeder that is never 
used unless the primary feeder is down for repair or maintenance. 
Therefore, the NOX emission rate used in the modeling is not 
representative of actual or reasonably foreseeable conditions. EPA 
should re-propose the FIP using a more realistic NOX 
emission rate in the modeling, or else revise the model outputs 
accordingly in the final FIP.
    PCC also stated that EPA's CALPUFF modeling is based on a 
NOX emissions factor that was different from that used in 
EPA's cost analysis. In the cost analysis, EPA used ``[a]nnual baseline 
emissions . . . calculated using the average of the lb/ton 
NOX emissions factors . . . observed over a 2005 to 2010 
timeframe.'' For the CALPUFF modeling, EPA used the highest 
NOX emissions factor (3.69 lbs/ton) that corresponds to the 
year 2008. PCC asserted that EPA should re-propose the FIP to harmonize 
the two approaches or revise the model outputs accordingly in the final 
FIP.
    Response: We disagree that the NOX emission rate used in 
the modeling is unrealistic and unrepresentative of actual or 
reasonably foreseeable conditions. With regard to the emissions factors 
used for calculating the costs of compliance, we have determined costs 
of compliance on an annual average basis, with costs and emissions 
calculated on an annualized basis (e.g., dollars/year, tons emitted/
year, tons removed/year), as recommended in the BART Guidelines.\198\ 
With regard to visibility modeling, while visibility improvement is not 
listed in the CAA or RHR as a required factor for evaluating individual 
RP sources, we consider it to be relevant and have therefore considered 
it as a supplemental factor in our RP analyses. In general, we have 
used the same modeling approach for RP sources as for BART sources, as 
we consider this to be a reasonable means of assessing visibility 
benefits from potential controls at specific sources. In particular, 
since the visibility modeling examines improvement on certain days, 
emission rates used in visibility modeling correspond to daily emission 
rates. As described in the BART Guidelines, pre-control (baseline) 
model emission rates for BART sources use the 24-hour average actual 
emission rate from the highest emitting day over a specified baseline 
period.\199\ For cement kilns, actual emission data are either not 
recorded on a daily basis, or are not publicly available. As noted in 
the TSD for the proposed rulemaking, baseline emissions for the 
Clarkdale Plant were developed primarily from information contained in 
annual emission inventories reported to ADEQ. Since these reports 
provide only total annual emissions and annual average emissions 
factors (lb/ton clinker), it is not possible to identify the highest 
emitting day based on this information. As a result, the single highest 
annual average emission factor (lb/ton clinker) was used in combination 
with short-term production capacity (ton clinker/day) in order to 
estimate a short-term emission rate (lb/day) that is representative of 
the highest emitting day. As noted in the model emission spreadsheet 
included in the docket for the proposed rule,\200\ the maximum 24-hour 
average NOX emission rate used for the baseline is 645 lb/
hour, or about 7.75 tons/day. A summary of calculated daily 
NOX emissions for the Clarkdale Plant is now included in the 
docket for this final rulemaking. As seen in these emission data, there 
were 12 days between 2005 and 2010 in which daily emissions were higher 
than the modeled baseline emission rate, ranging from 7.77 tons/day to 
11.91 tons/day. Since the Clarkdale Plant has emitted at rates greater 
than those modeled in the baseline scenario, we disagree that the 
baseline NOX emission rate we selected is unrepresentative 
of actual or reasonably foreseeable conditions.
---------------------------------------------------------------------------

    \198\ See Guidance for Setting Reasonable Progress Goals Under 
the Regional Haze Program (June 1, 2007) (``RP Guidance'') section 
5.1 (recommending use of BART Guidelines and CCM for calculating 
costs of compliance for stationary sources); BART Guidelines, 70 FR 
at 39166-68 (Impact analysis part 1: How do I estimate the costs of 
control?).
    \199\ 70 FR 39170.
    \200\ D-06c-AZRPsourcesall-
Task92012-09-30.xlsx.
---------------------------------------------------------------------------

    Regarding the use of the Schenk feeder's capacity in emission 
calculations rather than the primary feeder's capacity, we note that 
the primary feeder's capacity is specified as simply ``NA'' in the 
Clarkdale Plant's Title V permit. Furthermore, this information was not 
provided by ADEQ or PCC in their comments or any other communication 
with EPA over the last 18 months.\201\ In addition, while PCC has 
stated that use of the primary feeder's capacity, combined with other 
revisions to emission calculations, could result in 25 percent lower 
NOX emissions, it has not provided supporting data to 
justify this claim, such as the primary feeder's capacity. The modeled 
baseline emission rate is within the range of actual emissions reported 
for the Clarkdale Plant, as noted in the previous paragraph. Thus, we 
consider that 645 lb/hour is a

[[Page 52457]]

representative characterization of the facility's baseline emission 
rate.
---------------------------------------------------------------------------

    \201\ See, e.g. Summary of Communications and Consultation 
between EPA, Phoenix Cement Company (PCC), and Salt River Pima 
Maricopa Indian Community (SRPMIC) Regarding Potential Reasonable 
Progress (RP) Controls for Phoenix Cement Clarkdale Plant (January 
27, 2014); Revision to the Regional Haze SIP for the State of 
Arizona with Technical Support Document (May 3, 2013); Attachments 
to the 2013 Arizona Regional Haze SIP revision (May 3, 2013).
---------------------------------------------------------------------------

    Comment: According to PCC, EPA post-processed its CALPUFF 
dispersion modeling results using IMPROVE Method 8b to compute 
extinction and delta deciview impacts attributable to the Clarkdale 
Plant's NOX emissions. PCC said that EPA should re-propose 
the FIP to solicit comments on the applicability of Method 8b for the 
RHR, or propose its understanding of how best to assess source-specific 
visibility impacts in a separate notice and comment rulemaking, before 
it uses Method 8b in the regional haze context. In the alternative, EPA 
could issue a separate notice-and-comment rulemaking to explain the 
Agency's understanding of how best to assess source-specific visibility 
impacts using Method 8b before EPA uses Method 8b to impose legal 
obligations on the regulated community.
    Response: The details of our visibility analyses are in the TSD and 
the public has had ample opportunity to comment on these analyses 
through the notice and comment process on our proposal. With regard to 
use of Method 8b in particular, the ``8'' in ``8b'' refers to ``method 
8'' in CALPOST, a post-processor for the CALPUFF model, and indicates 
that CALPOST uses the revised IMPROVE equation for calculating 
visibility impact from pollutant concentrations (as opposed to ``method 
6'' which specifies the original IMPROVE equation). The ``b'' refers to 
natural conditions on the 20 percent best days (as opposed to ``a'' for 
annual average natural conditions). As explained in our TSD, ``Method 8 
is currently preferred by the [FLMs]'' and use of ``b'' (best 20 
percent) is ``consistent with initial EPA recommendations for BART 
[and] current [FLM] guidance for assessing visibility impacts at Class 
I areas.'' \202\ The commenter has not asserted or provided any 
evidence that EPA's reliance on method 8b is unreasonable or that use 
of another method is preferable in this instance. Therefore, we do not 
agree that any further notice and comment process is needed to evaluate 
our assessment of source-specific visibility impacts.
---------------------------------------------------------------------------

    \202\ TSD at 13-14.
---------------------------------------------------------------------------

    Comment: PCC noted that CALPUFF ``is nominally for great distances 
and, therefore, assumes the NO component of NOX emissions is 
fully converted to NO2 that is then `available to form 
visibility-degrading particulate nitrate.' '' However, PCC is ``only 
10.5 km'' from Sycamore Canyon Wilderness Area (SCWA), the nearest and 
most affected Class I area. PCC stated that EPA's sensitivity analysis 
is arbitrary and does not appear to support EPA's proposal to impose an 
SNCR-based standard on the Clarkdale Plant, given the significant 
reductions in SNCR-related visibility benefits in the SCWA that would 
result from lower NO-NO2 conversion rates. PCC stated that 
EPA should re-propose the FIP using photochemical modeling to determine 
appropriate estimates of NO-to-NO2 and NO2-to-
NO3 conversions, the nitrogen species' effects on visibility 
in the SCWA, and the improvement in visibility that would result from 
the use of SNCR at the Clarkdale Plant.
    Response: NO is converted to NO2 and 
NO3- by oxidants such as ozone. This conversion 
takes some time, since the plume from the facility does not instantly 
mix into the ambient air containing oxidants. We agree with the PCC 
that NO emitted by the Clarkdale Plant may not fully convert to 
NO2 by the time it reaches the nearby SCWA, and therefore 
may not fully form visibility-impairing nitrate 
(NO3-). However, we disagree CALPUFF can only be 
used to model great distances, that our sensitivity analysis is 
arbitrary, or photochemical modeling is necessary in this instance. PCC 
stated that CALPUFF ``is nominally for great distances.'' It is true 
that we promulgated CALPUFF with distances greater than 50 km in 
mind.\203\ However, we also approved it for situations with complex 
wind situations, and specifically recommended CALPUFF for regional haze 
analyses. EPA's Guideline on Air Quality Models states that CALPUFF 
(Section A.3) may be applied when assessment is needed of reasonably 
attributable haze impairment or atmospheric deposition due to one or a 
small group of sources.\204\ Further, the BART Guidelines provide that 
in situations where one is assessing visibility impacts for source-
receptor distances less than 50 km, one should use expert modeling 
judgment in determining visibility impacts, giving consideration to 
both CALPUFF and other EPA-approved methods.\205\ In this instance, we 
consider CALPUFF to be the most appropriate EPA-approved method, but 
have also conducted additional analyses to account for the limitations 
of CALPUFF at distances less than 50 km.
---------------------------------------------------------------------------

    \203\ ``Revision to the Guideline on Air Quality Models: 
Adoption of a Preferred Long Range Transport Model and Other 
Revisions'', 68 FR 18440, April 15, 2003.
    \204\ 40 CFR Appendix W, Guideline on Air Quality Models section 
7.2.1.e. at the time of promulgation, 68 FR 18440, April 15, 2003; 
later moved to section 6.2.1.e, 70 FR 68218, November 9, 2005.
    \205\ 40 CFR part 51, appendix Y, IV.D.5. or 70 FR 39170.
---------------------------------------------------------------------------

    In particular, we acknowledge that CALPUFF's assumption that NO is 
totally converted to NO2 and NO3\-\ might not be 
warranted for all circumstances. NO is converted to NO2 and 
NO3\-\ by oxidants such as ozone. This conversion takes some 
time, since the plume from the facility does not instantly mix into the 
ambient air containing oxidants. The Clarkdale Plant is only 6.5 miles 
from the SCWA. We explored this issue in our proposal in the form of a 
sensitivity analysis described in the TSD \206\ and an associated 
spreadsheet.\207\ We scaled the nitrate portion of the visibility 
impact of the Clarkdale Plant on SCWA to reflect NO-to-NO2 
conversion rates ranging from 10 percent to 100 percent. We used 10 
percent as an absolute lower bound because typically 10 percent of 
emitted NOX (the sum of NO and NO2) is already in 
the form of NO2, but we consider 25 percent a more 
reasonable assumption, since there is time for some conversion during 
the plume's travel to SCWA. We disagree that this analysis is 
``arbitrary'' as asserted by PCC, because it covers the full range of 
possible conversion rates, as shown in Table 7.
---------------------------------------------------------------------------

    \206\ TSD section IV.C.3, p.109.
    \207\ Docket spreadsheet 
PhoenixCementvisNO2conv.xlsx.

 Table 7--Sycamore Canyon Visibility Benefit From SNCR on Clarkdale Cement Plant as a Function of NO Conversion
                                                       208
----------------------------------------------------------------------------------------------------------------
                                                                       NO to NO2 Conversion
                                                ----------------------------------------------------------------
                                                     10%          25%          50%          75%          100%
----------------------------------------------------------------------------------------------------------------
Base Visibility Impact (dv)....................         1.17         1.94         3.13         4.19         5.14
Visibility Impact with SNCR (dv)...............         0.92         1.42         2.07         2.68         3.30

[[Page 52458]]

 
Improvement (dv)...............................         0.25         0.52         1.06         1.51         1.85
----------------------------------------------------------------------------------------------------------------

    We also disagree that we must use photochemical modeling for this 
visibility assessment. The range of NO conversion rates assumed in our 
sensitivity analysis already spans whatever rate would be derived using 
a photochemical model. As noted in our proposed rule, considering that 
SNCR is very cost-effective in this instance, we consider a benefit of 
0.25 dv at a single Class I area to be sufficient to warrant SNCR as a 
control for RP. Given that SNCR is warranted for any conversion rate, 
photochemical modeling would not alter our decision. Even if we were to 
perform such modeling, it would be strongly dependent on the background 
concentration of ozone and other oxidants in the local area for which 
no ozone measurements are available. The two ozone monitors nearest to 
the Clarkdale Plant are both about 28 miles away at Prescott to the 
southwest and in the opposite direction at Flagstaff.\209\ One might 
also use modeled ozone, derived from photochemical modeling of 
NOX and VOC sources over a large area, but such an estimate 
would have its own uncertainties. For example, the results may not be 
sufficiently precise at the 6.5-mile scale in question to provide an 
accurate ozone background. Therefore, we do not agree that 
photochemical modeling is preferable to CALPUFF or required in this 
instance.
---------------------------------------------------------------------------

    \208\ Id.
    \209\ See EPA's Air Quality System Database at http://www.epa.gov/ttn/airs/airsaqs/.
---------------------------------------------------------------------------

    Comment: PCC stated that EPA's conclusion that SNCR should be 
considered the basis of an RHR standard for the Clarkdale Plant is 
without reference to a decision-making threshold. EPA stated that ``the 
benefit of SNCR remained substantial even for the lowest (NO-
NO2) conversion assumption.'' However, PCC stated that EPA 
does not state or justify what visibility benefit is ``substantial'' 
enough to warrant imposition of RHR control technology-based standards 
on a BART-ineligible source. In PCC's case, PCC stated that EPA does 
not explain or justify how low the improvement in visibility would have 
had to go before EPA would have decided the visibility benefits are not 
``substantial'' enough to impose a standard based on SNCR. Absent this, 
PCC believes EPA's decision to impose on PCC a standard based on SNCR 
is arbitrary. PCC stated EPA should re-propose the FIP to provide such 
explanation and justification for public comment, or provide them in 
the final FIP.
    Response: We do not agree with this comment. The RHR does not 
require the development of specific thresholds for any of the RP 
factors. If 100 percent NO-NO2 conversion is assumed, SNCR 
is expected to reduce Kiln 4's visibility impact at SCWA from 5.14 dv 
to 3.30 dv, resulting in a benefit of 1.85 dv, which is quite 
large.\210\ Assuming only 10 percent conversion, SNCR is expected to 
reduce the Clarkdale Plant's visibility impact at SCWA from 1.17 dv to 
0.92 dv, a benefit of 0.25 dv, which would still contribute to improved 
visibility.\211\ Given that the four RP factors establish SNCR as a 
reasonable control for the Clarkdale Plant, we consider this visibility 
benefit sufficient to support installation of controls during this 
planning period. Indeed, because SNCR would reduce the facility's 
impact from more than 1 dv to less than 1 dv, the Clarkdale Plant would 
no longer cause visibility impairment at SCWA, but would instead only 
contribute to such impairment.\212\
---------------------------------------------------------------------------

    \210\ Id.
    \211\ Id.
    \212\ See 70 FR 39120 (``States should consider a 1.0 deciview 
change or more from an individual source to `cause' visibility 
impairment, and a change of 0.5 deciviews to `contribute' to 
impairment.'').
---------------------------------------------------------------------------

    Comment: PCC asserted that EPA used the wrong cost for ammonium 
hydroxide. PCC argued that the correct cost is $1,180/ton, not $1,000/
ton, based on information PCC provided to EPA on December 20, 2013. PCC 
stated that EPA also used a 15 percent contingency on costs without 
reference to a promulgated rule for that percentage and without 
offering a reasoned justification of the use of that percentage 
generally or in PCC's case. PCC concluded that EPA should re-propose 
the FIP to include legally applicable inputs, explain why its inputs 
are not arbitrary, or revise its cost analysis accordingly in the final 
FIP. PCC added that EPA's analysis relied on EPA's CCM, which has no 
legal force because it has never been subjected to a notice and comment 
rulemaking. Therefore, PCC concluded that EPA should re-propose the FIP 
to eliminate its reliance on the CCM in PCC's case, or else adjust its 
determination for PCC in the final FIP to exclude all assumptions based 
on the CCM or justify such assumptions on their merits so that they are 
not arbitrary.
    Response: We disagree with these comments. EPA's RP Guidance 
specifically recommends use of the CCM in evaluating the cost of 
controls for potentially affected RP sources.\213\ While the CCM itself 
has not been subject to notice and comment rulemaking, our use of the 
CCM in this rulemaking has been subject to public notice and comment, 
and PCC has had ample opportunity to dispute all assumptions in our 
analysis.\214\ In this instance, PCC provided its own SNCR cost 
estimate that also relied on information from the CCM for certain line 
items (such as direct and indirect installation costs), as well as 
internal cost estimates for other line items (SNCR purchased-equipment 
cost).\215\ In our proposed rule, we accepted the majority of PCC's 
cost analysis and included all of the line items provided by PCC. In 
specific instances, where we found a particular line item cost to be 
excessive or unjustified, we revised the value provided by PCC in order 
to ensure a fair and meaningful comparison of costs between the 
Clarkdale Plant and other facilities. In no case did we entirely 
eliminate or disregard the cost of a line item provided by PCC.
---------------------------------------------------------------------------

    \213\ RP Guidance section 5.1.
    \214\ In addition to the public comment period on our proposed 
FIP, EPA previously provided PCC with two opportunities to review 
and provide feedback on our analysis for the Clarkdale Plant. See 
email from Colleen McKaughan, EPA, to Verle Martz, PCC (November 6, 
2012); email from Charlotte Withey to George Tsiolis (December 11, 
2013).
    \215\ F-42--2013-03-06 Comments from Phoenix Cement Co.pdf.
---------------------------------------------------------------------------

    In the case of reagent cost, PCC used a reagent cost of $0.59/lb 
(i.e., $1,180/ton), citing the cost-effectiveness analysis performed 
for the BACT analysis of the Drake Cement Plant's PSD construction 
permit in 2005. Based

[[Page 52459]]

on the information provided by PCC, this estimate does not appear to 
have been updated or adjusted from its original 2005 estimate, nor has 
PCC explained why the estimate provided for a different plant is 
appropriate for the Clarkdale Plant. As noted in the proposed rule, we 
used a reagent cost of $1,000/ton, based on recent historical prices 
(about $500/ton) and increased it by a factor of two in order to 
account for potential fluctuations in ammonia prices over the 20-year 
useful life of the control equipment. Absent additional details from 
PCC indicating a more recent or site-specific justification for an 
ammonia cost of $1,180/ton, we consider our estimate of $1000/ton to be 
a reasonable and sufficiently conservative estimate for the price of 
ammonia.
    In the case of cost contingency, we consider the 40 percent 
contingency suggested by PCC, without additional site-specific 
information to support it, to be excessive. The CCM uses contingency 
values ranging from five to 15 percent, depending upon the control 
device in question and the precise nature of the factors requiring 
contingency. We have used the upper end of this estimate in our cost 
calculation. In no instance does the CCM provide for a generic 
contingency value as high as 40 percent. We recognize, however, that 
retrofit installations may pose additional cost estimate uncertainty 
(i.e., cost contingency). Consequently, we have incorporated estimates 
of such additional costs at other facilities affected by our regional 
haze FIP actions.\216\ In these instances, however, affected facilities 
provided greater detail regarding the additional costs, which we 
incorporated either as additional specific line items or as larger 
purchased equipment costs. We do not consider it appropriate to include 
these additional retrofit costs in a generic contingency value. 
Therefore, we are retaining the 15 percent contingency value.
---------------------------------------------------------------------------

    \216\ AEPCO Final Comments to AZ FIPSIPCBI 
included.pdf, C-37 Letter from Erik Bakken, TEP, to Greg Nudd, EPA, 
re TEP Sundt Modeling & Cost Information.
---------------------------------------------------------------------------

    Comment: PCC said that reliance on the EPA's CCM for the 20-year 
useful life presumption for amortization is inappropriate because the 
CCM was never subject to notice and comment rulemaking. PCC stated that 
the EPA should re-propose the FIP to eliminate its reliance on the CCM 
in PCC's case, or adjust its determination for PCC in the final FIP to 
exclude all presumptions based on the CCM, or justify such presumptions 
on their merits so that they are not arbitrary.
    Response: We do not agree with this comment. EPA's RP Guidance 
recommends use of the CCM in considering the remaining useful life of 
potentially affected RP sources, and explains that ``the methods for 
calculating annualized costs in EPA's [CCM] require the use of a 
specified time period for amortization that varies based upon the type 
of control.'' \217\ The CCM, in turn, provides that ``[a]n economic 
lifetime of 20 years is assumed for the SNCR system.'' \218\ As noted 
in the previous response, while the CCM itself has not been subject to 
notice-and-comment rulemaking, our use of the CCM in this particular 
rulemaking has been subject to public notice and comment. PCC has had 
ample opportunity to dispute all assumptions in our analysis, including 
the 20-year amortization period. However, PCC has provided no evidence 
that our use of an equipment lifetime of 20 years is inappropriate in 
this instance. On the contrary, PCC submitted a four-factor analysis 
dated March 28, 2013, which states that Kiln 4 has a remaining useful 
life of roughly 50 years. Thus, there is no evidence in the record to 
suggest that an amortization period of less than 20 years is 
appropriate for capital costs of SNCR at Kiln 4.
---------------------------------------------------------------------------

    \217\ RP Guidance section 5.4.
    \218\ CCM section 4.2, chapter 1, section 1.4.2, page 1-37.
---------------------------------------------------------------------------

    Comment: Earthjustice disagreed with EPA's calculation of baseline 
emissions for Kiln 4, noting that the baseline value of 1,620 tpy 
employed by EPA is higher than actual annual emissions from 2005 
through 2010. Earthjustice asserted that using baseline emissions that 
are higher than any of the baseline years is bad policy and bad 
precedent, and urged EPA to use the maximum of the actual observed 
emissions from the baseline period, which is 1,513 tpy in 2005.
    Response: We disagree that the baseline emission rate should be 
adjusted in the manner suggested by Earthjustice. The challenges 
associated with accurately characterizing the baseline emissions for a 
source that exhibited such significant variation in cement production, 
annual emissions, and emission factors over the baseline period are 
documented in our proposed rule. We acknowledged in our proposed rule 
that our method marginally overstates the annual baseline emission 
rate. However, we do not consider the method proposed by Earthjustice, 
which involves using the maximum actual baseline value observed, to be 
a more accurate characterization of baseline emissions. We acknowledge 
that Earthjustice's method would result in a marginally lower annual 
emission limit,\219\ but Earthjustice's method would also result in a 
higher lb/ton NOX emission limit.\220\ We do not consider 
the use of the maximum observed emission factor (lb/ton), which is the 
result of low levels of kiln production, as a realistic depiction of 
anticipated annual emissions from the source. Moreover, an adjustment 
of the baseline by this amount would not alter our determination that 
SNCR constitutes the appropriate RP control for Kiln 4.\221\
---------------------------------------------------------------------------

    \219\ As a result of using a 1,513 tpy NOX baseline 
emission rate instead of 1,620 tpy as described in the proposed 
rule.
    \220\ As a result of using a 3.69 lb/ton baseline emission 
factor instead of a 3.25 lb/ton emission factor as described in the 
proposed rule.
    \221\ Use of a 1,513 tpy baseline emission rate would result in 
an SNCR cost-effectiveness of $1,215/ton, rather than $1,162/ton in 
the proposed rule.
---------------------------------------------------------------------------

    Comment: PCC noted an inconsistency between the proposed compliance 
date in the preamble applicable to the Clarkdale Plant, ``by December 
31, 2018,'' and the compliance date in the proposed regulations, ``no 
later than (three years after date of publication of the final rule in 
the Federal Register).'' PCC stated that it needs the maximum 
flexibility that EPA can provide, and requested that the compliance 
date in the final rule be stated as ``no later than December 31, 
2018.'' Similarly, ADEQ asserted that, given the difficulty of 
retrofitting Kiln 4 with SNCR, more than three years is necessary to 
demonstrate compliance. By contrast, Earthjustice commented that the 
proposed compliance time frame of 4.5 years to install SNCR on the kiln 
is too long, asserting that the proposed compliance deadline has no 
basis, and should be shortened to one year.
    Response: EPA acknowledges that there is a discrepancy between the 
preamble and the regulatory language in the proposed FIP regarding the 
compliance date for the Clarkdale Plant. Unlike BART controls, which 
must be installed as expeditiously as practicable, RP controls are not 
subject to any particular compliance deadlines under the CAA and RHR, 
other than the overarching requirement to achieve reasonable progress 
during each planning period. PCC has indicated that it needs until 
December 31, 2018, to comply with any requirements of the FIP, which is 
also the end of the first planning period. While it may be technically 
feasible for the Plant to install SNCR before this date, we

[[Page 52460]]

consider it appropriate in this instance to provide the facility until 
December 31, 2018. We have amended the regulatory text to require 
compliance with the NOX emission limit and other 
NOX-related requirements no later than December 31, 2018.
    Comment: Earthjustice did not support revising the 30-day average 
emission limit in order to accommodate startup and shutdown events at 
the Clarkdale Plant. Earthjustice concluded that the proposed upward 
revision is not warranted. In contrast, PCC commented that the method 
EPA used to derive the 2.12 lb/ton emission limit is ``not unreasonable 
for being based on empirical data.''
    Response: Under the CAA and EPA's implementing regulations, 
``emission limitation'' is defined as a requirement which limits the 
quantity, rate, or concentration of emissions of air pollutants ``on a 
continuous basis.'' \222\ Thus, the emission limits established in the 
FIP apply at all times, including periods of startup, shutdown, and 
malfunction. Malfunctions are, by definition, unforeseeable, and cannot 
be accounted for in setting emission limits. By contrast, startup and 
shutdown are part of normal operations, and must be included when 
establishing emission limits. As discussed in our proposed rule, the 30 
percent upward revision from the annual emission rate to the 30-day lb/
ton limit was based on an examination of daily emissions (lbs) and 
production (tons clinker) data over a multi-year period for cement 
kilns (operating without SNCR) in which we identified the highest 
rolling 30-day emission rate and the highest annual average emission 
rate, and examined the difference between these values. A similar 
approach was used to develop the rolling 30-day emission limits for TEP 
Sundt Unit 4, and a copy of the emission data is included in the 
docket.\223\ Unlike the emission data for Sundt Unit 4, which are 
publicly available from EPA's CAMD, the data we examined for the cement 
kilns contain daily production information that is considered CBI and 
we are generally prohibited from making it available for public review. 
The method we applied in developing the 30-day emission limit for the 
cement plants, however, is the same as the method documented for Sundt 
Unit 4 that is available for public review. While alternative methods 
might exist to account for these emissions, we did not receive any 
comments describing any alternative or more refined approaches to 
address this issue. Accordingly, we are finalizing the emission limit 
of 2.12 lb/ton as proposed.
---------------------------------------------------------------------------

    \222\ 42 U.S.C. 7602(k), 40 CFR 51.100(z).
    \223\ See spreadsheet labeled ``E-45--TEP Sundt4 2001-12 
Emission Calcs 2014-01-24.''
---------------------------------------------------------------------------

    Comment: Earthjustice opposed setting an annual NOX 
emission cap for the Clarkdale Plant's Kiln 4. According to 
Earthjustice, the cap is inexplicable because there is just the single 
kiln at the facility, and a cap is not needed. Earthjustice pointed out 
that EPA acknowledges that the facility can meet the cap without 
further controls. Earthjustice would support a combination of a unit-
specific mass-based emission limit (e.g., ton/year or ton/day) and an 
output-based limit (e.g., lb/ton clinker) in some situations. 
Nevertheless, Earthjustice opposed the NOX cap for Kiln 4 
and urged EPA not to adopt the cap in the final rule.
    Response: We disagree with this comment. The RHR does not preclude 
the establishment of an annual emission limit \224\ for the purpose of 
achieving emissions reductions for reasonable progress. As proposed, an 
annual NOX emission limit of 810 tpy represents a 50 percent 
reduction, consistent with the use of SNCR, relative to baseline 
emissions. In addition, we note that while the RHR does require the 
consideration of specific control technologies and emission reduction 
systems in BART and RP analyses, the emission limits established 
pursuant to the RHR do not specifically require the application of a 
specific control method or technology.\225\ Although the emission limit 
itself is based on the reductions achievable from a considered control 
option, the source is not required to install a specific technology to 
demonstrate compliance with the limit, and may pursue other means of 
meeting the limit. In this instance, PCC may elect to comply with the 
810 tpy NOX limit by installing SNCR, or may elect to limit 
cement production to about half of pre-2008 production levels.
---------------------------------------------------------------------------

    \224\ Although the term ``cap'' was used to describe the limit 
on Kiln 4, the commenter is correct to note that only Kiln 4 is 
subject to the ``cap.'' The ``cap'', therefore, essentially 
functions as an emission limit for a single emission unit.
    \225\ We note, for example, that per 40 CFR 51.301 
(Definitions), BART represents an emission limit, not necessarily a 
requirement to install a specific control technology.
---------------------------------------------------------------------------

    Comment: Earthjustice noted that EPA considered two BART controls 
options, SCR and SNCR, but that EPA rejected SCR as technically 
infeasible. Earthjustice disagreed with this decision, and provided 
information asserting that while SCR systems have proven impractical 
due to operational reasons at several European kilns, that is not the 
same as technical infeasibility. Earthjustice asserted that SCRs can 
work in cement kilns, but require additional maintenance that may 
impact the cost of the controls. However, because EPA did not do any 
cost analysis, Earthjustice asserted that it is impossible to state 
with certainty that SCR is not cost-effective, which Earthjustice 
alleged is what is implied from EPA's discussion. Thus, Earthjustice 
stated that EPA should not have conflated technical infeasibility and 
economic infeasibility when it rejected SCR.
    Response: We agree that SCR is technically feasible. We clarify 
that although SCR was not further considered after Step 2 (Eliminate 
Technically Infeasible Options) of the RP analysis, we consider SCR a 
technically feasible control option. While we explicitly eliminated 
other control options (e.g., mixing air technologies) in Step 2 as 
technically infeasible, we elected not to consider further SCR due to a 
lack of information that would allow us to evaluate its effectiveness 
and cost of controls on cement kilns. In particular, we note that SCR 
has not been commercially applied to a cement plant of any type in the 
United States, and there is little information available about its use 
on cement kilns in other countries.\226\ Thus, we lack sufficient 
information to conduct a four-factor analysis for SCR on cement kilns.
---------------------------------------------------------------------------

    \226\ See TSD at 92-93.
---------------------------------------------------------------------------

B. Comments on CalPortland Cement Rillito Plant

    Comment: CPC asserted that the four-factor analysis for the Rillito 
Plant must be done within the context of the RPGs. In the current 
litigation over EPA's FIP governing three subject-to-BART power plants 
in Arizona, CPC noted that the petitioners argued that EPA erred by 
disapproving Arizona's BART determinations without considering whether 
the Arizona RH SIP demonstrated reasonable progress. According to CPC, 
EPA asserted in response:

    Given that there is no statute or regulation plainly requiring 
EPA to consider source-specific BART determinations in the context 
of a state's overall ``reasonable progress,'' the State must 
demonstrate that EPA's approach was an unreasonable interpretation 
of EPA's own regulations.

    Whether EPA is correct with respect to BART determinations, CPC 
asserted that 40 CFR 51.308(d)(l) and (d)(l)(A) plainly require EPA to 
consider source-specific reasonable progress factors in the context of 
establishing RPGs. CPC concluded that EPA should not, and cannot, take 
a position in this matter

[[Page 52461]]

that is patently inconsistent with its position currently pending 
before the Ninth Circuit Court of Appeals.
    Response: We do not agree that our action here is in any way 
inconsistent with our Phase 1 action or our brief defending that 
action. Furthermore, while we agree that the RHR requires consideration 
of the RP factors in the context of setting RPGs, we do not agree that 
our proposed FIP failed to comply with this requirement. The RPGs are 
analytical benchmarks that reflect the visibility improvement at each 
Class I area that is estimated to occur by the end of the planning 
period on the 20 percent best and worst days after all reasonable 
control measures, including both RP determinations and BART 
determinations, have been implemented. In our proposed FIP, we proposed 
RPGs for Arizona's Class I areas that reflect the combination of 
control measures included in the approved portions of the Arizona RH 
SIP (Phases 1 and 2), the partial Arizona RH FIP (Phase 1), and the 
proposed partial Arizona RH FIP (Phase 3) that we are finalizing today 
with some modifications.\227\ In addition, as explained elsewhere in 
this notice, we are now quantifying (in deciviews) the RPGs for each 
Class I area.
---------------------------------------------------------------------------

    \227\ 79 FR 9363.
---------------------------------------------------------------------------

    Comment: CPC stated that the estimated cost per dv improvement for 
Kilns 1-3 in Table 43 of the proposal notice does not reflect the cost 
for all three kilns. According to CPC, the Table 43 figures improperly 
compare the annual cost of SNCR at one kiln with the cumulative 
visibility improvement from requiring SNCR at all three kilns. CPC 
asserted that, based on EPA's estimates, the corrected values would be 
$4.5 million/dv (cumulative improvement) and $14.3 million/dv (maximum 
improvement). CPC also stated there are several errors in the proposed 
FIP's visibility modeling for Kilns 1-3.
    Response: We agree that Table 43 reflects the annual cost of SNCR 
for one kiln, compared to the cumulative visibility improvement from 
requiring SNCR at all three kilns. However, this error had no impact on 
our proposed determination that no controls should be required for 
Kilns 1-3 at this time. Making the change suggested by CPC would 
further support this determination by increasing the $/dv value for 
SNCR at Kilns 1-3. Likewise, making the alterations in the modeling as 
suggested by CPC would not alter our determination that no controls are 
reasonable for Kilns 1-3 in this planning period.
    Comment: CPC stated that the proposed FIP underestimates ammonia 
costs (citing Exhibit 1 submitted with the comments). CPC stated that 
its total annual cost estimate, which differs from the proposed FIP's 
only due to vendor quotes and site-specific information for ammonia 
costs, is $1,348,084.
    Response: As part of its comments, CPC provided an ammonia vendor 
quote of $1,336/ton (compared to our ammonia cost of $1000/ton in our 
proposed rule). We have revised the ammonia costs in our cost estimate 
based upon the vendor quote provided by CPC. This change, together with 
other revisions described below, results in a cost-effectiveness of 
$1,850/ton, which we consider to be very cost-effective.
    Comment: Earthjustice and NPS indicated that they do not agree with 
EPA's assessment of the control efficiency of SNCR for Kilns 1-3, which 
they believe is higher than 30 percent. In Earthjustice's opinion, EPA 
randomly chose a 25 percent control efficiency for SNCR without 
explanation, despite the Agency's acknowledgement that the technology 
is capable of reducing NOX by as much as 40 percent.
    With respect to two other control options, Mid Kiln Firing (MKF) 
and Mixing Air Technology (MAT), Earthjustice noted similar concerns in 
that EPA simply accepted the 20 percent reduction from CPC's observed 
range of 11 to 55 percent NOX reduction, again without 
support or justification. Better support must be provided, or EPA 
should select a higher control efficiency for these control strategies.
    NPS agreed with EPA that it is not reasonable to require controls 
at the kilns that will not operate again, but noted that it does not 
agree with how EPA conducted the analysis to arrive at the decision not 
to require controls, particularly with regard to control efficiency 
assumptions, and emphasized that before the kilns begin operating, they 
should be reevaluated.
    Response: As noted in the proposed rule, and as pointed out by the 
commenters, we relied upon information provided by CPC to estimate the 
control efficiencies of various control options being analyzed for 
Kilns 1-3, specifically LNB, SNCR, and MKF. The information provided by 
CPC indicated a range of performances for each option. However, the 
site-specific information available for Kilns 1-3 was insufficient to 
allow us to determine that the maximum control efficiency values within 
the performance ranges were achievable at the kilns. Consequently, we 
reasonably chose to use control efficiency values that fell within the 
middle of the respective performance ranges. While the commenters 
advocate for control efficiency values at the high end of the 
performance ranges, they have provided no new site-specific information 
to demonstrate that more stringent levels of control are achievable. 
Finally, we note that Kilns 1-3 are long-dry kilns, whereas Kiln 4 is a 
preheater/precalciner kiln. Given that more information is available 
regarding the control efficiency of SNCR on preheater/precalciner 
kilns, we were able to estimate a higher control efficiency for SNCR at 
Kiln 4 (50 percent) than we were able to at Kilns 1-3.
    Comment: Earthjustice disagreed with EPA's decision to require no 
further controls for Rillito Kilns 1-3. EPA justified its determination 
based on the fact that the kilns have not operated over the last five 
years, and the relatively high cost of controls. Earthjustice argued 
that EPA's justification is inadequate because the kilns are not 
required to be permanently removed and an enforceable commitment from 
the company should be put in place if these units are to be exempt from 
RP controls. By contrast, CPC agreed with EPA that controls are not 
appropriate on Kilns 1-3 at this time.
    Response: As noted in our proposed rule, we do not consider it 
reasonable to require RP controls on Kilns 1-3 given the relatively 
high cost of the control options and the fact that these kilns last 
operated in 2008, and have therefore not generated any emissions for 
the last five years. With regard to an enforceable shutdown date, we do 
not consider it appropriate to require the shutdown of these units. As 
noted in our proposed rule, if Kilns 1-3 resume production, they should 
be re-evaluated for RP controls by ADEQ during the next regional haze 
planning period.
    Comment: Earthjustice disagreed with EPA's rejection of SCR as a 
technically feasible control technology for Kiln 4. Earthjustice argued 
that the technology can be used on kilns, but it may require additional 
maintenance, which includes more frequent catalyst changes. 
Earthjustice stated that this can have an effect on the cost of 
controls, but because EPA did not conduct a cost analysis, the 
conclusion cannot be drawn that SCR is definitely not cost-effective. 
Infeasibility due to cost should not have been equated with technical 
infeasibility, if that is what EPA has done.
    Response: We agree that SCR is technically feasible. As noted in 
our responses regarding to comments concerning PCC's Clarkdale Plant, 
we

[[Page 52462]]

wish to clarify that although SCR was not considered after Step 2 of 
the RP analysis, we consider SCR to be a technically feasible control 
option. While we explicitly eliminated other control options (such as 
Mixing Air Technologies) in Step 2 as being technically infeasible, we 
elected to not further consider SCR further due to a lack of 
information that would allow us to evaluate its effectiveness and cost 
on cement plants. In particular, we note that SCR has not been 
commercially applied to a cement plant of any type in the United States 
and there is little information available about its use on cement kilns 
in other countries.\228\ Thus, we lack sufficient information to 
conduct a four-factor analysis for SCR on cement kilns.
---------------------------------------------------------------------------

    \228\ See TSD at 92-93.
---------------------------------------------------------------------------

    Comment: Earthjustice argued that EPA has not provided adequate 
support for the proposed 50 percent NOX reduction at Kiln 4 
using SNCR. Earthjustice acknowledged the existence of Table IV.B-7 in 
the TSD showing SNCR NOX control efficiencies from different 
sources, but indicated that it could not tell based on the cited 
sources in that table that the test results would limit the control 
efficiency to 50 percent for Kiln 4 as well. Earthjustice indicated 
that SNCR performance is site-specific and can be optimized. 
Earthjustice said that the injection of ammonia or urea into an exhaust 
gas stream under certain conditions can reduce NOX emissions 
significantly, but that the temperature range is important because at 
temperatures beyond a certain range, the reagent can oxidize to create 
NO, thereby increasing NOX emissions. On the other hand, if 
the temperature is below a certain temperature range, the reaction rate 
is too slow for completion and the source might emit unreacted agent.
    Reemphasizing the fact that the control efficiency of SNCR is 
variable and dependent on installation-specific variables, Earthjustice 
argued that it is possible to achieve NOX reductions of 90 
percent at cement kilns. Therefore, Earthjustice urged EPA to 
reconsider the 50 percent level of control and consider raising the 
control efficiency for Kiln 4 at Rillito. By contrast, NPS indicated 
that it agreed with EPA's estimate of 50 percent control efficiency for 
SNCR and believed this level of control is supported by estimates of 50 
percent at similar kilns.
    Response: We disagree that a 50 percent control efficiency estimate 
for SNCR is too low for the reasons provided in response to similar 
comments regarding PCC's Clarkdale Plant. In addition, in our proposed 
rule, we solicited comment regarding SNCR control efficiency on Kiln 4, 
and stated that if we receive additional information or data providing 
more site-specific information that justifies a different control 
efficiency at the Rillito Plant, we would revise our analysis 
accordingly. As noted later in our responses, CPC provided information 
regarding the design and operation of Kiln 4, and stated that only a 35 
percent control efficiency was achievable. As described in greater 
detail below, we agree that 35 percent reflects an appropriate estimate 
of the degree of control achievable with SNCR at Kiln 4, and have 
revised our cost analysis to reflect a 35 percent control efficiency at 
Kiln 4.
    However, in response to concerns raised by Earthjustice and in 
order to ensure that performance of the SNCR system installed at Kiln 4 
is optimized, we are including in the final rule a series of control 
technology demonstration requirements. In particular, CPC is required 
to prepare and submit to EPA: (1) A design report describing the design 
of the ammonia injection system to be installed as part of the SNCR 
system; (2) data collected during a baseline period; (3) an 
optimization protocol; (4) data collected during an optimization 
period; (5) an optimization report establishing optimized operating 
parameters; and (6) a demonstration report including data collected 
during a demonstration period. While this type of control technology 
demonstration is not typically required as part of a regional haze 
plan, we consider it to be appropriate here, given the significant 
variability in control efficiencies achievable with SNCR at cement 
kilns. Based upon the data collected, EPA may revise the lb/ton 
emission limit in a future notice and comment rulemaking action.
    Comment: CPC stated that the proposed FIP's estimate of 50 percent 
control of NOX emissions using SNCR on Kiln 4 is inaccurate 
because it is based on feasibility studies at four other cement plants 
and data collection from an optimization protocol at CPC's Mojave 
cement plant. CPC asserted that for each of the four plants, the TSD 
incorrectly characterized them in Table IV.B-9 as ``a preheater/
precalciner operating with existing combustion controls.'' According to 
the commenter, the Holcim Trident and Ash Grove Montana plants are 
long-wet kilns, which have fundamentally different combustion 
characteristics and emission profiles.
    CPC added that, while initially estimating 30 percent control 
effectiveness for SNCR at Kiln 4, it had refined its analysis and 
determined that 35 percent control efficiency may be achievable, based 
on the data observed at Mojave and CPC's engineering judgment that 
accounts for the site-specific differences between the two kilns.
    CPC stated that a critical difference between Kiln 4 and Mojave is 
that potential ammonia injection points at Kiln 4 are not within the 
optimum temperature range of 1,600[emsp14][deg]F to 
l,900[emsp14][deg]F. Moreover, CPC continued, because potential 
injection points at Kiln 4 are below the optimum temperature range, 
NOX reduction reactions will be much slower, leading to less 
reduction of NOX emissions. Another critical difference, 
according to CPC, is Kiln 4's unique modified loop calciner, which, due 
to its design, is less efficient at mixing exhaust gases and reagent 
than a cyclonic precalciner, such as the one at Mojave. CPC asserted 
that the inferior mixing in Kiln 4's modified loop calciner will impede 
the ability of the SNCR reactions to reduce NOX 
concentrations. In addition, CPC stated that fuel combustion is less 
efficient in a modified loop calciner, which leads to significantly 
higher carbon monoxide (CO) and lower oxygen concentrations in Kiln 4's 
exhaust when compared to Mojave. Kiln 4 CO emissions are approximately 
ten times higher than at Mojave. CPC concluded that, collectively, 
these factors will reduce the potential NOX control 
efficiency to no more than 35 percent for Kiln 4.
    Response: In its ``Reasonable Progress Analysis for CalPortland 
Company Rillito Cement Plant Kilns'' dated May 2013, CPC estimated a 30 
percent NOX control efficiency, based in part on an SNCR 
optimization report for CPC's Mojave Plant in California. Emission data 
from this report, which CPC submitted to EPA on August 30, 2013, 
indicated a range of SNCR control efficiency of 30 to 60 percent at the 
Mojave Plant, depending upon operating parameters. Based on this 
information, and given the range of SNCR performance indicated from the 
first six months of Mojave Plant optimization protocol collection, we 
stated that the use of a 50 percent control efficiency for SNCR was 
appropriate for Kiln 4. We also noted that, if we received additional 
information or data providing more site-specific information that 
justified a different control efficiency at the Rillito Plant, we would 
revise our analysis accordingly.
    As part of its comments on the proposed FIP, CPC submitted to EPA a

[[Page 52463]]

document entitled ``Evaluation of EPA's Reasonable Progress Analysis 
for Kiln 4 at CalPortland Company's Rillito Cement Plant dated March 
2014,'' which, among other things, provided further information on the 
NOX control efficiency that is assumed for applying SNCR to 
Kiln 4. This evaluation provided differences between Kiln 4 at the 
Rillito Plant and the cement kiln at the Mojave Plant that could lead 
to a lower NOX control efficiency when applying SNCR to Kiln 
4.
    CPC stated that because of these differences, the SNCR 
NOX control efficiencies obtained for the cement kiln at the 
Mojave Plant cannot be applied to Kiln 4 at Rillito. In addition to the 
differences cited above, CPC also stated in its March 2014 report that 
the emission data from the Mojave Plant are highly variable (due to the 
operational variability that is part of the optimization), and CPC has 
not determined what control efficiency or emission rate is appropriate 
to use as the basis for an emission limit for the Mojave Plant. Based 
on considered engineering judgment, CPC proposed that a 35 percent 
NOX control efficiency would be an appropriate estimate for 
Kiln 4. Because we agree with the analysis in CPC's report, we are 
revising our analysis based on a 35 percent NOX control 
efficiency for SNCR at Kiln 4. In addition, as explained above, we are 
including in the final rule a series of control technology 
demonstration requirements to ensure that performance of the SNCR 
system installed at Kiln 4 is optimized.
    In our proposed rule, we proposed a 50 percent NOX 
control efficiency using SNCR, with a corresponding emission limit of 
2.05 lb/ton of clinker produced and a cost-effectiveness of $1,047/ton. 
A 35 percent control efficiency would result in a NOX 
emission limit of 2.67 lb/ton of clinker produced and a cost-
effectiveness of $1,850/ton. We consider $1,850/ton to be very cost-
effective.
    Comment: CPC stated that EPA should revise the proposed rolling 30-
day emission limit for Kiln 4 to reflect more recent emissions data and 
35 percent control efficiency for SNCR. CPC stated that the TSD for the 
proposed rule references an annual design value of 2.05 lb 
NOX/ton clinker based on a pre-control emission rate 
estimate of 4.10 lb/ton, which omits data for 2011 and 2012. According 
to CPC, a six-year average based on the 2007 to 2012 time period yields 
a pre-control emission rate of 4.62 lb/ton. Over the 2009 to 2012 time 
period, the annual average emission rate has been 5.15 lb/ton.
    CPC also stated that emission limits must account for changes in 
production rates that are a function of market forces beyond the 
company's control. CPC said that, to be achievable, any emission limit 
imposed must account for the inherently higher emission rates that 
occur during periods of reduced production. CPC stated that if an 
emission limit is based on 50 percent control efficiency and that level 
of control is not achievable, then the company will be at risk of an 
enforcement action, third party claim, and/or plant shutdown for 
failing to meet an unachievable standard.
    Response: As noted above, we agree that 35 percent reflects an 
appropriate estimate of the degree of control achievable with SNCR at 
Kiln 4. Accordingly we are revising the 30-day rolling average for the 
NOX emission limit at Kiln 4 from 2.05 lb/ton of clinker to 
2.67 lb/ton of clinker. In addition, as explained above, we are 
including in the final rule a series of control technology 
demonstration requirements to ensure that performance of the SNCR 
system installed at Kiln 4 is optimized. If the data collected pursuant 
to these control demonstration requirements indicate that a different 
control efficiency is appropriate for this kiln, EPA may revise the lb/
ton limit in a future notice-and-comment rulemaking action.
    We do not agree that the lb/ton emission limit should be based 
solely on periods of reduced production. Such an approach does not 
ensure that the facility would achieve fully effective emission control 
during periods of full production, which exhibit lower lb/ton values. 
Conversely, a lb/ton limit based solely upon periods of full production 
would result in a low lb/ton value that may not be achievable during 
periods of reduced production. Although our baseline period did not 
include the most recent two years of data, it did incorporate emission 
data from periods of both full operation and reduced operation. As a 
result, we consider it to be a reasonable representation of baseline 
emissions. Therefore, we are not revising this value.
    Comment: CPC stated that because Kiln 4 does not cause or 
contribute to visibility impairment, a source specific four-factor 
reasonable progress analysis was not necessary or appropriate. The 
commenter asserted that EPA, in its final partial approval/disapproval 
of the Arizona RH SIP, stated ``We are approving Arizona's BART 
threshold of 0.5 dv and its determination that West Phoenix Power Plant 
and the Rillito Cement Plant are not subject to BART.'' Thus, the 
commenter argued that if a facility was not required to undergo a five-
factor BART analysis, it follows that the facility should not be 
required to undergo a similarly burdensome reasonable progress analysis 
either.
    Response: We disagree that exemption from BART automatically 
exempts a facility from control for purposes of reasonable progress 
under the RHR. In this instance, EPA approved Arizona's determination 
to exempt Kiln 4 at the Rillito Plant from BART, but disapproved the 
State's reasonable progress analysis for point sources of 
NOX. As part of our own analysis of point sources of 
NOX, we identified the Rillito Plant as a potentially 
affected source because it had a Q/D value of 726, more than 70 times 
the threshold value of 10.\229\ Furthermore, our modeling indicates 
that the plant causes visibility impairment at Saguaro National Park, 
where it has a baseline impact of 1.26 dv from all four kilns.\230\ 
Therefore, we determined that a source-specific four-factor analysis 
was appropriate.
---------------------------------------------------------------------------

    \229\ See 79 FR 9352.
    \230\ TSD page 98, table IV.B-12
---------------------------------------------------------------------------

    Comment: Earthjustice was not supportive of revising the 30-day 
average emission limit in order to accommodate startup and shutdown 
events. Earthjustice indicated that there is insufficient evidence in 
the record documenting the analysis referenced in the TSD \231\ where 
EPA indicates it looked at emission factors over 2008 to 2011 for other 
preheater/precalciner kilns. Further, Earthjustice also questioned 
whether the data that EPA examined was with or without SNCR. In 
Earthjustice's opinion, if the data represented uncontrolled emissions, 
the variability would not remain the same after the installation of 
SNCR. According to Earthjustice, proper controls have the effect of 
reducing variability. Therefore, Earthjustice did not believe that the 
proposed 30 percent upward revision to the 30-day average was warranted 
or sufficiently documented in the record.
---------------------------------------------------------------------------

    \231\ The commenter cited the last paragraph on page 99 of EPA's 
TSD (EPA-R09-OR-2013-0588-0009).
---------------------------------------------------------------------------

    Response: As noted in our response to a similar comment for PCC's 
Clarkdale Plant, under the CAA and EPA's implementing regulations, an 
``emission limitation'' is defined as a requirement which limits the 
quantity, rate, or concentration of emissions of air pollutants on a 
continuous basis.\232\ Thus, the emission limits established in the FIP 
apply at all times, including periods of startup, shutdown, and

[[Page 52464]]

malfunction. Malfunctions are, by definition, unforeseeable, and cannot 
be accounted for in setting emission limitations. By contrast, startup 
and shutdown are part of normal operations and emissions occurring 
during startup and shutdown must be accounted for when establishing 
emission limits.
---------------------------------------------------------------------------

    \232\ 42 U.S.C. 7602(k), 40 CFR 51.100(z).
---------------------------------------------------------------------------

    As discussed in our proposed rule, the 30 percent upward revision 
was based upon an examination of daily emissions (lbs) and production 
(tons clinker) data over a multi-year period for cement kilns 
(operating without SNCR) in which we identified the highest rolling 30-
day emission rate and the highest annual average emission rate, and 
examined the difference between these values. A similar approach was 
used to develop the rolling 30-day emission limits for TEP Sundt Unit 
4, and a copy of the emission data was included in the docket.\233\ 
Unlike the emission data for Sundt Unit 4, which is publicly available 
from EPA's CAMD Acid Rain database, the data set we examined for the 
cement kilns contains daily production data that is considered CBI, 
which we are prohibited from making available for public review. The 
methodology we applied in developing the 30-day emission rate for the 
cement plants, however, is the same as the methodology documented for 
Sundt Unit 4, which is available for public review. While there might 
be alternative methods to account for these emissions than the approach 
we adopted, we did not receive any comments describing any alternative 
or more refined approaches for addressing this issue. Accordingly, we 
have retained this methodology in establishing the emission limit in 
the final rule.
---------------------------------------------------------------------------

    \233\ See spreadsheet labeled ``E-45--TEP Sundt4 2001-12 
Emission Calcs 2014-01-24''.xlsx''.
---------------------------------------------------------------------------

    Comment: ADEQ said that, given the difficulty of retrofitting Kiln 
4 with SNCR, more time is necessary to demonstrate compliance. ADEQ 
said that the three-year compliance time frame is not sufficient. By 
contrast, Earthjustice asserted that the compliance deadline should be 
shortened to one year.
    Response: As noted in a response to a similar comment on PCC's 
Clarkdale Plant, unlike BART controls, which must be installed as 
expeditiously as practicable, RP controls are not subject to any 
particular compliance deadlines under the CAA and RHR, other than the 
overarching requirement to achieve reasonable progress during each 
planning period. CPC has indicated that it needs until the end of the 
first planning period that ends on December 31, 2018, to comply with 
any requirements of the FIP. While it may be technically feasible for 
the plant to install SNCR before that date, we consider it within our 
discretion and reasonable in this instance to provide the facility 
until December 31, 2018.
    Comment: Earthjustice responded to EPA's request for comments on 
whether a NOX emission cap should be set for the Rillito 
Plant. Earthjustice did not understand how EPA arrived at the proposed 
cap level and argued that the level is not commensurate with actual 
emissions data. The proposed level of 2,082 tpy would allow minimal to 
no control of NOX at the plant, assuming that Kilns 1-3 do 
not operate. Therefore, Earthjustice asserted that it is unreasonable 
to propose a cap without a guarantee that the older kilns will 
permanently cease operation because this could mean no control at all 
for Kiln 4. Earthjustice suggested that the combination of a unit-
specific mass-based emission limit (e.g., ton/year or ton/day) and 
process-based limits (e.g., lb/ton clinker) might be reasonable in some 
situations, but Earthjustice indicated that it is does not support the 
proposed cap.
    CPC also expressed opposition to the annual emission cap. CPC 
stated that the proposed alternative NOX emissions cap would 
require the permanent shutdown of Kilns 1-3, as installing SNCR on Kiln 
4 would not be sufficient to meet the cap if the other kilns were 
operating. CPC noted that when Kilns 1-3 operate at full capacity, 
NOX emissions from them exceed 1,900 tpy, so an annual cap 
of 2,082 tpy would require Kiln 4 to reduce emissions to around 150 
tpy, which is more than a 90 percent reduction from current emission 
levels. CPC asserted that, because 90 percent control efficiency is not 
possible with SNCR, the only way it could meet this annual limit would 
be to permanently shut down at least two, and perhaps all three, of its 
smaller kilns.
    Response: As noted in a response to a similar comment regarding 
PCC's Clarkdale Plant, the RHR does not preclude the establishment of 
an annual emission cap for the purposes of achieving emission 
reductions for reasonable progress. However, considering the issues 
raised by commenters, and the multi-unit nature of the proposed annual 
emission cap, we are not including the option of an annual emission cap 
for the Rillito Plant in the final rule.
    Comment: CPC stated that the visibility modeling for Kiln 4 
contains some errors and unsupported assumptions, leading to an 
overestimate of the visibility benefit due to SNCR, including assuming 
50 percent control and inaccurately assuming constant background 
ammonia levels. CPC asserted that because modeling results are highly 
sensitive to the estimated ammonia value, the assumption of 1 ppb for 
winter greatly overestimates NOX effects on regional haze. 
CPC stated that EPA used monthly background ammonia concentrations in 
the visibility modeling for the recently adopted Wyoming RH FIP and 
should do the same here given the available and representative 
monitoring data from the Chiricahua monitoring station, located less 
than 200 km from the Rillito Plant.
    CPC also asserted that EPA's visibility modeling for Kiln 4 
contains the following errors:
    (1) The stack parameters in the worksheet labeled ``Stack 
Parameters'' are the parameters for Kiln 6 that was proposed for 
construction at the Rillito Cement Plant to replace Kilns I-4, but has 
not been constructed.
    (2) EPA's contractor assumed a geometric mean diameter for coarse 
particulate matter of 0.48 microns in its CALPUFF modeling. Because 
coarse particles are larger than 2.5 microns in diameter, CPC's 
technical consultant, AECOM, assumed a geometric mean diameter of 6 
microns.
    (3) EPA's subcontractor used non-default minimum turbulence 
velocities sigma-v (SVMIN) and sigma-w (SWMIN) for each stability class 
over land and over water of 0.5 meter/second (m/s). According to 
comments in the subcontractor's CALPUFF modeling files, using the 
default values produced an error message. The only way to bypass the 
error and run the model to completion was to set SVMIN and SWMIN to 0.5 
m/s. AECOM used the default values without encountering errors from 
CALPUFF.
    Finally, CPC stated that AECOM reran the visibility modeling 
analysis using corrected and supportable inputs, demonstrating that the 
maximum visibility benefit from installing SNCR on Kiln 4 would be 0.15 
dv, approximately seven times less than the human eye can detect. 
Citing the DC Circuit's decision in American Corn Growers, CPC stated 
that a source should not be required to spend millions of dollars for 
imperceptible visibility improvements.
    Response: We partially agree with this comment. As explained above, 
we agree with CPC's assertion that a control efficiency of 35 percent 
is more appropriate for SNCR at Kiln 4 than our proposed efficiency of 
50 percent. However, we do not agree that our use of the IQAQM default 
for background

[[Page 52465]]

ammonia of 1.0 ppb was improper. As explained in our response to 
comments from TEP on the BART determination for Sundt Unit 4, given the 
uncertainty and variability in ammonia values measured in Arizona, we 
consider the 1.0 ppb IWAQM default to be the most appropriate value to 
use here.\234\
---------------------------------------------------------------------------

    \234\ Memorandum in docket, ``Full Technical Response to 
Modeling Comments for June 2014 Final Arizona Regional Haze FIP 
(Phase III),'' Colleen McKaughan and Scott Bohning, EPA, June 16, 
2014.
---------------------------------------------------------------------------

    We agree that we used the incorrect stack parameters. However, 
because these parameters have varying impacts on visibility benefits, 
this error had little effect overall. In particular, the lower stack 
height and smaller stack diameter tend to increase baseline visibility 
impacts and the visibility improvements due to controls, whereas the 
higher stack exit velocity and higher exit temperature tend to decrease 
visibility impacts and control benefits.
    Similarly, the changes related to particle diameters have little 
effect on the modeling results because PM contributes only a few 
percent to the modeled visibility impacts. The changes related to 
default minimum turbulence velocities would tend to increase slightly 
atmospheric mixing and thus to reduce slightly pollution impacts and 
the benefit of controls. Overall, the effect of the changes to the 
modeling input parameter is much smaller than the change in SNCR 
control efficiency, and does not affect our control determination.
    While CPC's comment cites the results of AECOM's modeling using 
variable ammonia background, AECOM also conducted modeling using 
constant 1.0 ppb ammonia background. As explained above, we consider 
use of constant 1.0 ppb ammonia background to be the most appropriate 
approach and we agree with CPC's other corrections to our contractor's 
modeling. Therefore, we accept the results of CPC's modeling using 1.0 
ppb ammonia background as a generally reasonable estimate of visibility 
benefits expected from SNCR on Kiln 4. These results indicate that the 
benefit of SNCR at Kiln 4 would be somewhat less than EPA's modeling 
showed. In particular, EPA's modeling showed a benefit of 0.24 dv at 
Saguaro National Park, the area with the highest impact from Kiln 4, 
and a cumulative benefit over the 12 nearby Class I areas of 0.78 dv. 
By contrast, CPC's modeling showed a benefit of 0.18 dv at Saguaro 
National Park and a cumulative improvement of 0.59 dv.
    Despite these decreased visibility benefits, EPA still considers 
SNCR to be reasonable for Kiln 4 for several reasons. First, as 
explained above, even with the revisions suggested by CPC in its 
comments, SNCR remains highly cost-effective at $1,850/ton. Second, 
even though the visibility benefits from SNCR at Kiln 4 at the Rillito 
Plant are lower than those expected to result from controls on other 
sources addressed in this FIP, they are not negligible, and together 
with controls on other sources now and in the future will achieve 
progress in improving visibility at multiple Class I areas. In 
particular, we note that, according to CPC's modeling, 12 different 
Class I areas will be improved, including Galiuro WA, for which the 
expected improvement is 0.16 dv, only slightly less than expected 
improvement of 0.18 dv at Saguaro National Park. Third, due to the 
close proximity of the Rillito Plant to the western unit of Saguaro 
National Park, there is significant uncertainty regarding the benefits 
of controls. In particular, EPA's modeling indicated that the benefit 
of SNCR at the western unit of Saguaro National Park (0.30 dv) is 
greater than the benefit at the eastern unit (0.24 dv), if 100 percent 
conversion of NO to NO2 is assumed. EPA also conducted a 
sensitivity analysis to address the possibility that NOX 
emitted from the Rillito Plant is not 100 percent in the form of 
NO2. The results of this analysis are shown in Table 8.

     Table 8--Visibility Benefit at Western Saguaro NP From SNCR on Rillito Cement Plant as a Function of NO
                                                   Conversion
----------------------------------------------------------------------------------------------------------------
                                                                       Conversion Rate
            NO to NO2 Conversion            --------------------------------------------------------------------
                                                  10%           25%           50%           75%          100%
----------------------------------------------------------------------------------------------------------------
Improvement (deciviews)....................         0.03          0.05          0.15          0.22          0.30
----------------------------------------------------------------------------------------------------------------

While we do not know for certain which of these scenarios is most 
realistic, it is worth noting that there also will be some benefit to 
the western unit of Saguaro, which is not directly reflected in the 
modeling provided by CPC.
    Finally, we disagree with CPC's suggestion that human 
perceptibility of visibility improvement is a criterion for imposing 
controls for purposes of selecting source-specific controls for 
reasonable progress under the CAA and the RHR. No one control will be 
sufficient to achieve the visibility goals of the RHR. The effect of 
reasonable controls on the many contributing sources will cumulatively 
enable progress toward those goals.
    Comment: CPC asserted that the reasonable progress analysis for 
Kiln 4 is inconsistent with EPA's analyses of other sources. CPC 
included a table comparing the proposed FIP's cost and visibility 
results for TEP Sundt Units 1-3 and CPC Rillito's Kiln 4, and concluded 
that for about the same annual cost, emission controls at Sundt would 
have a much greater beneficial impact on visibility at Saguaro National 
Park. CPC stated that the only factor that could explain this 
differential treatment is the ``cost/ton reduced'' metric, which the 
FIP estimates is higher for TEP Sundt than Rillito, thus demonstrating 
the limitations of the cost/ton reduced metric. CPC further stated that 
the FIP should not rely on this metric, which provides no insight on 
whether controls are cost-effective for achieving RPGs by improving 
visibility, the sole potential justification for establishing controls. 
With respect to TEP Sundt Units 1-3, CPC stated that EPA concluded 
``the cost-effectiveness of ULNB is relatively high in light of the 
anticipated visibility benefit'' and argued that because the costs are 
similar and the visibility benefits are even smaller, the same 
conclusion must be reached for Kiln 4.
    Concerning the reasonable progress analysis for El Paso's 
facilities and Pima County's Ina Road sewage plant, CPC included a 
table comparing the four-factor analyses for those facilities and Kiln 
4. CPC asserted that there is no explanation or justification to 
support the proposed decision to require controls on Kiln 4, but not on 
these other sources. CPC noted that the cost of compliance is higher 
for Kiln 4 than the other sources, the time needed to comply is longer, 
energy and non-air quality impacts are equivalent, and the remaining 
useful life is assumed to be identical. CPC asserted that because the 
four factors set forth in 40 CFR

[[Page 52466]]

51.308(d)(l) cannot justify this differential treatment, the proposed 
FIP justifies the decision to not require controls on these other 
sources based on a factor that is not listed in 40 CFR 51.308(d)(l), 
and stated that CPC should, and must, be treated equally, and no 
controls should be imposed during this first planning period.
    Response: We do not agree with this comment. The CAA and RHR 
provide considerable discretion in how the four RP factors are weighed. 
Moreover, while the CAA and RHR explicitly require consideration of 
visibility improvement in BART analyses, they do not require 
consideration of such benefits for individual RP sources. Therefore, 
while we have taken visibility benefits into account as a supplementary 
factor, we have not weighed them as heavily for RP as we have for BART. 
Rather, we have placed more emphasis on cost, which is one of the 
enumerated statutory factors for RP analyses.\235\ Accordingly, we do 
not agree with CPC's suggestion that we should consider $/dv as more 
important than $/ton in evaluating potential RP controls. Even with 
CPC's suggested modifications, the cost-effectiveness of SNCR at Kiln 4 
($1,850/ton) is two to four times less than the cost-effectiveness of 
controls at Sundt Units 1-3 ($4,400-$8,300/ton).\236\ Accordingly, we 
do not agree that we are treating these units inconsistently.
---------------------------------------------------------------------------

    \235\ Our cost analyses also incorporate consideration of two 
other statutory factors: Remaining useful life and energy and non-
air environmental impacts.
    \236\ See 79 FR 9358.
---------------------------------------------------------------------------

    With regard to El Paso's Compressor Station and Pima County's Ina 
Road sewage plant, we agree with the commenter that controls on these 
units would be more cost-effective than SNCR at Kiln 4, and that the 
results for the other three statutory factors are similar. However, we 
note that El Paso Natural Gas Company (EPNG) has asserted that EPA has 
underestimated the costs of compliance and time necessary for 
compliance.\237\ Furthermore, as explained in our proposal, natural-gas 
engines similar to those at these facilities are dispersed throughout 
the State and it is not practical for EPA to control these sources. By 
contrast, the Rillito Plant is a single discrete facility for which 
SNCR is a cost-effective and otherwise reasonable control option. We 
also note that, while we do not have visibility modeling to gauge the 
impacts of the other facilities cited by CPC, the Q/D value for the 
Rillito Plant (a rough gauge of potential for visibility impairment) is 
more than ten times the Q/D value for any of the other sources. Under 
these circumstances, we consider it reasonable to require SNCR at the 
Rillito Plant and not to require additional controls at the compressor 
stations or the sewage treatment plant. We strongly encourage the State 
to consider development of a statewide rule to regulate natural-gas 
engines in the next planning period.
---------------------------------------------------------------------------

    \237\ EPNG Comment Letter at 1-2.
---------------------------------------------------------------------------

    Comment: Arizona Rock Products Association expressed support for 
and incorporated by reference the comments of CPC and PCC.
    Response: We have responded to CPC's and PCC's comments above.

C. Comments on Other Reasonable Progress NOX Point Sources

    Comment: NPS argued that SCR should be BART for APS Cholla Unit 1. 
NPS provided more details on the cost analysis for Cholla Unit 1, 
indicating that the calculated average and incremental cost-
effectiveness values for SCR of $5,313/ton and $6,307/ton, 
respectively, are erroneously high. NPS noted that EPA's calculation 
methodology relied heavily upon IPM, and suggested several revisions 
and corrections to EPA's calculation that would have the effect of 
reducing the control costs. After applying the corrections, NPS 
concluded that an average cost-effectiveness of $5,263/ton is obtained 
which NPS considers to be reasonable. In addition, NPS provided its own 
set of cost calculations, relying primarily upon the cost equations 
contained in EPA's CCM. NPS estimated that the average cost-
effectiveness of SCR is $4,353/ton, which is less than the values 
established by several states and EPA.
    NPS also made similar comments about TEP Springerville Units 1 and 
2. NPS asserted that EPA's estimates of SCR cost-effectiveness of 
$6,829/ton for Unit 1 and $6,085/ton for Unit 2 are erroneously high, 
and therefore the incremental cost-effectiveness of SCR over SNCR of 
$8,606/ton and $7,416/ton, respectively, are also too high. After 
applying the corrections discussed by NPS, average cost-effectiveness 
of $5,700 to $6,400/ton is obtained, which NPS considers to be 
reasonable. In addition, NPS provided its own cost calculations for 
Springerville Units 1 and 2, relying primarily upon the cost equations 
contained in EPA's CCM. NPS estimated that the average cost-
effectiveness of SCR is $5,688 to $6,377/ton, which is less than the 
values established by several states and EPA for EGUs. Detailed 
calculations and analysis for Cholla Unit 1 and Springerville Units 1 
and 2 are documented in Appendix C and E of NPS's submittal.
    Response: We disagree with NPS's assertion that our calculations, 
based on IPM methodology, are overestimates. The revisions indicated by 
NPS consist primarily of lower urea/ammonia and catalyst costs. NPS 
made similar assertions regarding ammonia and catalyst costs in our 
analysis for TEP Sundt Unit 4. As described in our responses to those 
comments, we consider the values we used for ammonia and catalyst costs 
appropriate.
    Regarding NPS's cost calculations that use the cost equations from 
the CCM (as opposed to using the information contained in IPM), we note 
that nothing in the RHR requires use of the CCM for calculating the 
cost of compliance for RP sources. Moreover, while EPA's RP Guidance 
recommends use of the CCM, it also allows for divergence from the CCM, 
provided that any difference from the CCM is documented.\238\ In this 
and other RH rulemakings, we have not required strict adherence to the 
study level cost equations contained in the CCM, and have developed 
cost calculations based on a number of supplemental sources including 
certain site-specific data provided by the facility, vendor quotes, and 
information from other EPA rulemakings. As noted in our proposed rule 
and TSD,\239\ IPM has been used by EPA in multiple regulatory actions, 
and we consider it an appropriate source of supplemental information.
---------------------------------------------------------------------------

    \238\ See RP Guidance, section 5.1, note 23.
    \239\ TSD for the Proposed Phase 3 FIP, January 27, 2013, Page 
19 of 233.
---------------------------------------------------------------------------

    Regarding the use of cost-effectiveness thresholds, we note that 
the examples cited by NPS consist of BART determinations and not RP 
determinations.\240\ Given the differences between the BART factors and 
RP factors and the nature of the applicability criteria that would 
trigger BART and RP analyses,\241\ we do not necessarily consider the 
cost-effectiveness and visibility benefit values from BART 
determinations to be directly comparable to RP analyses. Furthermore, 
the cost-effectiveness values that NPS finds reasonable are, in fact, 
higher than EPA has required for

[[Page 52467]]

any BART source during this planning period.\242\ While it may be 
necessary to require controls at this cost level for RP sources in 
future planning periods, we do not agree that this level of cost-
effectiveness is reasonable at this time, given the significant 
emission reductions already achieved by BART and RP determinations 
during this planning period (see Table 12).
---------------------------------------------------------------------------

    \240\ We also note that while NPS refers to ``BART for Cholla 
Unit 1'', Cholla Unit 1 is, in fact, not BART-eligible and therefore 
not subject to BART. See 78 FR 46145.
    \241\ I.e., BART has very specific applicability criteria, and 
is a ``one-time'' analysis that is only performed on affected 
sources during the first planning period. The procedure for 
identifying candidate sources for RP controls is not as specific, 
may have more or less expansive criteria than BART, and can be 
potentially performed each planning period.
    \242\ See, e.g. BART EGU FIP Summary.
---------------------------------------------------------------------------

    Comment: ADEQ expressed support for EPA's determination that it is 
not practical to control compressor stations due to their dispersed 
locations. Similarly, the owner of Williams and Flagstaff Compressor 
Stations (EPNG) said that it agreed with EPA's determination that it is 
not reasonable to require further controls at these two facilities. 
Even though EPNG supported EPA's decision, EPNG did not agree that the 
control technology, cost of compliance, and time to comply used by EPA 
in its analysis are appropriate.
    Response: We acknowledge ADEQ's and EPNG's support on this issue. 
We note that our finding of impracticability with regard to the 
regulation of engines (including those found at compressor stations) 
only applies to regulation by EPA in this planning period. It does not 
apply to potential regulation by the State in future planning periods. 
Given the availability of cost-effective controls for these sources and 
the potential for significant emission reductions from a statewide rule 
applicable to such sources, we strongly encourage ADEQ to develop such 
a rule during the next planning period. We acknowledge the comments 
made by EPNG regarding our control technology analyses for the natural 
gas turbines, but have not revised our analysis at this time because it 
would not alter our determination not to control compressor stations at 
this time.
    Comment: TEP, the owner of the Sundt and Springerville facilities, 
agreed with EPA's conclusion that additional controls are not required 
on Springerville Units 1 and 2 or Sundt Units 1-3 at this time. ADEQ 
similarly expressed support for the EPA's decision not to require low-
NOX burners for Sundt Units 1-3 because they are not cost-
effective. TEP added that the same result would have been achieved if 
EPA had approved ADEQ's identical determination.
    Response: We acknowledge TEP's support on this issue. We agree 
that, with regard to TEP Sundt Unit 1-3, our determinations are 
identical to those made by ADEQ. However, we note that, unlike ADEQ, 
EPA conducted a four-factor RP analysis for these units, as well as 
visibility modeling to evaluate potential visibility benefits, before 
concluding that no additional controls are reasonable at this time.
    Comment: The owner of Tucson Compressor Station (EPNG) indicated 
that that the facility is no longer operating and should therefore be 
removed from the FIP.
    Response: We appreciate the clarification. Our proposed FIP did not 
require any controls for this facility, so no revisions are needed.

D. Comments on Area Sources of NOX and SO2

    Comment: Earthjustice argued that area sources should also be 
required to install reasonable progress controls. Earthjustice referred 
to an NPCA Report \243\ that shows how Visibility Restoration Plans can 
help ensure that Class I areas achieve the glide path by 2064. The 
report indicated that Arizona's area sources are the largest 
contributors to visibility impairment at the Grand Canyon. Earthjustice 
noted that EPA looked at reasonable progress controls for area sources, 
but classified its analysis as ``limited in scope.'' Earthjustice 
explained that EPA identified the area source categories contributing 
the most to visibility impairment, but performed only a brief analysis 
because the inventories that were analyzed did not contain sufficient 
data (e.g., on the number, age, and design of the actual area sources). 
In Earthjustice's opinion, in order to conduct a thorough reasonable 
progress analysis in this case where there was limited information 
available, EPA should have obtained the data necessary to conduct a 
proper analysis. Further, Earthjustice said that the justification for 
no further controls based on no other regional haze SIP or FIP 
requiring controls on such sources primarily to ensure reasonable 
progress is not sufficient, because no other state had RPGs as poor as 
Arizona's.
---------------------------------------------------------------------------

    \243\ National Parks Conservation Association, On an Approach 
for Improving Visibility in Class I Areas Using Visibility 
Restoration Plans (VRPs) with an Example VRP for the Grand Canyon 
National Park (2014). Exhibit 17 in Earthjustice's comments. 
Hereafter ``NPCA Report''.
---------------------------------------------------------------------------

    Earthjustice highlighted the Visibility Restoration Plan that was 
submitted with the Earthjustice's public comments as a tool to help EPA 
in identifying other sources that impact visibility, and should be 
evaluated for reasonable progress controls. According to Earthjustice, 
the Visibility Restoration Plan could also be a helpful tool to the 
Agency by illustrating how a long-term strategy based on existing data 
can be developed to restore visibility by 2064. In Earthjustice's 
opinion, if the plan is adopted, this would assist states and EPA to 
implement the goals of the haze program's reasonable progress mandate.
    Response: We do not agree that additional area source controls are 
reasonable for this planning period. According to our analysis, 
Arizona's area sources are typically the smallest contributor to 
anthropogenic nitrate and sulfate pollution at Arizona's Class I areas, 
including the Grand Canyon, where Arizona area sources contribute only 
2.9 percent of the nitrate pollution and only 0.4 percent of the 
sulfate pollution.\244\ EPA's analysis is based on source apportionment 
modeling conducted by the WRAP. As we note in the proposal, EPA has 
carefully evaluated that work and has determined it to be of sufficient 
quality to use in making policy decisions.
---------------------------------------------------------------------------

    \244\ See 79 FR 9362, Tables 53 and 54.
---------------------------------------------------------------------------

    The NPCA Report suggests that the contribution of Arizona's area 
sources to haze at the Grand Canyon may be greater than indicated by 
our analysis. However, as acknowledged in the NPCA Report's Visibility 
Restoration Plan (VRP), there are significant limitations in the data 
on which the VRP is based.\245\ Furthermore, the average apportionment 
provided in the VRP is based on the highest 10 daily-average 
PM2.5 concentrations,\246\ rather than the 20 percent most 
impaired days and the 20 percent least impaired days, on which RPGs are 
based. Therefore, the NPCA Report does not provide an adequate 
technical basis for revising our findings regarding the relative 
contribution of area sources at Arizona's Class I areas. Accordingly, 
for the reasons described in our proposal, we conclude that it is not 
reasonable to require additional controls on Arizona's area sources at 
this time.
---------------------------------------------------------------------------

    \245\ NPCA Report, section C.2 at 10 (``While we have currently 
accepted these findings for the purposes of developing the example 
VRP for the GCNP, the accuracy of these findings is questionable and 
a thorough analysis of the many emission inventories and modeling 
assumptions made in the WestJump study would be a necessary task in 
developing an actual VRP for any Class I area'').
    \246\ NPCA Report, Attachment B Development of Extinction Source 
Apportionment Data for the Visibility Restoration Plan, Particulate 
Matter Species Apportionment (``The average apportionment during the 
highest ten daily-average PM2.5 concentrations was 
created for the six PM species corresponding to the six pollutants 
that account for the controllable contributions to Bext 
(PMC, EC, NO3, SOA, SO4, and 
PM2.5)'').

---------------------------------------------------------------------------

    Comment: EPNG said that it agrees with EPA's assessment that the 
potential visibility benefits from applying NOX controls at 
natural gas compressor stations would be relatively small.

[[Page 52468]]

    Response: We agree with this comment on a per-engine basis, but we 
strongly encourage the State to consider development of a statewide 
rule to regulate the categories of natural gas engines and sewage 
treatment plants in the next planning period.

E. Comments on Reasonable Progress Goals and Uniform Rate of Progress

    Comment: Two commenters objected to the lack of numerical RPGs, 
expressed in deciviews, in EPA's proposed FIP. CPC asserted that 
because EPA disapproved Arizona's RPGs, EPA is required to establish 
its own RPGs, under 40 CFR 51.308(d). CPC noted that there is no 
statutory or regulatory provision that excuses compliance with 
51.308(d)(1) due to time and resource limitations. CPC added that EPA 
would not approve a SIP that did not include numerical RPGs. For these 
reasons, CPC asserted that the FIP cannot be approved as proposed.
    CPC also stated that there is no statutory or regulatory support 
for EPA's assertion that emission limitations are more critical 
components of an RH plan than RPGs. CPC stated that establishing RPGs, 
not emission limits, is the first ``core requirement'' listed in 
51.308(d), and that other components, including emission limits 
established as part of an LTS, must be developed in consideration of 
RPGs.
    CPC stated that future RH plans will be unable to comply with 40 
CFR 51.308(f), (g), and (h) unless numerical RPGs are established now. 
Citing 40 CFR 51.308(f)(2) and (3), CPC noted that Arizona must 
evaluate the effectiveness of its LTS for achieving RPGs and affirm or 
revise its RPGs as part of the next 10-year RH SIP. CPC also noted that 
Arizona must submit a report to the Administrator every five years 
evaluating progress toward RPGs. CPC stated that such provisions are 
predicated on the establishment of numerical RPGs and that without 
this, the proposed FIP does not comply with the RHR today and prevents 
Arizona from complying with the RHR in the future.
    Earthjustice also asserted that EPA should quantify its RPGs. 
Earthjustice stated that EPA's contention that it has limited time and 
resources to conduct this task is not justified because Arizona 
completed its analysis within months of EPA's request. Earthjustice 
further pointed out that EPA did analysis to determine RPGs in other 
haze FIPs, such as Hawaii and Montana. Earthjustice also found EPA's 
claim of insufficient time and resources weak considering the multiple 
extensions it has received on the consent decree deadlines to complete 
the FIP. Therefore, Earthjustice asserted that EPA's claim is not 
warranted and the Agency should have conducted this critical analysis. 
Earthjustice strongly urged EPA to conduct this analysis during this 
rulemaking to meet the RHR requirements and for the purpose of 
identifying emission reductions needed for future planning periods. 
Earthjustice contended that EPA and the public must have this 
information available in order to determine how progress will be made 
and how reasonable EPA's plan is.
    Response: We agree that, having disapproved Arizona's RPGs, EPA is 
required to establish new RPGs under 40 CFR 51.308(d). Therefore, we 
proposed non-quantified RPGs consistent with the combination of 
approved control measures in the Arizona RH SIP, the Phase 1 RH FIP, 
and the proposed Phase 3 RH FIP.\247\ We explained that ``[w]hile we 
would prefer to quantify these proposed RPGs for each of Arizona's 12 
Class I areas based on the new State and Federal plans, we lack 
sufficient time and resources to conduct the type of regional-scale 
modeling required to develop such numerical RPGs.'' \248\ The 
commenters underestimate the difficulty and time required for this 
task. While Earthjustice points to the effort of Arizona to provide for 
new RPGs, the State's effort was based on an extrapolation of 
historical monitoring trends into the future without any evaluation of 
whether these trends could reasonably be expected to continue through 
2018.\249\ Further, the RPGs that EPA promulgated for Hawaii and 
Montana are not directly comparable to the situation in Arizona. For 
Montana, EPA relied on WRAP modeling to set RPGs without updating the 
modeling to reflect additional controls included in the FIP.\250\ For 
Hawaii, EPA employed unique, island-specific emission inventories to 
develop RPGs.\251\
---------------------------------------------------------------------------

    \247\ 79 FR 9363.
    \248\ Id.
    \249\ The State's analysis included monitored data for 2000 
through 2010, i.e. including several years after the 2000-2004 
baseline, during which the effect of emission changes from new 
controls and other causes might be expected to manifest. We did not 
find the evidence for downward trends compelling, partly because the 
year to year variability was comparable to the claimed decreases in 
visibility impairment. 78 FR 29297. A portion of the State analysis 
attempted to explain some periods of anomalously high sulfate 
impairment, with back trajectories suggesting that they were due to 
out-of-State sources. The difficulty of this analysis illustrates 
why recent monitored trends by themselves are not a reliable basis 
for projecting progress, and why multistate photochemical modeling 
is needed. Unlike trend analysis, such modeling accounts for out-of-
State and other sources, along with the varying meteorology and 
atmospheric chemistry conditions encountered by the pollution plumes 
from these sources. In any case, the State's analysis and recent 
trend data do not provide us a basis for establishing numerical 
RPGs.
    \250\ 77 FR 23988, 24053.
    \251\ See 77 FR 31693, 31708.
---------------------------------------------------------------------------

    Development of more refined numerical RPGs for each of Arizona's 12 
Class 1 would require photochemical grid modeling of a multistate area, 
involving thousands of emission sources, unlike the comparatively 
simple single-source CALPUFF modeling used for individual BART 
assessments. In order to accurately reflect all emissions reductions 
expected to occur during this planning period, the new modeling would 
require an update of the emissions inventory for Arizona and the 
surrounding states to include not just the actions under this FIP, but 
all EPA and state regulatory actions on point, area, and mobile 
sources. After the inventory is developed and reviewed by the affected 
states for accuracy, it must be converted to a model-ready format 
before air quality modeling can be used to estimate the future 
visibility levels at the Class I areas.\252\ This modeling would 
require specialized and extensive computing hardware and expertise. 
Developing all of the necessary input files, running the photochemical 
model, and post-processing the model outputs would take several months 
at a minimum. Finally, the specific controls we are requiring that 
would be inputs to the modeling changed from the proposal as a result 
of comments and supplemental information received from the affected 
facilities and other commenters. Some of these changes occurred only 
shortly before the deadline for this action, leaving insufficient time 
for the extensive modeling effort required to develop new RPGs based on 
photochemical modeling. Therefore, we were unable to conduct additional 
modeling to quantify the degree of progress that we expect to result 
from this new combination of controls.
---------------------------------------------------------------------------

    \252\ 79 FR 2437.
---------------------------------------------------------------------------

    Nonetheless, in order to provide RPGs that account for emission 
reductions from the FIP controls, we have used a method similar to the 
one that we used in our FIP for Hawaii, which is based on a scaling of 
visibility extinction components in proportion to emission changes. To 
determine the RPGs, we started with the 2018 projection of extinction 
components from the WRAP's CMAQ photochemical modeling of WRAP 
emissions scenario PRP18b (``Preliminary Reasonable Progress for 2018, 
version b''). This

[[Page 52469]]

CMAQ PRP18b emission scenario included the results of State BART 
determinations and other SIP controls, as well as projected emissions 
from other point, area, and mobile sources.\253\ We scaled the modeled 
visibility extinction components for sulfate (SO4) and 
nitrate (NO3) in proportion to the FIP's emission reductions 
for SO2 and NOX, respectively. The sulfate 
scaling factor was the CMAQ PRP18b SO2 emissions with FIP 
controls for BART and RP sources in place, divided by the original CMAQ 
PRP18b SO2 emissions.\254\ We conducted the same scaling 
exercise with nitrate and NOX. The scaled sulfate and 
nitrate extinctions were added to the unscaled extinctions for organic 
mass and other components to get total extinction, and then this was 
used to calculate post-FIP RPGs in deciviews.\255\ The results of this 
analysis are shown in Tables 9 and 10.
---------------------------------------------------------------------------

    \253\ ``Simulation Specification for 2018 Preliminary Reasonable 
Progress Simulation version B'', WRAP Regional Modeling Center, 
August 11, 2009. Available at WRAP Regional Modeling Center 
Visibility Modeling Results Web page http://pah.cert.ucr.edu/aqm/308/cmaq.shtml.
    \254\ We assumed that the relevant inventory is the emissions in 
Arizona and all of its neighboring states.
    \255\ Additional details of the calculation are available in a 
spreadsheet in the docket, FIPRPGestimates.xlsx.

                                                                  Table 9--Reasonable Progress Goals for 20 Percent Worst Days
                                                                                         [In deciviews]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                     2064                      2018                                  Years to
                   Code                            Class I area             IMPROVE monitor code     2000-2004     natural      2018 URP    projection   FIP effect    FIP 2018    reach natural
                                                                                                      baseline    conditions                 by WRAP                     RPG        conditions
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
chir.....................................  Chiricahua NM...............  CHIR1....................        13.43         7.20        11.98        13.35        -0.16        13.19             367
chrw.....................................  Chiricahua WA...............  CHIR1....................        13.43         7.20        11.98        13.35        -0.16        13.19             367
gali.....................................  Galiuro WA..................  CHIR1....................        13.43         7.20        11.98        13.35        -0.16        13.19             367
grca.....................................  Grand Canyon NP.............  GRCA2....................        11.66         7.04        10.58        11.14        -0.11        11.02             101
maza.....................................  Mazatzal WA.................  IKBA1....................        13.35         6.68        11.79        12.76        -0.13        12.63             131
moba.....................................  Mount Baldy WA..............  BALD1....................        11.95         6.24        10.62        11.52        -0.13        11.40             141
pefo.....................................  Petrified Forest NP.........  PEFO1....................        13.21         6.49        11.64        12.76        -0.12        12.64             165
pimo.....................................  Pine Mountain WA............  IKBA1....................        13.35         6.68        11.79        12.76        -0.13        12.63             131
sagu.....................................  Saguaro NP East.............  SAGU1....................        14.83         6.46        12.88        14.82        -0.13        14.68             767
sagu.....................................  Saguaro NP West.............  SAWE1....................        16.22         6.24        13.90        15.99        -0.12        15.87             397
sian.....................................  Sierra Ancha WA.............  SIAN1....................        13.67         6.59        12.02        13.17        -0.12        13.05             159
supe.....................................  Superstition WA.............  TONT1....................        14.16         6.61        12.40        13.85        -0.13        13.72             237
syca.....................................  Sycamore Canyon WA..........  SYCA1....................        15.25         6.65        13.25        15.00        -0.08        14.92             360
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


                                              Table 10--Reasonable Progress Goals for 20 Percent Best Days
                                                                     [In deciviews]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         2064         2018
              Code                   Class I area      IMPROVE monitor   2000-2004     natural     projection   FIP effect    FIP 2018     Degradation?
                                                            code          baseline    conditions    by WRAP                     RPG
--------------------------------------------------------------------------------------------------------------------------------------------------------
chir............................  Chiricahua NM.....  CHIR1...........         4.91         1.83         4.90        -0.12         4.77              No
chrw............................  Chiricahua WA.....  CHIR1...........         4.91         1.83         4.90        -0.12         4.77              No
gali............................  Galiuro WA........  CHIR1...........         4.91         1.83         4.90        -0.12         4.77              No
grca............................  Grand Canyon NP...  GRCA2...........         2.16         0.31         2.12        -0.10         2.02              No
maza............................  Mazatzal WA.......  IKBA1...........         5.40         1.91         5.17        -0.11         5.07              No
moba............................  Mount Baldy WA....  BALD1...........         2.98         0.51         2.86        -0.10         2.76              No
pefo............................  Petrified Forest    PEFO1...........         5.02         1.07         4.73        -0.11         4.62              No
                                   NP.
pimo............................  Pine Mountain WA..  IKBA1...........         5.40         1.91         5.17        -0.11         5.07              No
sagu............................  Saguaro NP East...  SAGU1...........         6.94         2.23         7.04        -0.11         6.93              No
sagu............................  Saguaro NP West...  SAWE1...........         8.58         2.50         8.34        -0.11         8.23              No

[[Page 52470]]

 
sian............................  Sierra Ancha WA...  SIAN1...........         6.16         2.03         5.88        -0.10         5.78              No
supe............................  Superstition WA...  TONT1...........         6.46         2.03         6.22        -0.12         6.09              No
syca............................  Sycamore Canyon WA  SYCA1...........         5.58         0.98         5.49        -0.10         5.39              No
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Although we recognize that this method is not refined, it allows us 
to translate the emission reductions achieved through the FIP into 
quantitative RPGs, based on modeling previously performed by the WRAP. 
These RPGs reflect rates of progress that are faster than the rates 
projected by the State, but are still slower than the URP for each 
Class I areas. Nonetheless, we consider these rates to be reasonable 
for the reasons set forth in our proposal and in this final rule. We 
also note that RPGs, unlike the emission limits that apply to specific 
RP sources, are not directly enforceable.\256\ Rather, they are an 
analytical tool used by EPA to evaluate whether measures in the 
implementation plan are sufficient to achieve reasonable progress.\257\ 
Arizona may choose to use these RPGs for purposes of its progress 
report, or may develop new RPGs, based on new modeling or other 
appropriate techniques, in accordance with the requirements of 40 CFR 
51.308(d)(1).
---------------------------------------------------------------------------

    \256\ 40 CFR 51.308(d)(1)(v).
    \257\ Id.
---------------------------------------------------------------------------

    Comment: Citing 40 CFR 51.308(d)(1)(vi) and EPA's RP Guidance, CPC 
stated that emission reductions that will occur under other CAA 
requirements must be taken into account when establishing RPGs. For 
example, CPC cited the Portland Cement MACT that imposes a PM emission 
standard of 0.07 lb/ton clinker for existing kilns and clinker coolers. 
The revised Portland Cement MACT will significantly reduce PM emissions 
at the Rillito Cement Plant. CPC stated that this is particularly 
noteworthy because at Saguaro National Park and other Class I areas in 
Arizona, PM is a far more substantial contributor to regional haze than 
NOX. CPC asserted that even if no additional controls are 
imposed as part of this initial RH plan, emissions of the primary 
visibility-impacting pollutant will substantially decrease at the 
Rillito Plant.
    Response: We partly agree with this comment. The cited provision of 
the RHR prohibits the adoption of RPGs that represent less visibility 
improvement than is expected to result from implementation of other 
requirements of the CAA during the applicable planning period.\258\ 
EPA's RP Guidance explains that states ``must therefore determine the 
amount of emission reductions that can be expected from identified 
sources or source categories as a result of requirements at the local, 
State, and federal levels during the planning period of the SIP and the 
resulting improvements in visibility at Class I areas.'' \259\ The WRAP 
modeling that Arizona used to develop RPGs addressed this requirement 
by including all emission reductions expected at the time that the 
modeling was performed.\260\ In addition, Arizona submitted a 
supplemental analysis of monitored coarse mass and fine soil impairment 
at the State's Class I areas, including an examination of the monitored 
visibility impairment at Class I areas near large stationary sources of 
PM10.\261\ Based on these analyses and EPA's supplemental 
analysis, as described in our supplemental notice of proposed 
rulemaking, we approved Arizona's conclusion that no further analysis 
of PM controls was necessary for this planning period.\262\ Therefore, 
we do not agree that we are required to consider expected reductions in 
PM emissions from the Portland Cement MACT. Nonetheless, we note that, 
according to information supplied by CPC, implementation of the cement 
MACT at Kiln 4 would result in a relatively modest decrease in 
emissions from 9.6 pounds/hour (lb/hour) to 9.0 lb/hour, a difference 
of 0.6 lb/hour or 6.25 percent.\263\ According to modeling performed by 
the WRAP, based on an emission rate of 1.43 grams/second (g/s) (about 
11.3 lb/hour), the baseline impact of PM emissions from Kiln 4 at the 
Rillito Plant would be 0.02 dv or less at all potentially affected 
Class I areas.\264\ While the expected emission reductions from Kilns 
1-3 are greater, these kilns have not operated since 2008, so there 
would be no practical impact from this change. Therefore, the overall 
visibility improvement expected from implementation of the Portland 
Cement MACT at the Rillito Plant would be de minimis.
---------------------------------------------------------------------------

    \258\ 40 CFR 51.308(d)(1)(vi).
    \259\ RP Guidance section 4.1.
    \260\ See Arizona RH SIP at 167 (explaining that Arizona's RPGs 
are based on, among other things, ``the results of the CMAQ modeling 
. . . which includes ``on-the-books'' controls and other emission 
inputs'' and Appendix C (list of CMAQ model emission inputs) Section 
11.3.3, and the BART review described in Chapter 10. http://wrapedms.org/InventoryDesc.aspx.
    \261\ Arizona RH SIP Supplement, page 97.
    \262\ See 78 FR 29298 (proposing to concur with the State's 
decision to omit coarse mass and fine soil from its four-factor 
reasonable progress analysis for this planning period); 78 FR 46175, 
codified at 40 CFR 52.120(c)(154)(ii)(A)(2) and (c)(158) (approving 
the Arizona Regional Haze SIP, except for specified sections).
    \263\ See CPC Comments, Exhibit 2.
    \264\ Summary of WRAP RMC BART Modeling for Arizona 
Draft5, May 25, 2007, at 2 (Table 1) and 17, SRC04 Arizona 
Portland Cement: PM Only (98th percentile 3 Year Average).
---------------------------------------------------------------------------

    Comment: CPC stated that EPA's proposed demonstration that its RPGs 
are reasonable does not and cannot comply with all requirements of 
51.308(d)(1)(ii), which state that a RH plan ``must provide to the 
public for review an assessment of the number of years it would take to 
attain natural conditions if visibility improvement continues at the 
rate of progress selected by the State as reasonable.'' As the FIP does 
not contain this analysis, CPC asserted that the proposed rule does not 
comply with these requirements.
    CPC further stated that once EPA establishes RPGs based on the 
controls proposed for BART sources, it may learn that 40 CFR 
51.308(d)(l)(ii) is not even applicable. CPC asserted that given the 
significant additional controls proposed for BART sources, it is likely 
that several Class I Areas will be on pace to meet or exceed URPs, 
eliminating the need to provide the assessment required here. For 
example, CPC stated that at Saguaro National Park, EPA has estimated 
that its proposed BART controls on the Hayden Smelter, Miami Smelter, 
and Apache Power Plant will have a collective visibility benefit of 
2.68 dv, more than enough to meet the URP with no additional controls. 
CPC added that if Saguaro National Park is already on pace to meet the 
URP, then

[[Page 52471]]

it would be reasonable to conclude that additional controls are not 
necessary for Kiln 4 at this time.
    Response: We disagree with this comment. As shown in Table 9 above, 
even accounting for BART and RP controls, the RPG for Saguaro National 
Park on the 20 percent worst days is still well above the URP, and it 
is expected to take hundreds years to reach natural conditions. It is 
important to note that deciview improvements modeled for individual 
BART and RP sources using CALPUFF are not directly comparable to RPGs. 
In particular, modeling for individual BART and RP sources is performed 
using natural background conditions, rather than current, degraded 
conditions. EPA explained the rationale for this approach in the 
preamble to the BART Guidelines:

    Using existing conditions as the baseline for single source 
visibility impact determinations would create the following paradox: 
the dirtier the existing air, the less likely it would be that any 
control is required. This is true because of the nonlinear nature of 
visibility impairment. In other words, as a Class I area becomes 
more polluted, any individual source's contribution to changes in 
impairment becomes geometrically less. Therefore the more polluted 
the Class I area would become, the less control would seem to be 
needed from an individual source. . . . Such a reading would render 
the visibility provisions meaningless, as EPA and the States would 
be prevented from assuring ``reasonable progress'' and fulfilling 
the statutorily-defined goals of the visibility program. \265\
---------------------------------------------------------------------------

    \265\ See 70 FR 39124.

    Thus, EPA has determined that it is appropriate to use natural 
background conditions in order to gauge the impacts of an individual 
source and the expected benefits of controls on an individual source.
    By contrast, RPGs are intended to reflect actual conditions at a 
future date. Accordingly, they are typically set using regional-scale 
photochemical grid modeling that accounts for the visibility impacts of 
numerous sources over a large geographic area. Under this approach, the 
impact attributable to any one source (and the benefits available from 
controls on any one source) are quite small. Therefore, the expected 
degree of visibility improvement (in dv) from controls on individual 
sources does not translate directly into the same degree of improvement 
in RPGs.
    Comment: Citing 40 CFR 51.308(d)(1)(iv), CPC stated that the RHR 
imposes an obligation to consult with states that may reasonably be 
anticipated to cause or contribute to visibility impairment in 
Arizona's Class 1 areas. CPC stated that the proposed FIP does not 
identify this requirement or explain how it complies with it. CPC 
concluded that because this consultation must occur when developing 
each RPG, the proposed FIP does not comply with this requirement.
    Response: We do not agree with this comment. As explained in our 
proposal, the Arizona RH FIP covers only those elements of the RHR for 
which we disapproved the Arizona RH SIP.\266\ Although we disapproved 
Arizona's RPGs, we did not disapprove the Arizona RH SIP with respect 
to the consultation requirements 40 CFR 51.308(d)(iv). As explained in 
our proposal on the Arizona RH SIP, ``Arizona consulted with other 
states and tribes using the WRAP forums and processes. In particular, 
Arizona consulted with California, Colorado, New Mexico, and Utah using 
the primary vehicle of the WRAP Implementation Work Group (IWG).'' 
\267\ EPA also consulted with these other states through our 
participation in the WRAP.\268\ Furthermore, as explained elsewhere in 
this notice, we have relied upon modeling performed by the WRAP to help 
quantify RPGs for Arizona. In addition, through our actions on other 
states' RH SIPs, EPA has considered the impacts of emissions from other 
states on Arizona's Class I areas.\269\ Therefore, we do not agree that 
we failed to comply with 40 CFR 51.308(d)(1)(iv) or that further 
consultation was necessary for purposes of today's FIP.
---------------------------------------------------------------------------

    \266\ See also CAA section 302(y), 42 U.S.C. 7602(y) (defining 
FIP 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 [SIP] . . .'').
    \267\ 79 FR 75730.
    \268\ See, e.g. http://www.wrapair.org/commforum.html 
(describing and listing membership of various WRAP forums, 
committees and work groups).
    \269\ See, e.g. 76 FR 13944, 13953 (discussing the ``very small 
impact on visibility impairment'' of emissions from California on 
Grand Canyon NP and Sycamore Canyon NP); 77 FR 50936, 50937 
(discussing expected improvement in visibility at Grand Canyon NP 
from BART at Reid Gardner Generating Station in Nevada); 79 FR 
26909, 26917, Table 4 (showing expected visibility improvement at 
Grand Canyon NP and Petrified Forest NP from BART at San Juan 
Generating Station in New Mexico).
---------------------------------------------------------------------------

    Comment: CPC asserted that 40 CFR 51.308(i)(2) requires that FLMs 
must be provided with an opportunity for consultation at least 60 days 
before holding any public hearing on a regional haze implementation 
plan, and must be provided an opportunity to discuss their 
recommendations on development of RPGs. CPC stated that the proposed 
FIP neither identifies nor explains how these requirements were met.
    Response: We do not agree with these comments. As noted above, the 
Arizona RH FIP covers only those elements of the RHR for which we 
disapproved the Arizona RH SIP.\270\ We approved the Arizona RH SIP 
with respect to the requirements of 40 CFR 51.308(i).\271\ Therefore, 
no FIP is required for this element under the RHR. Nonetheless, we 
consulted the FLMs during development of the proposed FIP and we have 
considered and responded to their comments on our proposal, as 
documented elsewhere in this notice. We note that, while the FLMs have 
urged EPA to require additional RP controls, they expressed support for 
EPA's proposed determinations with regard to CPC's Rillito Plant.\272\
---------------------------------------------------------------------------

    \270\ See also CAA section 302(y), 42 U.S.C. 7602(y) (defining 
FIP 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 [SIP] . . .'').
    \271\ See 77 FR 75734 (proposing to find that Arizona met the 
requirements for coordination with the FLMs under 40 CFR 51.308(i)); 
78 FR 46175 (codified at 40 CFR 52.120(c)(154)(ii)(A)(2) and 
(c)(158)) (approving the Arizona Regional Haze SIP, except for 
specified sections).
    \272\ NPS Comment Letter at 7-8, 10-11.
---------------------------------------------------------------------------

    Comment: NPS indicated that it agreed with EPA that it is not 
likely that all of Arizona's Class I areas will meet the URP during 
this planning period. But, according to NPS, this is partly because EPA 
and states have not done enough to properly address emissions from RP 
sources. NPS expressed disappointment that although EPA has 
acknowledged that certain control technologies are cost-effective, it 
still proceeded to reject certain controls because they would lead to 
insufficient improvements in visibility. According to NPS, a 
fundamental principle of the RHR is the recognition that a decline in 
visibility is due to a number of sources that contribute to a 
cumulative visibility issue. NPS argued that EPA's approach of 
disaggregating each source's contributions to visibility impairment 
does not solve the problem. The EGU sources that EPA analyzed for 
reasonable progress, i.e., Cholla Unit 1 and Springerville Units 1 and 
2, combined to cause a cumulative 32 dv of impairment at Class I areas 
in the State. By installing controls on these units, NPS said that 
emissions could be reduced by more than 4,400 tpy and decrease 
visibility impacts by 2.6 dv at a cost of $25 million annually. NPS 
asserted that, by not requiring controls on these units, EPA has failed 
to meet its obligation to show that it has taken all reasonable 
measures to make reasonable progress at this time.
    Response: We agree with NPS that a fundamental principle of the RHR 
is the

[[Page 52472]]

recognition that visibility impairment at Class I areas is caused by a 
multitude of different sources. However, in this particular action, EPA 
is only considering the reasonableness of controls for point sources of 
NOX and area sources of NOX and SO2. 
As for the specific EGUs referenced in this comment, we have addressed 
NPS's concerns about these sources elsewhere in this notice. Therefore, 
we do not agree that EPA has failed to meet its obligation to ensure 
reasonable progress. We will continue to work with NPS, the State, and 
other stakeholders to ensure that reasonable progress is made at 
Arizona's Class I areas.
    Comment: PCC agreed with EPA that it is necessary to consider the 
degree of improvement in visibility that would be achieved by the 
imposition of control technology-based standards under 40 CFR 
51.308(d)(1)(i)(A), but noted the requirement of 40 CFR 
51.308(d)(1)(i)(B) to consider the uniform rate of improvement in 
visibility. PCC stated that, although EPA has appropriately concluded 
it is not reasonable to provide for rates of progress at any of 
Arizona's Class I areas consistent with the URP in this planning 
period, EPA should make clear the functional distinction between 40 CFR 
51.308(d)(1)(i) [RP analysis] and 308(e)(1)(ii)(A) [BART analysis] or 
else the distinction might appear to be irrelevant. PCC said this 
clarity is needed where BART-ineligible sources are concerned, 
particularly PCC, for which EPA characterized the proposed standard as 
``EPA's proposed BART,'' even though PCC is a BART-ineligible source.
    Response: We agree that the Clarkdale Plant is not BART-eligible. 
The reference in the TSD to ``EPA's proposed BART'' for the Clarkdale 
Plant was a clerical error. Thus, our analysis of the Clarkdale Plant 
is based solely on the RP requirements. There are several distinctions 
in the applicable requirements for RP sources and BART sources, which 
are reflected in our analyses for the respective source types. First, 
unlike for BART, the expected degree of visibility improvement is not 
listed in the RHR as a required factor for consideration in relation to 
individual RP sources. While we have considered visibility improvement 
as a supplementary factor for RP sources, we have not given it the same 
weight as in our BART determinations, for which it is a mandatory 
statutory factor. Second, ``the time necessary for compliance'' is a 
required factor for RP, but not for BART, and we have considered it as 
such. Third, BART controls must be installed ``as expeditiously as 
practicable,'' whereas there is no similar requirement for RP sources. 
Thus, we do not consider the distinction between BART and RP sources to 
be irrelevant.
    Comment: Earthjustice stated that EPA's proposed FIP fails to meet 
the goals of the regional haze program. The commenter asserted that 
EPA's RPGs and reasonable progress determination are in violation of 
the CAA. Earthjustice said that Arizona's regional haze plan, which EPA 
disapproved, was far from meeting the RPGs and would have delayed 
natural visibility for Arizona's national parks and wilderness areas by 
hundreds, even thousands of years. According to Earthjustice, it is now 
EPA's responsibility to step in and ensure that a Federal haze plan 
makes reasonable progress toward the national goals, because Arizona's 
plan failed to do so. However, in Earthjustice's opinion, EPA's 
proposal failed to comply with the regional haze program's reasonable 
progress requirements. Earthjustice pointed out that the Agency 
admitted that the Federal plan will not achieve reasonable progress 
towards the 2064 goal. Earthjustice continued by stating that EPA has 
failed to meet the requirements of 40 CFR 51.308(d)(1)(ii) to 
demonstrate that (1) the 2064 goal is unreasonable at each of Arizona's 
Class I areas and that (2) EPA's RPGs are reasonable.
    Earthjustice stated that EPA should have determined the necessary 
emissions reductions needed to remain on the 2064 glide path and 
whether those reductions would be reasonable based on the four 
reasonable progress factors. According to Earthjustice, instead of 
doing this EPA promptly determined that the 2064 glide path was 
unachievable because the individual source-by-source reasonable 
progress determinations would not be enough to meet the glide path. 
Earthjustice acknowledged and appreciates the work EPA has done in 
place of Arizona's inadequate haze plan. However, Earthjustice thought 
that the approach EPA has followed is inadequate because it is not 
bound to the overarching 2064 natural visibility goal. Specifically, it 
is not known what level of emissions reductions (1,000, 100,000 or 
1,000,000 tpy) will ensure that the State of Arizona will meet the 
glide path for each Class I area. Nor is it known how those reductions 
could be achieved and if those reductions would be reasonable. Because 
these analyses have not been conducted, Earthjustice argued that EPA 
has not shown that it would be unreasonable for Arizona's Class I areas 
to achieve the glide path.
    Earthjustice pointed to a brief filed by EPA in American Corn 
Growers, where EPA stated that:

    Certainly the courts would not find it difficult to affirm an 
EPA decision finding a State plan ``unreasonable'' if a State 
proposes to improve visibility so slowly that the national 
visibility goal would not be achieved for 200 or 300 years despite 
the availability of more stringent, cost-effective measures.\273\
---------------------------------------------------------------------------

    \273\ Corrected Final Brief of Respondent EPA at 80-81, Am. Corn 
Growers Ass'n v. EPA, 291 F.3d 1 (D.C. Cir. 2002) (No. 99-1348). 
Submitted with the comments as Exhibit 15.

    Earthjustice stated, however, that under EPA's proposal it is very 
likely that it would take even longer to restore Class I areas to their 
natural visibility. In spite of recent EPA actions and the proposed 
pollution controls, the FIP does not, in Earthjustice's opinion, have 
sufficient emissions reductions to bring Arizona's Class I areas back 
on track to the glide path. Earthjustice asserted that additional 
controls are needed, and without further controls, it could still take 
centuries or millennia to restore natural visibility.
    Similarly, CPC stated that because the proposed FIP contains no 
discussion of what measures would be required to meet a uniform rate of 
improvement in Arizona's Class 1 areas, the proposed rule does not 
comply with 40 CFR 51.308(d)(1)(i)(B).
    Response: The commenters' focus on the URP for the 20 percent worst 
days is misguided for a number of reasons. First, the URP is not 
binding. A state or EPA can set RPGs that provide for less progress 
than the URP if those RPGs are demonstrated to be reasonable (and 
achievement of the URP to be unreasonable) based upon an analysis of 
the four RP factors.\274\ Second, as explained further below, much of 
the visibility impairment on the 20 percent worst days at many Class I 
areas implicated in this plan is caused by sources that are either non-
anthropogenic or not feasible to control. Under these circumstances, 
projections regarding progress on those days are of limited value in 
determining the reasonableness of additional controls. Lastly, the only 
source categories and pollutants at issue in this action are non-BART 
point sources of NOX and area sources of NOX and 
SO2. All other source categories and pollutants were 
addressed by EPA's action on the State's SIP.\275\
---------------------------------------------------------------------------

    \274\ See 64 FR 35730-35731.
    \275\ See 78 FR 46172.
---------------------------------------------------------------------------

    EPA disagrees with Earthjustice's assertion that we have not 
demonstrated that it is unreasonable to attain the URP. The commenter 
correctly notes that the

[[Page 52473]]

State's RPGs provide little visibility improvement on the 20 percent 
worst days, leading to long estimates of the time that would be 
required to attain ``natural'' levels of visibility. Earthjustice 
implicitly assumes that most of the visibility impairment on the 20 
percent worst days is from controllable, anthropogenic sources. As EPA 
explained in our previous action on the Arizona RH SIP, the causes of 
haze on the 20 percent worst days in the Class I areas of Arizona are 
often due to largely uncontrollable sources.\276\ Table 8 in our 
December 21, 2012, proposed action on the Arizona RH SIP shows the 
causes of haze at the Class I areas in Arizona. Earthjustice 
highlighted seven Class I areas that are projected to make particularly 
slow progress in visibility improvement on the 20 percent worst days: 
Saguaro National Park East Unit (SAGU1 monitor), Chiricahua National 
Monument, Chiricahua Wilderness and Galiuro Wilderness (all represented 
by the CHIR1 monitor), Saguaro National Park West Unit (SAWE1 monitor), 
Sycamore Canyon Wilderness (SYCA1 monitor) and Superstition Wilderness 
(TONT1 monitor).\277\ As shown in Table 11, in each of these Class I 
areas, the majority of impairment on the 20 percent worst days is 
attributable to organic carbon, elemental carbon, coarse mass, fine 
soil and sea salt.
---------------------------------------------------------------------------

    \276\ The pollutants in question are organic carbon, elemental 
carbon, coarse mass, fine soil and sea salt. We explained in our 
action on the State's SIP that these pollutants are not reasonable 
to control at this time. 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.
    \277\ See 77 FR 75717.

Table 11--Percentage Contribution From Organic Carbon, Elemental Carbon,
 Coarse Mass, Fine Soil on 20 Percent Worst Days During Baseline Period
                                  \278\
------------------------------------------------------------------------
                                                       Contribution from
                                                         organic carbon,
                                                       elemental carbon,
                   IMPROVE Monitor                        coarse mass,
                                                         fine soil and
                                                            sea salt
                                                           (percent)
------------------------------------------------------------------------
SAGU1................................................               65.9
CHIR1................................................               68.9
SAWE1................................................               72.9
SYCA1................................................               81.8
TONT1................................................               66.8
------------------------------------------------------------------------

    We previously approved Arizona's RP determinations for this 
planning period with respect to each of these pollutants.\279\ We also 
approved the State's determination that it is not reasonable to require 
additional controls on mobile sources of NOX and 
SO2 and that it is not reasonable to require additional 
SO2 reductions from point sources in this planning period 
for RP purposes.\280\ Thus, the only RP issue at question in this 
action is whether it is appropriate to require controls on non-BART 
point sources of NOX or area sources of NOX and 
SO2 in order to ensure reasonable progress in visibility 
improvement. As explained elsewhere in this notice, based on our 
analyses of the four RP factors and the potential for visibility 
improvement from additional controls, we have determined that it 
reasonable to require installation of SNCR on two cement kilns by 2018, 
but that additional RP controls are not reasonable at this time.
---------------------------------------------------------------------------

    \278\ See Table 8 on 77 FR 75717.
    \279\ 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.
    \280\ 78 FR 46146.
---------------------------------------------------------------------------

    Comment: Earthjustice strongly urged EPA to require additional RP 
controls beyond the proposal for control on only two cement kilns, to 
make sure Arizona returns to the glide path to meet natural visibility 
goal in 2064. According to Earthjustice, in EPA's explanation of why it 
did not require any of the other sources of NOX to install 
pollution controls, EPA recognized that reasonable progress controls on 
these other sources are generally reasonable and EPA said that the 
decision of no control for these sources should be revisited in future 
planning periods. Earthjustice argued that taking into account how far 
off Arizona Class I areas are from their glide paths, EPA should 
require reasonable progress controls on these other sources during the 
current planning period. Earthjustice cited 40 CFR 51.308(d)(3)(ii), 
which requires ``all measures necessary'' be implemented to achieve 
reasonable progress. Earthjustice said that additional NOX 
reductions can be achieved at both cement plants and should be pursued 
in order to ensure Arizona Class I areas move closer towards the glide 
path.
    While acknowledging that EPA's proposal is an improvement over the 
State's plan, Earthjustice questioned whether it represents all 
measures that should be taken to reduce SO2, NOX, 
and PM that impair visibility at places like the Grand Canyon and the 
many other renowned national parks in Arizona and the Southwest. To the 
extent that it does not, Earthjustice encouraged EPA to compel further 
reductions. Earthjustice stated that it is good that EPA has acted, 
particularly in the earlier phase of the Arizona plan that compels 
controls on the Cholla, Coronado, and Apache coal-fired power plants, 
but Earthjustice asserted that given the level of impairment and 
numerous sources responsible, more should be done.
    Response: As explained in our response to the previous comment, the 
URP is not binding and a state or EPA can set RPGs that provide for 
less progress than the URP if those RPGs are demonstrated to be 
reasonable (and achievement of the URP to be unreasonable) based upon 
an analysis of the four RP factors.\281\ EPA disagrees with the 
Earthjustice's interpretation of 40 CFR 51.308(d)(3)(ii), which 
requires the State (or EPA in the case of a FIP) to implement all 
measures necessary to achieve the RPG. As explained in the previous 
response, due to our previous partial approval of the State's SIP, our 
RP analysis is limited to point sources of NOX and area 
sources of NOX and SO2. Our responses to comments 
regarding specific sources are included elsewhere in this notice. As 
explained in those responses, EPA does not agree that additional 
controls are warranted in this implementation period.
---------------------------------------------------------------------------

    \281\ See 64 FR 35730-35731.
---------------------------------------------------------------------------

F. Other Comments on Reasonable Progress

    Comment: ADEQ commented that even though EPA has disapproved the 
RPGs in Arizona's RH SIP, the Agency has been unable to develop 
specific goals, except for the ones based on the WRAP modeling results. 
The only thing EPA has added to the LTS for Arizona, besides new BART 
or reasonable progress control requirements, was ``enforceable 
measures.'' However, ADEQ asserted that many of these measures are 
already in place. For example, ADEQ asserted that ``EPA admits that the 
current Title V permit for the Miami Smelter provide[s] sufficient 
enforceability.'' Therefore, ADEQ argued that EPA has no basis for 
disapproving those portions of the Arizona RH SIP and should not impose 
a FIP for that reason.
    Response: These comments largely pertain to EPA's partial 
disapproval of the Arizona RH SIP and are therefore untimely, as EPA 
has already taken final action on the SIP.\282\ To the extent that that 
comments suggest that EPA has not fulfilled the requirements of the 
RHR, we do not agree. As explained above, we are now quantifying the 
RPGs that we proposed. These RPGs show greater

[[Page 52474]]

reasonable progress at all of the State's Class 1 areas than Arizona's 
RPGs. Furthermore, we note that our FIP includes enforceable emission 
limits and related requirements applicable to six different sources. 
The Arizona RH SIP did not include any such enforceable measures. With 
regard to the Miami Smelter in particular, as explained elsewhere in 
this notice, we are incorporating the relevant NESHAP requirements as 
part of the final FIP in order to ensure the federal enforceability of 
ADEQ's BART determination for PM10.
---------------------------------------------------------------------------

    \282\ 78 FR 46142.
---------------------------------------------------------------------------

    Comment: Earthjustice commented that additional PM reductions could 
be achieved by using improved fabric filter materials at the cement 
plants' fabric filters.
    Response: Because we previously approved the State's RP analysis 
for PM, we did not evaluate additional PM controls at any sources for 
purposes of our FIP. However, we note that, as detailed in CPC's 
comments, the Rillito Plant will be required to improve its PM controls 
in order to comply with the Portland cement MACT.

VIII. Responses to Comments on Statutory and Executive Order Reviews

    Comment: CPC stated that, with the exception of Consultation and 
Coordination with Indian Tribal Governments (Executive Order 13175), 
the proposed FIP asserts that the statutes and executive orders (E.O. 
or Order) are inapplicable in this matter, but does not adequately 
explain why. With respect to Regulatory Planning and Review (Executive 
Order 12866), the proposed FIP stated that it is not a ``significant 
regulatory action'' and is not a rule of general applicability. CPC 
stated that the proposed FIP will have an adverse material effect on 
several sectors of the economy, in particular the cement and copper 
industries, and includes requirements that have statewide, general 
applicability. According to CPC, one of the provisions of Executive 
Order 12866 requires agencies to consider alternatives. CPC stated that 
had the Proposed FIP considered and evaluated alternatives, such as 
deferring controls on CPC during this first planning period, then it 
would be possible to conduct a full and fair evaluation to see if the 
benefits are worth the costs. Without this analysis of alternatives, 
CPC believes the proposed FIP is incomplete. Regarding the Unfunded 
Mandates Reform Act (UMRA), CPC asserted that given the extremely high 
costs to comply with the rule (about $81,000,000 for the Hayden Smelter 
alone), it is likely that the aggregate costs will exceed the 
$100,000,000 threshold in at least one year. Similarly, according to 
CPC, when combined with the BART controls imposed by the FIP on three 
power plants, annual expenditures will exceed the UMRA's threshold ``in 
any one year.'' CPC stated EPA should not circumvent UMRA by 
subdividing a regulatory action, in this case the adoption of a FIP, 
into multiple parts. Regarding Executive Order 13563, CPC asserted that 
EPA must redo the proposed FIP to establish new RPGs, and identify 
controls as necessary to meet the RPGs. As part of that process, 
Executive Order 13563 should be followed so that EPA identifies and 
uses the best, most innovative, and least burdensome tools to achieve 
reasonable progress. CPC asserted that complying with the statutes and 
Executive Orders governing the rulemaking process is good public policy 
and the decision to disregard these principles has led to arbitrary and 
capricious results.
    Response: We do not agree that our proposed FIP is inconsistent 
with the requirements of any applicable Executive Orders (E.O.s) or 
statutes, or that we failed to explain the applicability of these 
requirements. Under E.O. 12866, ``Regulatory Action'' is defined as 
``any substantive action by an agency . . . that promulgates or is 
expected to lead to the promulgation of a final rule or regulation.'' 
\283\ ``Regulation'' or ``rule,'' in turn, is defined as ``an agency 
statement of general applicability and future effect.'' \284\ E.O. 
12866 does not define ``statement of general applicability,'' but this 
term commonly refers to statements that apply to groups or classes, as 
opposed to statements which apply only to named entities. The Phase 3 
partial FIP for Arizona's regional haze program is not a rule of 
general applicability because its requirements are tailored to six 
individually identified facilities. Thus, it is not a ``rule'' or 
``regulation'' within the meaning of E.O. 12866 and this action is not 
a ``regulatory action'' subject to 12866.
---------------------------------------------------------------------------

    \283\ Executive Order 12866, 58 FR 51735 (October 4, 1993), 
section 3(e).
    \284\ Id. section 3(d).
---------------------------------------------------------------------------

    Executive Order 13563, Improving Regulation and Regulatory Review, 
is supplemental to and reaffirms the principles, structures, and 
definitions governing contemporary regulatory review that were 
established in EO 12866. In general, the Order seeks to ensure the 
regulatory process is based on the best available science; allows for 
public participation and an open exchange of ideas; promotes 
predictability and reduces uncertainty; identifies and uses the best, 
most innovative, and least burdensome tools for achieving regulatory 
ends; and takes into account benefits and costs, both quantitative and 
qualitative. However, nothing in the Order shall be construed to impair 
or otherwise affect the authority granted by law to the Agency. As 
explained in our proposal, this action is not an action subject to 
review under Executive Orders 12866 and 13563. In particular, as 
explained above, this action is not a ``regulatory action'' as defined 
under E.O. 12866. Nonetheless, we have followed the principles of E.O. 
13563 in developing this action. We have applied the best available 
science, sought information and feedback from potentially affected 
sources, carefully considered costs and benefits, provided a public 
comment period and two public hearings, and offered flexibility on 
compliance mechanisms (e.g., a BART alternative for TEP Sundt, 
performance standards rather than emissions standards for the copper 
smelters, adjusted averaging times for the Nelson Lime Plant, and the 
option of annual emission limits for the cement plants).
    Under section 202 of UMRA, before promulgating any final rule for 
which a general notice of proposed rulemaking was published, EPA must 
prepare a written statement, including a cost-benefit analysis, if that 
rule includes any ``Federal mandates'' that may result in expenditures 
to state, local, and tribal governments, in the aggregate, or to the 
private sector, of $100 million or more (adjusted for inflation) in any 
one year. As of 2013, the inflation-adjusted threshold was $150 
million.\285\ UMRA defines the term ``Federal private sector mandate'' 
to mean any provision in regulation that would impose an enforceable 
duty upon the private sector. Under UMRA, the term ``regulation'' or 
``rule'' means any rule for which the agency publishes a general notice 
of proposed rulemaking. This final rule is limited to addressing the 
remaining requirements of the RHR for Arizona and does not include 
other regional haze actions occurring in separate rulemakings. We 
estimate that the total annual costs of this rulemaking action will not 
exceed $32,012,772.\286\

[[Page 52475]]

Even if this were added to the annual costs of our prior Phase 1 FIP 
for Arizona ($65 million), the total cost is still less than the 
inflation-adjusted annual threshold. Furthermore, the cost estimates we 
have provided are based on conservative assumptions (i.e., tending to 
overestimate rather than underestimate costs) and do not account for 
the fact that certain controls (e.g., SO2 controls for the 
smelters) may be required under other provisions of the CAA prior to 
the implementation deadlines in this FIP.
---------------------------------------------------------------------------

    \285\ See http://www.cbo.gov/publication/45209.
    \286\ See ``Summary of Costs for Final Rule: Promulgation of Air 
Quality Implementation Plans; Arizona; Regional Haze and Interstate 
Visibility Transport Federal Implementation Plan, EPA-R09-OAR-2013-
0588.'' We do not agree with the commenter that we should use total 
capital costs instead of annualized costs. The UMRA threshold is 
based on annual costs. It is not known in exactly which year capital 
costs associated with controls would be incurred. Thus it is not 
possible to allocate these costs to specific years. Instead, our 
total annual cost estimate includes both annualized capital costs 
and variable annual costs (i.e., operation and maintenance costs).
---------------------------------------------------------------------------

    Comment: One commenter (Representative Gosar) expressed concern 
that the proposed FIP does not adequately assess the potential negative 
economic impacts on small businesses. The commenter noted that EPA 
states in the Federal Register that this proposed rule will not have a 
significant economic impact on a substantial number of small businesses 
as none of the facilities subject to this proposed rule are owned by a 
small entity. While conceding that the six facilities addressed in the 
FIP are technically not small businesses, the commenter asserted that 
the rule will harm small businesses with services that are dependent on 
the facilities. The commenter contended that putting these facilities 
out of business or causing them to increase their rates to pay for the 
new technology mandates will certainly have a trickle-down effect on a 
significant number of small businesses.
    Response: This comment appears to refer to EPA's certification 
under the Regulatory Flexibility Act (RFA) that the FIP will not have a 
significant economic impact on a substantial number of small entities. 
Courts have interpreted the RFA to require a regulatory flexibility 
analysis only when a substantial number of small entities will be 
subject to the requirements of the Agency's action.\287\ None of the 
facilities subject to this rule is owned by a small entity.\288\ Thus, 
no regulatory flexibility analysis is required. Nonetheless, EPA sought 
comments regarding the cost of controls from all entities affected by 
this action and carefully considered all relevant information. None of 
the affected entities, nor any other commenter, has provided any 
evidence that the requirements of today's rule would cause any company 
to go out of business. As described elsewhere, this final action is 
necessary to achieve the objectives of the CAA and RHR based on our 
determination that the visibility improvements justify the costs of 
this rule.
---------------------------------------------------------------------------

    \287\ See, e.g., Mid-Tex Elec. Co-op, Inc. v. FERC, 773 F.2d 
327, 342 (D.C. Cir. 1985).
    \288\ See Regulatory Flexibility Act Screening Analysis for 
Proposed Arizona Regional Haze Federal Implementation Plan (EPA-R09-
OAR-2013-0588).
---------------------------------------------------------------------------

IX. Responses to Other Comments

A. Comments on Preamble Language

    Comment: LNA recommended a number of corrections and clarifications 
to the preamble language in our proposed rule published on February 18, 
2014.
    Response: We acknowledge the corrections and clarifications from 
LNA. While we cannot revise the text of the proposal preamble, we have 
addressed the substantive issues identified by LNA in our responses to 
comments in this final rule.

B. Comments on Rule Language

    Comment: Two commenters (LNA and ASARCO) suggested various 
corrections and clarifications to the proposed rule language.
    Response: We acknowledge the corrections and clarifications 
suggested by LNA and ASARCO. We have addressed the substantive issues 
identified by LNA and ASARCO in our responses to comments in this final 
rule. Where we agree with LNA's and ASARCO's suggestions, we have made 
the appropriate revisions to the regulatory text.

C. Comments on Other Benefits of the Regional Haze Program

    Comment: Two commenters expressed concern about the health effects 
of the pollutants that cause or contribute to regional haze. 
Earthjustice stated that, in addition to improving visibility, the 
regional haze program for Arizona will yield significant public health 
benefits if properly implemented. Earthjustice noted that the same 
pollutants that impair scenic views at national parks and wilderness 
areas also cause significant public health impacts, including the 
following:
     NOX is a precursor to ground level ozone, which 
is associated with respiratory diseases, asthma attacks, and decreased 
lung function.
     NOX also reacts with ammonia, moisture, and 
other compounds to form particulates that can cause and worsen 
respiratory diseases, aggravate heart disease, and lead to premature 
death.
     SO2 increases asthma symptoms, leads to 
increased hospital visits, and can form particulates that aggravate 
respiratory and heart diseases and cause premature death.
     PM can penetrate deep into the lungs and cause a host of 
health problems, such as aggravated asthma and heart attacks.
    Earthjustice believes that Arizona's regional haze program will 
reduce the serious public health toll imposed on Arizonans by the 
State's power plants, copper smelters, and other sources of pollution.
    A private citizen expressed concerns specifically about the health 
effects that are a result of burning coal, which the commenter said is 
a form of energy that leads to some of the worst air pollution compared 
to renewable energy sources such as wind, solar and geothermal power. 
The commenter said that 87 percent of NOX emissions, 94 
percent of SO2 emissions, and 98 percent of mercury 
emissions from the utility sector are from utilities that burn coal. 
The commenter discussed the health effects of these pollutants and 
specifically mentioned the negative health effects of NOX, 
which can cause throat irritation at low levels of exposure and serious 
damage to the tissues in the respiratory tract, fluid buildup in the 
lungs, and death at high levels of exposure.
    Response: We agree that the same pollutants that contribute to haze 
also cause significant public health problems and that to the extent 
that this FIP reduces these pollutants, there are co-benefits for 
public health. However, for purposes of this regional haze action, we 
have not considered these benefits.
    Comment: Earthjustice stated the regional haze program for Arizona 
will provide substantial economic benefits, noting that EPA values the 
regional haze program's health benefits nationally at $8.4 to $9.8 
billion annually. Earthjustice also noted that requiring sources to 
invest in modern pollution controls is a job-creating mechanism in 
itself, as each installation creates short-term construction jobs, as 
well as permanent operations and management positions. Earthjustice 
pointed out that the regional haze program protects national parks and 
wilderness areas, which are of great natural and cultural value, as 
well as serving to sustain local economies. According to Earthjustice, 
in 2012 more than 4.4 million people visited the Grand Canyon. This 
tourism supported more than 6,000 jobs and resulted in more than $453 
million in visitor spending. Another example is that over 1.2 million 
people visited Petrified Forest and Saguaro National Parks in 2012, 
which supported more than 1,000 jobs and resulted in more than $76 
million in visitor spending. Earthjustice added that studies show that 
national park visitors prioritize

[[Page 52476]]

enjoying beautiful scenery when visiting national parks and will visit 
parks less during hazy conditions. Earthjustice concluded that the 
Arizona regional haze program will noticeably improve visibility at 
Arizona's national parks, and thereby increase revenue to the parks and 
surrounding communities.
    Response: We agree that our action today, together with prior 
actions by the State and EPA, will provide economic benefits. However, 
for purposes of this action, we have not calculated these benefits.
    Comment: Earthjustice stated the regional haze program for Arizona 
will provide important environmental benefits because in addition to 
impairing visibility, NOX, SO2, and PM pollution 
harms plants and animals, soil health, and entire ecosystems in the 
following ways:
     NOX and SO2 are the primary causes 
of acid rain, which acidifies lakes and streams and can damage certain 
types of trees and soils. Acid rain also accelerates the decay of 
building materials and paints, including irreplaceable buildings and 
statues that are part of our nation's cultural heritage.
     Nitrogen deposition, caused by wet and dry deposition of 
nitrates derived from NOX emissions, causes well-known 
adverse impacts on ecological systems. At times, nitrogen deposition 
exceeds ``critical loads'' beyond the tolerance of various ecosystems.
     NOX is also a precursor to ozone. Ground-level 
ozone affects plants and ecosystems by interfering with plants' ability 
to produce food and increasing susceptibility to disease and insects. 
Ozone also contributes to wildfires and bark beetle outbreaks in the 
West by depressing plant water levels and growth.
    Response: We agree that NOX, SO2, and PM can 
have negative impacts on plants and ecosystems. However, while we note 
the potential for co-benefits to ecosystem health resulting from our 
action today, we have not taken these potential benefits into account 
in this action.

D. Miscellaneous Comments

    Comment: PCC incorporated by reference its previous comments on 
EPA's proposal for partial approval and partial disapproval of 
Arizona's RH SIP published in a final rule dated July 30, 2013. PCC 
also incorporated the comments that ADEQ made on EPA's proposed action 
on the Arizona RH SIP. ADEQ's comments were in regard to federalism and 
deference that EPA owes to the State's decision-making under the 
regional haze provisions of the CAA, especially as they relate to non-
BART sources of NOX and PCC's facility in particular.
    Response: To the extent that previous comments from PCC and ADEQ 
regarding our Phase 2 SIP action are relevant here, we incorporate by 
reference our responses to those comments in the final SIP rule 
published on July 30, 2013.\289\
---------------------------------------------------------------------------

    \289\ 78 FR 46142.
---------------------------------------------------------------------------

    Comment: One private citizen acknowledged EPA's proposal addressing 
regional haze in Arizona, but submitted comments regarding controlled 
burns that occur in the White Mountain area of North Arizona, and in 
other areas of the country.
    Response: We agree that wildfires also contribute to regional haze. 
However, today's rule does not address wildfires. We will continue to 
work with the State to address emissions from wildfires.
    Comment: One private citizen pointed out that natural resources 
come in two forms, and some are finite, including coal and natural gas. 
The commenter noted that as those run out, we have to come up with 
other sources of energy, so we might as well start thinking about that 
sooner rather than later. The commenter went on to say that he would 
rather pay more for energy or not have technology at all if it is going 
to have a negative effect on health and medical costs. The commenter 
asked that EPA provide information, not only about the science, but 
also the social science of using finite resources.
    Response: This comment is not relevant to this rulemaking.

X. Summary of Final Action

A. Regional Haze

    EPA's is promulgating a FIP to address the remaining portions of 
the Arizona RH SIP that we disapproved on July 30, 2013. This final 
rule establishes limits on NOX and SO2 emissions 
at four BART sources and on NOX emissions at two RP sources. 
We estimate that these emission limits on all six facilities will 
result in total annual emission reductions of about 2,900 tons/year of 
NOX and 29,300 tons/year of SO2 as shown in Table 
12. While the rule also establishes emission limits for PM10 
on the four BART facilities, these limits are based on existing 
controls.

                Table 12--Emissions Reductions by Source
------------------------------------------------------------------------
                                                   Emission reductions
                                   Control             (tons/year)
            Source                technology   -------------------------
                                                    NOX          SO2
------------------------------------------------------------------------
Sundt Unit 4 (BART)..........  SNCR and DSI...          393        1,502
Nelson Lime Plant Kilns 1 and  SNCR and Lower           983          925
 2.                             sulfur fuel.
Hayden Smelter (multiple       Amine scrubber   ...........       20,036
 units).                        for secondary
                                capture.
Miami Smelter (multiple        Improve primary  ...........        6,845
 units).                        and new
                                secondary
                                capture
                                systems,
                                additional
                                controls as
                                needed.
PCC Clarkdale Plant Kiln 4...  SNCR...........          810  ...........
CPC Rillito Plant Kiln 4.....  SNCR...........          729  ...........
                                               -------------------------
Total........................  ...............        2,915       29,308
------------------------------------------------------------------------

    The estimated costs associated with the NOX and 
SO2 emission reductions are shown in Tables 13 and 14 for 
each of the six sources, and are based on the control technology 
corresponding with the final emission limits.

[[Page 52477]]



                                   Table 13--Summary of Costs for NOX Controls
----------------------------------------------------------------------------------------------------------------
                                                    Annualized                         Total           Cost-
             Source                Capital cost    capital cost   Annual O&M  ($/   annualized     effectiveness
                                        ($)          ($/year)          year)      cost  ($/year)      ($/ton)
----------------------------------------------------------------------------------------------------------------
TEP Sundt Unit 4................      $3,079,089        $290,644        $975,124      $1,265,768          $3,222
Nelson Lime Plant Kiln 1........         450,000         42, 477         358,459         400,936             817
Nelson Lime Plant Kiln 2........         450,000          42,477         354,981         397,458             807
Phoenix Cement Kiln 4...........       1,500,000         140,000         800,000         940,000           1,162
CalPortland Cement Kiln 4.......       1,300,000         128,000       1,220,000       1,350,000           1,850
----------------------------------------------------------------------------------------------------------------


                                   Table 14--Summary of Costs for SO2 Controls
----------------------------------------------------------------------------------------------------------------
                                                    Annualized                         Total           Cost-
             Source                Capital cost    capital cost   Annual O&M  ($/   annualized     effectiveness
                                        ($)          ($/year)          year)      cost  ($/year)      ($/ton)
----------------------------------------------------------------------------------------------------------------
TEP Sundt Unit 4................      $3,250,000        $306,777      $2,482,107      $2,788,884          $1,857
Nelson Lime Plant Kiln 1........  ..............  ..............         313,096         313,096             856
Nelson Lime Plant Kiln 2........  ..............  ..............         458,179         458,179             819
Hayden Smelter..................      85,000,000       8,023,399       9,300,000      17,323,399             865
Miami Smelter...................      47,850,000       4,516,701       2,258,351       6,775,052             990
----------------------------------------------------------------------------------------------------------------

    Based on air quality modeling, the emission reductions should 
result in improved visibility at 17 Class I areas in four states, 
including Arizona. The maximum and cumulative visibility benefits 
(i.e., the sum of benefits over affected areas) are shown in Table 15 
for each source and type of control.

                                    Table 15--Summary of Visibility Benefits
----------------------------------------------------------------------------------------------------------------
                                                    Maximum       Cumulative
                                                  visibility      visibility
                    Source                         benefit,         benefit            Control technology
                                                  (deciviews)     (deciviews)
----------------------------------------------------------------------------------------------------------------
Sundt Unit 4..................................            0.49             1.4  SNCR and DSI.
Sundt Unit 4: BART Alternative................            1.06             2.7  Natural gas.
Nelson Lime Plant Kilns 1 and 2 (NOX).........            0.58            0.85  SNCR.
Nelson Lime Plant Kilns 1 and 2 (SO2).........            0.10            0.29  Lower sulfur fuel.
Hayden Smelter (multiple units)...............            1.44            10.2  Amine scrubber for secondary
                                                                                 capture.
Miami Smelter (multiple units)................            0.41             1.7  Improve primary and new
                                                                                 secondary capture systems,
                                                                                 additional controls as needed.
PCC Clarkdale Plant Kiln 4....................       0.52-1.85        1.7-3.0.  SNCR
CPC Rillito Plant Kiln 4......................            0.18             0.6  SNCR.
----------------------------------------------------------------------------------------------------------------

    This final rule, along with the previously approved portions of the 
Arizona RH SIP and a previously finalized FIP, constitute Arizona's 
regional haze implementation plan for the first planning period that 
ends in 2018.

B. Interstate Transport

    We also are finalizing our determination that the interstate 
transport visibility requirement of section 110(a)(2)(D)(i)(II) for the 
1997 8-hour ozone, 1997 PM2.5, and 2006 PM2.5 
NAAQS is satisfied by a combination of measures in the Arizona RH SIP 
and FIP. These measures are in the approved portions of the Arizona RH 
SIP and in our two FIP actions, this final rule and our final rule on 
December 5, 2012.

XI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action finalizes a Regional Haze FIP for six individually 
named facilities in Arizona. This action is not a rule of general 
applicability and therefore not a ``regulatory action'' under the terms 
of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993). This type 
of action is exempt from review under EO 12866 and is therefore not 
subject to review under Executive Order 13563 (76 FR 3821, January 21, 
2011).

B. Paperwork Reduction Act

    This action does not impose an information collection burden under 
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
Burden is defined at 5 CFR 1320.3(b). Because this action will finalize 
a Regional Haze FIP for only six facilities in Arizona, the Paperwork 
Reduction Act does not apply. See 5 CFR 1320.3(c). An agency may not 
conduct or sponsor, and a person is not required to respond to a 
collection of information unless it displays a currently valid Office 
of Management and Budget (OMB) control number. The OMB control numbers 
for our regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies

[[Page 52478]]

that the rule will not have a significant economic impact on a 
substantial number of small entities. Small entities include small 
businesses, small organizations, and small governmental jurisdictions. 
For purposes of assessing the impacts of this rule on small entities, 
small entity is defined as: (1) A small business as defined by the 
Small Business Administration's (SBA) regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for 
profit enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of this action on small 
entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. This final 
rule will not impose any requirements on small entities. None of the 
facilities subject to this rule is owned by a small entity.\290\
---------------------------------------------------------------------------

    \290\ See Regulatory Flexibility Act Screening Analysis for 
Proposed Arizona Regional Haze Federal Implementation Plan (EPA-R09-
OAR-2013-0588).
---------------------------------------------------------------------------

D. Unfunded Mandates Reform Act (UMRA)

    Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, 
establishes requirements for Federal agencies to assess the effects of 
their regulatory actions on State, local, and Tribal governments and 
the private sector. Under section 202 of UMRA, EPA generally must 
prepare a written statement, including a cost-benefit analysis, for 
proposed and final rules with ``Federal mandates'' that may result in 
expenditures to State, local, and Tribal governments, in the aggregate, 
or to the private sector, of $100 million or more (adjusted for 
inflation) in any one year. Before promulgating an EPA rule for which a 
written statement is needed, section 205 of UMRA generally requires EPA 
to identify and consider a reasonable number of regulatory alternatives 
and to adopt the least costly, most cost-effective, or least burdensome 
alternative that achieves the objectives of the rule. The provisions of 
section 205 of UMRA do not apply when they are inconsistent with 
applicable law. Moreover, section 205 of UMRA allows EPA to adopt an 
alternative other than the least costly, most cost-effective, or least 
burdensome alternative if the Administrator publishes with the final 
rule an explanation why that alternative was not adopted. Before EPA 
establishes any regulatory requirements that may significantly or 
uniquely affect small governments, including Tribal governments, it 
must have developed under section 203 of UMRA a small government agency 
plan. The plan must provide for notifying potentially affected small 
governments, enabling officials of affected small governments to have 
meaningful and timely input in the development of EPA regulatory 
proposals with significant Federal intergovernmental mandates, and 
informing, educating, and advising small governments on compliance with 
the regulatory requirements.
    Under Title II of UMRA, EPA has determined that this rule does not 
contain a Federal mandate that may result in expenditures that exceed 
the inflation-adjusted UMRA threshold of $100 million (in 1996 dollars) 
by State, local, or Tribal governments or the private sector in any 1 
year. In addition, this rule does not contain a significant Federal 
intergovernmental mandate as described by section 203 of UMRA nor does 
it contain any regulatory requirements that might significantly or 
uniquely affect small governments.

E. Executive Order 13132: Federalism

    This rule will not have substantial direct effects on the states, 
on the relationship between the national government and the states, or 
on the distribution of power and responsibilities among the various 
levels of government, as specified in Executive Order 13132. In this 
action, EPA is fulfilling our statutory duty under CAA Section 110(c) 
to promulgate a partial Regional Haze FIP. Thus, Executive Order 13132 
does not apply to this action.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Subject to the Executive Order 13175 (65 FR 67249, November 9, 
2000) EPA may not issue a regulation that has tribal implications, that 
imposes substantial direct compliance costs, and that is not required 
by statute, unless the Federal government provides the funds necessary 
to pay the direct compliance costs incurred by tribal governments, or 
EPA consults with tribal officials early in the process of developing 
the proposed regulation and develops a tribal summary impact statement.
    EPA has concluded that this action will have tribal implications, 
because it will impose substantial direct compliance costs on tribal 
governments and the Federal government will not provide the funds 
necessary to pay those costs. PCC is a division of Salt River Pima 
Maricopa Indian Community (SRPMIC or the Community) and profits from 
the Phoenix Cement Clarkdale Plant are used to provide government 
services to SRPMIC's members. Therefore, EPA is providing the following 
tribal summary impact statement as required by section 5(b).
    EPA consulted with tribal officials early in the process of 
developing this regulation so that they could have meaningful and 
timely input into its development. In November 2012, we shared our 
initial analyses with SRPMIC and PCC to ensure that the tribe had an 
early opportunity to provide feedback on potential controls at the 
Clarkdale Plant. PCC submitted comments on this initial analysis as 
part of the rulemaking on the Arizona Regional Haze SIP and we revised 
our initial analysis based on these comments. On November 6, 2013, the 
EPA Region 9 Regional Administrator met with the President and other 
representatives of SRPMIC to discuss the potential impacts of the FIP 
on SRPMIC. Following this meeting, staff from EPA, SPRMIC and PCC 
shared further information regarding the Plant and potential impacts of 
the FIP on SRPMIC.\291\
---------------------------------------------------------------------------

    \291\ See Memorandum to Docket: Summary of Communications and 
Consultation between EPA, PCC and SRPMIC (January 27, 2014).
---------------------------------------------------------------------------

    In our February 18, 2014 proposal, EPA proposed to require 
installation of SNCR at Kiln 4 at the Clarkdale Plant by December 31, 
2018 and sought comment on the possibility of establishing an annual 
cap on NOX emissions from Kiln 4 in lieu of a lb/ton 
emission limit. We explained that an annual cap would allow SRPMIC to 
delay installation of controls until the Plant's production returns to 
pre-recession levels and would thus help to address the Community's 
concerns about the budgetary impacts of control requirements.
    In its comments on the proposal, PCC expressed support for the cap 
``as long as the final FIP expressly provides that it would be at PCC's 
election whether to meet this cap effective December 31, 2018 or 
instead meet the applicable lbs/ton limit effective December 31, 
2018.'' \292\ EPA subsequently requested clarification of this request 
from PCC.\293\ On May 22, 2014, SRPMIC submitted a letter to EPA 
describing a proposal that would enable PCC to elect either emission 
limit and subsequently switch from one to other every five years. In 
response, EPA suggested that, if SRPMIC wished to change the emission

[[Page 52479]]

limit after 2018, it could seek to do so through a SIP revision.\294\ 
Consistent with this approach, in this final rule SRPMIC must elect 
which limit (i.e. either the lb/ton limit or the ton/year limit) by 
June 30, 2018. After that point, SRPMIC may seek to change the limit 
through a revision to the Arizona SIP.
---------------------------------------------------------------------------

    \292\ PCC Comment Letter at 2.
    \293\ See Memo to Final--Communications with PCC and SRPMIC.
    \294\ Email from Colleen McKaughan to Verle Martz (May 30, 
2014).
---------------------------------------------------------------------------

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045: Protection of Children from Environmental 
Health Risks and Safety Risks (62 FR 19885, April 23, 1997), applies to 
any rule that: (1) Is determined to be economically significant as 
defined under Executive Order 12866; and (2) concerns an environmental 
health or safety risk that we have reason to believe may have a 
disproportionate effect on children. EPA interprets EO 13045 as 
applying only to those regulatory actions that concern health or safety 
risks, such that the analysis required under section 5-501 of the EO 
has the potential to influence the regulation. This action is not 
subject to EO 13045 because it implements specific standards 
established by Congress in statutes. Also, because this action only 
applies to six sources and is not a rule of general applicability, it 
is not economically significant as defined under Executive Order 12866, 
and the rule also does not have a disproportionate effect on children. 
However, to the extent this action will limit emissions of 
NOX, SO2, and PM10, the rule will have 
a beneficial effect on children's health by reducing air pollution that 
causes or exacerbates childhood asthma and other respiratory issues.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113, 12(10) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities unless to do so would be inconsistent with 
applicable law or otherwise impractical. VCS are technical standards 
(e.g., materials specifications, test methods, sampling procedures and 
business practices) that are developed or adopted by the VCS bodies. 
The NTTAA directs EPA to provide Congress, through annual reports to 
OMB, with explanations when the Agency decides not to use available and 
applicable VCS. This action does not require the public to perform 
activities conducive to the use of VCS.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    We have determined that this rule will not have disproportionately 
high and adverse human health or environmental effects on minority or 
low-income populations because it increases the level of environmental 
protection for all affected populations without having any 
disproportionately high and adverse human health or environmental 
effects on any population, including any minority or low-income 
population. This rule limits emissions of NOX, 
PM10, and SO2 from six facilities in Arizona.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. Section 804 exempts from section 801 the following types 
of rules: (1) Rules of particular applicability; (2) rules relating to 
agency management or personnel; and (3) rules of agency organization, 
procedure, or practice that do not substantially affect the rights or 
obligations of non-agency parties. 5 U.S.C. 804(3). EPA is not required 
to submit a rule report regarding this action under section 801 because 
this is a rule of particular applicability that only applies to six 
named facilities.

L. Petitions for Judicial Review

    Under section 307(b)(1) of the Clean Air Act, petitions for 
judicial review of this action must be filed in the United States Court 
of Appeals for the appropriate circuit by November 3, 2014. Filing a 
petition for reconsideration by the Administrator of this final rule 
does not affect the finality of this rule for the purposes of judicial 
review nor does it extend the time within which a petition for judicial 
review may be filed, and shall not postpone the effectiveness of such 
rule or action. This action may not be challenged later in proceedings 
to enforce its requirements. See CAA section 307(b)(2).

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Incorporation by 
reference, Intergovernmental relations, Nitrogen oxides, Sulfur 
dioxide, Particulate matter, Reporting and recordkeeping requirements, 
Visibility, Volatile organic compounds.

    Dated: June 27, 2014.
Gina McCarthy,
Administrator.

    For the reasons stated in the preamble, part 52, chapter I, title 
40 of the Code of Federal Regulations is amended as follows:

PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS

0
1. The authority citation for part 52 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.

Subpart D--Arizona

0
2. Amend Sec.  52.145 by adding paragraphs (i), (j), (k), (l), and (m) 
and appendices (A) and (B) to read as follow:


Sec.  52.145  Visibility protection.

* * * * *
    (i) Source-specific federal implementation plan for regional haze 
at Nelson Lime Plant--(1) Applicability. This paragraph (i) applies to 
the owner/operator of the lime kilns designated as Kiln 1 and Kiln 2 at 
the Nelson Lime Plant located in Yavapai County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (i)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (i):

[[Page 52480]]

    Ammonia injection shall include any of the following: Anhydrous 
ammonia, aqueous ammonia, or urea injection.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of NOX emissions, SO2 emissions, diluent, 
and stack gas volumetric flow rate.
    Kiln means either of the kilns identified in paragraph (i)(1) of 
this section.
    Kiln 1 means lime kiln 1, as identified in paragraph (i)(1) of this 
section.
    Kiln 2 means lime kiln 2, as identified in paragraph (i)(1) of this 
section.
    Kiln operating day means a 24-hour period between 12 midnight and 
the following midnight during which there is operation of Kiln 1, Kiln 
2, or both kilns at any time.
    Kiln operation means any period when any raw materials are fed into 
the Kiln or any period when any combustion is occurring or fuel is 
being fired in the Kiln.
    Lime product means the product of the lime-kiln calcination 
process, including calcitic lime, dolomitic lime, and dead-burned 
dolomite.
    NOX means oxides of nitrogen.
    Owner/operator means any person who owns or who operates, controls, 
or supervises a kiln identified in paragraph (i)(1) of this section.
    SO2 means sulfur dioxide.
    (3) Emission limitations. (i) The owner/operator of the kilns 
identified in paragraph (i)(1) of this section shall not emit or cause 
to be emitted pollutants in excess of the following limitations in 
pounds of pollutant per ton of lime product (lb/ton), from any kiln. 
Each emission limit shall be based on a 12-month rolling basis.

 
------------------------------------------------------------------------
                       Kiln ID
----------------------------------------------------- Pollutant emission
               NOX                        SO2                limit
------------------------------------------------------------------------
Kiln 1..........................  3.80..............  9.32
Kiln 2..........................  2.61..............  9.73
------------------------------------------------------------------------

    (ii) The owner/operator of the kilns identified in paragraph (i)(1) 
of this section shall not emit or cause to be emitted pollutants in 
excess of 3.27 tons of NOX per day and 10.10 tons of 
SO2 per day, combined from both kilns, based on a rolling 
30-kiln-operating-day basis.
    (iii) In addition, if the owner/operator installs an ammonia 
injection system to comply with the limits specified in paragraph 
(i)(3) of this section, the owner/operator shall also comply with the 
control technology demonstration requirements set forth in paragraph 
(i)(5) of this section.
    (4) Compliance dates. (i) The owner/operator of each kiln shall 
comply with the NOX emission limitations and other 
NOX-related requirements of this paragraph (i) no later than 
September 4, 2017.
    (ii) The owner/operator of each kiln shall comply with the 
SO2 emission limitations and other SO2-related 
requirements of this paragraph (i) no later than March 3, 2016.
    (5) Control technology demonstration requirements. If the owner/
operator of a kiln installs an ammonia injection system to comply with 
the limits specified in paragraph (i)(3) of this section, the owner/
operator must comply with the following requirements for implementing 
combustion and process optimization measures.
    (i) Design report. Prior to commencing construction of an ammonia 
injection system used to comply with the limits specified in paragraph 
(i)(3) of this section, the owner/operator shall submit to EPA for 
review a Design Report as described in Appendix B of this section.
    (ii) Optimization protocol. Prior to commencement of the 
Optimization Program, the owner/operator shall submit to EPA for review 
an Optimization Protocol which shall include the procedures, as 
described in Appendix B of this section, to be used during the 
Optimization Program for the purpose of adjusting operating parameters 
and minimizing emissions.
    (iii) Optimization period. Following EPA review of the Optimization 
Protocol, the owner/operator shall operate the ammonia injection system 
and collect data in accordance with the Optimization Protocol. The 
owner/operator shall operate the ammonia injection system in such a 
manner for no longer than 180 kiln operating days, or the duration 
specified in the Optimization Protocol, whichever is longer in 
duration.
    (iv) Optimization report. Within 60 calendar days following the 
conclusion of the Optimization Program, the owner/operator shall submit 
to EPA for review an Optimization Report, as described in Appendix B of 
this section, demonstrating conformance with the Optimization Protocol, 
and establishing optimized operating parameters for the ammonia 
injection system as well as other facility processes.
    (v) Demonstration period. Following EPA review of the Optimization 
Report, the owner/operator shall operate the ammonia injection system 
consistent with the optimized operations of the facility and ammonia 
injection system specified in the Optimization Report. The owner/
operator shall operate the ammonia injection system in such a manner 
for a period of 360 kiln operating days, or the duration specified in 
the Optimization Report, whichever is longer. The Demonstration Period 
may be shortened or lengthened as provided for in appendix B of this 
section.
    (vi) Demonstration report. Within 60 calendar days following the 
conclusion of the Demonstration Program, the owner/operator shall 
submit a Demonstration Report, as described in appendix B of this 
section, which identifies a proposed rolling 12-month emission limit 
for NOX. In a subsequent regulatory action, EPA may seek to 
lower the NOX emission limits in paragraph (i)(3) of this 
section in view of, among other things, the information contained in 
the Demonstration Report. The proposed rolling 12-month emission limit 
shall be calculated in accordance with the following formula:

X = [mu] + 1.65[sigma]

Where:

X = Rolling 12-month emission limit, in pounds of NOX per 
ton of lime product;
[mu] = Arithmetic mean of all of the rolling 12-month emission 
rates;
[sigma] = Standard deviation of all of the rolling 12-month emission 
rates, as calculated in the following manner:
[GRAPHIC] [TIFF OMITTED] TR03SE14.001

Where:

N = The total number of rolling 12-month emission rates;
xi = Each rolling 12-month emission rate;
x = The mean value of all of the rolling 12-month emission rates.

    (6) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance dates specified in paragraph 
(i)(4) of this section, the owner/operator of kilns 1 and 2 shall 
maintain, calibrate, and operate a CEMS, in full compliance with the 
requirements found at 40 CFR 60.13 and 40 CFR part 60, appendices B and 
F, to accurately measure diluent, stack gas volumetric flow rate, and 
concentration by volume of NOX and SO2 emissions 
into the atmosphere from kilns 1 and 2. The CEMS shall be used by the 
owner/operator to determine compliance with the emission limitations in 
paragraph (i)(3) of this section, in combination with data on actual 
lime production. The owner/

[[Page 52481]]

operator must operate the monitoring system and collect data at all 
required intervals at all times that an affected kiln is operating, 
except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required monitoring 
system quality assurance or quality control activities (including, as 
applicable, calibration checks and required zero and span adjustments).
    (ii) Ammonia consumption monitoring. Upon and after the completion 
of installation of ammonia injection on a kiln, the owner or operator 
shall install, and thereafter maintain and operate, instrumentation to 
continuously monitor and record levels of ammonia consumption for that 
kiln.
    (iii) Compliance determination for lb per ton NOX limit. Compliance 
with the NOX emission limits described in paragraph 
(i)(3)(i) of this section shall be determined based on a rolling 12-
month basis. The 12-month rolling NOX emission rate for each 
kiln shall be calculated within 30 days following the end of each 
calendar month in accordance with the following procedure: Step one, 
sum the hourly pounds of NOX emitted for the month just 
completed and the eleven (11) months preceding the month just completed 
to calculate the total pounds of NOX emitted over the most 
recent twelve (12) month period for that kiln; Step two, sum the total 
lime product, in tons, produced during the month just completed and the 
eleven (11) months preceding the month just completed to calculate the 
total lime product produced over the most recent twelve (12) month 
period for that kiln; Step three, divide the total amount of 
NOX calculated from Step one by the total lime product 
calculated from Step two to calculate the 12-month rolling 
NOX emission rate for that kiln. Each 12-month rolling 
NOX emission rate shall include all emissions and all lime 
product that occur during all periods within the 12-month period, 
including emissions from startup, shutdown, and malfunction.
    (iv) Compliance determination for lb per ton SO2 limit. Compliance 
with the SO2 emission limits described in paragraph 
(i)(3)(i) of this section shall be determined based on a rolling 12-
month basis. The 12-month rolling SO2 emission rate for each 
kiln shall be calculated within 30 days following the end of each 
calendar month in accordance with the following procedure: Step one, 
sum the hourly pounds of SO2 emitted for the month just 
completed and the eleven (11) months preceding the month just completed 
to calculate the total pounds of SO2 emitted over the most 
recent twelve (12) month period for that kiln; Step two, sum the total 
lime product, in tons, produced during the month just completed and the 
eleven (11) months preceding the month just completed to calculate the 
total lime product produced over the most recent twelve (12) month 
period for that kiln; Step three, divide the total amount of 
SO2 calculated from Step one by the total lime product 
calculated from Step two to calculate the 12-month rolling 
SO2 emission rate for that kiln. Each 12-month rolling 
SO2 emission rate shall include all emissions and all lime 
product that occur during all periods within the 12-month period, 
including emissions from startup, shutdown, and malfunction.
    (v) Compliance determination for ton per day NOX limit. Compliance 
with the NOX emission limit described in paragraph 
(i)(3)(ii) of this section shall be determined based on a rolling 30-
kiln-operating-day basis. The rolling 30-kiln operating day 
NOX emission rate for the kilns shall be calculated for each 
kiln operating day in accordance with the following procedure: Step 
one, sum the hourly pounds of NOX emitted from both kilns 
for the current kiln operating day and the preceding twenty-nine (29) 
kiln-operating-day period for both kilns; Step two, divide the total 
pounds of NOX calculated from Step one by two thousand 
(2,000) to calculate the total tons of NOX; Step three, 
divide the total tons of NOX calculated from Step two by 
thirty (30) to calculate the rolling 30-kiln operating day 
NOX emission rate for both kilns. Each rolling 30-kiln 
operating day NOX emission rate shall include all emissions 
that occur from both kilns during all periods within any kiln operating 
day, including emissions from startup, shutdown, and malfunction.
    (vi) Compliance determination for ton per day SO2 limit. Compliance 
with the SO2 emission limit described in paragraph 
(i)(3)(ii) of this section shall be determined based on a rolling 30-
kiln-operating-day basis. The rolling 30-kiln operating day 
SO2 emission rate for the kilns shall be calculated for each 
kiln operating day in accordance with the following procedure: Step 
one, sum the hourly pounds of SO2 emitted from both kilns 
for the current kiln operating day and the preceding twenty-nine (29) 
kiln operating days, to calculate the total pounds of SO2 
emitted over the most recent thirty (30) kiln operating day period for 
both kilns; Step two, divide the total pounds of SO2 
calculated from Step one by two thousand (2,000) to calculate the total 
tons of SO2; Step three, divide the total tons of 
SO2 calculated from Step two by thirty (30) to calculate the 
rolling 30-kiln operating day SO2 emission rate for both 
kilns. Each rolling 30-kiln operating day SO2 emission rate 
shall include all emissions that occur from both kilns during all 
periods within any kiln operating day, including emissions from 
startup, shutdown, and malfunction.
    (7) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) All records of lime production.
    (iii) Monthly rolling 12-month emission rates of NOX and 
SO2, calculated in accordance with paragraphs (i)(6)(iii) 
and (iv) of this section.
    (iv) Daily rolling 30-kiln operating day emission rates of 
NOX and SO2 calculated in accordance with 
paragraphs (i)(6)(v) and (vi) of this section.
    (v) Records of quality assurance and quality control activities for 
emissions measuring systems including, but not limited to, any records 
specified by 40 CFR part 60, appendix F, Procedure 1, as well as the 
following:
    (A) The occurrence and duration of any startup, shutdown, or 
malfunction, performance testing, evaluations, calibrations, checks, 
adjustments maintenance, duration of any periods during which a CEMS or 
COMS is inoperative, and corresponding emission measurements.
    (B) Date, place, and time of measurement or monitoring equipment 
maintenance activity;
    (C) Operating conditions at the time of measurement or monitoring 
equipment maintenance activity;
    (D) Date, place, name of company or entity that performed the 
measurement or monitoring equipment maintenance activity and the 
methods used; and
    (E) Results of the measurement or monitoring equipment maintenance.
    (vi) Records of ammonia consumption, as recorded by the 
instrumentation required in paragraph (i)(6)(ii) of this section.
    (vii) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, CEMS, and lime 
production measurement devices.
    (viii) All other records specified by 40 CFR part 60, appendix F, 
Procedure 1.
    (8) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director,

[[Page 52482]]

Enforcement Division (Mail Code ENF-2-1), U.S. Environmental Protection 
Agency, Region 9, 75 Hawthorne Street, San Francisco, California 94105-
3901. All reports required under this section shall be submitted within 
30 days after the applicable compliance date(s) in paragraph (i)(4) of 
this section and at least semiannually thereafter, within 30 days after 
the end of a semiannual period. The owner/operator may submit reports 
more frequently than semiannually for the purposes of synchronizing 
reports required under this section with other reporting requirements, 
such as the title V monitoring report required by 40 CFR 
70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual 
period exceed six months.
    (i) The owner/operator shall submit a report that lists the daily 
rolling 30-kiln operating day emission rates for NOX and 
SO2, calculated in accordance with paragraphs (i)(6)(iii) 
and (iv) of this section.
    (ii) The owner/operator shall submit a report that lists the 
monthly rolling 12-month emission rates for NOX and 
SO2, calculated in accordance with paragraphs (i)(6)(v) and 
(vi) of this section.
    (iii) The owner/operator shall submit excess emissions reports for 
NOX and SO2 limits. Excess emissions means 
emissions that exceed any of the emissions limits specified in 
paragraph (i)(3) of this section. The reports shall include the 
magnitude, date(s), and duration of each period of excess emissions; 
specific identification of each period of excess emissions that occurs 
during startups, shutdowns, and malfunctions of the kiln; the nature 
and cause of any malfunction (if known); and the corrective action 
taken or preventative measures adopted.
    (iv) The owner/operator shall submit a summary of CEMS operation, 
to include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (v) The owner/operator shall submit results of all CEMS performance 
tests required by 40 CFR part 60, appendix F, Procedure 1 (Relative 
Accuracy Test Audits, Relative Accuracy Audits, and Cylinder Gas 
Audits).
    (vi) When no excess emissions have occurred or the CEMS has not 
been inoperative, repaired, or adjusted during the reporting period, 
the owner/operator shall state such information in the semiannual 
report.
    (9) Notifications. All notifications required under this section 
shall be submitted by the owner/operator to the Director, Enforcement 
Division (Mail Code ENF-2-1), U.S. Environmental Protection Agency, 
Region 9, 75 Hawthorne Street, San Francisco, California 94105-3901.
    (i) The owner/operator shall submit notification of commencement of 
construction of any equipment which is being constructed to comply with 
the NOX emission limits in paragraph (i)(3) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (10) Equipment operations. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner/operator shall, to the 
extent practicable, maintain and operate the kilns, including 
associated air pollution control equipment, in a manner consistent with 
good air pollution control practices for minimizing emissions. 
Pollution control equipment shall be designed and capable of operating 
properly to minimize emissions during all expected operating 
conditions. Determination of whether acceptable operating and 
maintenance procedures are being used will be based on information 
available to the Regional Administrator, which may include, but is not 
limited to, monitoring results, review of operating and maintenance 
procedures, and inspection of the kilns.
    (ii) After completion of installation of ammonia injection on a 
kiln, the owner/operator shall inject sufficient ammonia to achieve 
compliance with the NOX emission limits from paragraph 
(i)(3) of this section for that kiln while preventing excessive ammonia 
emissions.
    (11) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the kiln would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed can be used to establish whether or not the owner/operator 
has violated or is in violation of any standard or applicable emission 
limit in the plan.
    (j) Source-specific federal implementation plan for regional haze 
at H. Wilson Sundt Generating Station--(1) Applicability. This 
paragraph (j) applies to the owner/operator of the electricity 
generating unit (EGU) designated as Unit I4 at the H. Wilson Sundt 
Generating Station located in Tucson, Pima County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (j)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (j):
    Ammonia injection shall include any of the following: Anhydrous 
ammonia, aqueous ammonia, or urea injection.
    Boiler operating day means a 24-hour period between 12 midnight and 
the following midnight during which any fuel is combusted at any time 
in the unit.
    Continuous emission monitoring system or CEMS means the equipment 
required by 40 CFR part 75 and this paragraph (j).
    MMBtu means one million British thermal units.
    Natural gas means a naturally occurring fluid mixture of 
hydrocarbons as defined in 40 CFR 72.2.
    NOX means oxides of nitrogen.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the EGU identified in paragraph (j)(1) of this section.PM 
means total filterable particulate matter.
    PM10 means total particulate matter less than 10 microns in 
diameter.
    SO2 means sulfur dioxide.
    Unit means the EGU identified paragraph (j)(1) of this section.
    (3) Emission limitations. The owner/operator of the unit shall not 
emit or cause to be emitted pollutants in excess of the following 
limitations, in pounds of pollutant per million British thermal units 
(lb/MMBtu), from the subject unit.

------------------------------------------------------------------------
                                                             Pollutant
                        Pollutant                         emission limit
------------------------------------------------------------------------
NOX.....................................................           0.36
PM......................................................           0.030
SO2.....................................................           0.23
------------------------------------------------------------------------

    (4) Alternative emission limitations. The owner/operator of the 
unit may choose to comply with the following limitations in lieu of the 
emission limitations listed in paragraph (j)(3) of this section.
    (i) The owner/operator of the unit shall combust only natural gas 
or natural gas combined with landfill gas in the subject unit.
    (ii) The owner/operator of the unit shall not emit or cause to be 
emitted pollutants in excess of the following limitations, in pounds of 
pollutant per million British thermal units (lb/MMBtu), from the 
subject unit.

[[Page 52483]]



------------------------------------------------------------------------
                                                             Pollutant
                        Pollutant                         emission limit
------------------------------------------------------------------------
NOX.....................................................           0.25
PM10....................................................           0.010
SO2.....................................................           0.057
------------------------------------------------------------------------

    (iii) If the results of the initial performance test conducted in 
accordance with paragraph (j)(8)(iv) of this section show 
PM10 emissions greater than the limit in paragraph 
(j)(4)(ii) of this section, the owner/operator may elect to comply with 
an emission limit equal to the result of the initial performance test, 
in lieu of the PM10 emission limit in paragraph (j)(4)(ii).
    (5) Compliance dates. (i) The owner/operator of the unit subject to 
this paragraph (j)(5) shall comply with the NOX and 
SO2 emission limitations of paragraph (j)(3) of this section 
no later than September 4, 2017.
    (ii) The owner/operator of the unit subject to this paragraph 
(j)(5) shall comply with the PM emission limitation of paragraph (j)(3) 
of this section no later than April 16, 2015.
    (6) Alternative compliance dates. If the owner/operator chooses to 
comply with paragraph (j)(4) of this section in lieu of paragraph 
(j)(3) of this section, the owner/operator of the unit shall comply 
with the NOX, SO2, and PM10 emission 
limitations of paragraph (j)(4) of this section no later than December 
31, 2017.
    (7) Compliance determination--(i) Continuous emission monitoring 
system. (A) At all times after the compliance date specified in 
paragraph (j)(5)(i) of this section, the owner/operator of the unit 
shall maintain, calibrate, and operate CEMS, in full compliance with 
the requirements found at 40 CFR part 75, to accurately measure 
SO2, NOX, diluent, and stack gas volumetric flow 
rate from the unit. All valid CEMS hourly data shall be used to 
determine compliance with the emission limitations for NOX 
and SO2 in paragraph (j)(3) of this section. When the CEMS 
is out-of-control as defined by 40 CFR part 75, the CEMS data shall be 
treated as missing data and not used to calculate the emission average. 
Each required CEMS must obtain valid data for at least 90 percent of 
the unit operating hours, on an annual basis.
    (B) The owner/operator of the unit shall comply with the quality 
assurance procedures for CEMS found in 40 CFR part 75. In addition to 
the requirements in part 75 of this chapter, relative accuracy test 
audits shall be calculated for both the NOX and 
SO2 pounds per hour measurement and the heat input 
measurement. The CEMS monitoring data shall not be bias adjusted. 
Calculations of relative accuracy for lb/hour of NOX, 
SO2, and heat input shall be performed each time the CEMS 
undergo relative accuracy testing.
    (ii) Ammonia consumption monitoring. Upon and after the completion 
of installation of ammonia injection on the unit, the owner/operator 
shall install, and thereafter maintain and operate, instrumentation to 
continuously monitor and record levels of ammonia consumption for that 
unit.
    (iii) Compliance determination for NOX. Compliance with the 
NOX emission limit described in paragraph (j)(3) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The 30-boiler-operating-day rolling NOX emission rate 
for the unit shall be calculated for each boiler operating day in 
accordance with the following procedure: Step one, sum the hourly 
pounds of NOX emitted for the current boiler operating day 
and the preceding twenty-nine (29) boiler operating days to calculate 
the total pounds of NOX emitted over the most recent thirty 
(30) boiler-operating-day period for that unit; Step two, sum the total 
heat input, in MMBtu, during the current boiler operating day and the 
preceding twenty-nine (29) boiler operating days to calculate the total 
heat input over the most recent thirty (30) boiler-operating-day period 
for that unit; Step three, divide the total amount of NOX 
calculated from Step one by the total heat input calculated from Step 
two to calculate the rolling 30-boiler-operating-day NOX 
emission rate, in pounds per MMBtu for that unit. Each rolling 30-
boiler-operating-day NOX emission rate shall include all 
emissions and all heat input that occur during all periods within any 
boiler operating day, including emissions from startup, shutdown, and 
malfunction. If a valid NOX pounds per hour or heat input is 
not available for any hour for the unit, that heat input and 
NOX pounds per hour shall not be used in the calculation of 
the rolling 30-boiler-operating-day emission rate.
    (iv) Compliance determination for SO2. Compliance with the 
SO2 emission limit described in paragraph (j)(3) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The rolling 30-boiler-operating-day SO2 emission rate 
for the unit shall be calculated for each boiler operating day in 
accordance with the following procedure: Step one, sum the hourly 
pounds of SO2 emitted for the current boiler operating day 
and the preceding twenty-nine (29) boiler operating days to calculate 
the total pounds of SO2 emitted over the most recent thirty 
(30) boiler-operating-day period for that unit; Step two, sum the total 
heat input, in MMBtu, during the current boiler operating day and the 
preceding twenty-nine (29) boiler operating days to calculate the total 
heat input over the most recent thirty (30) boiler-operating-day period 
for that unit; Step three, divide the total amount of SO2 
calculated from Step one by the total heat input calculated from Step 
two to calculate the rolling 30-boiler-operating-day SO2 
emission rate, in pounds per MMBtu for that unit. Each rolling 30-
boiler-operating-day SO2 emission rate shall include all 
emissions and all heat input that occur during all periods within any 
boiler operating day, including emissions from startup, shutdown, and 
malfunction. If a valid SO2 pounds per hour or heat input is 
not available for any hour for the unit, that heat input and 
SO2 pounds per hour shall not be used in the calculation of 
the rolling 30-boiler-operating-day emission rate.
    (v) Compliance determination for PM. Compliance with the PM 
emission limit described in paragraph (j)(3) of this section shall be 
determined from annual performance stack tests. Within sixty (60) days 
either preceding or following the compliance deadline specified in 
paragraph (j)(5)(ii) of this section, and on at least an annual basis 
thereafter, the owner/operator of the unit shall conduct a stack test 
on the unit to measure PM using EPA Methods 1 through 5, in 40 CFR part 
60, appendix A. Each test shall consist of three runs, with each run at 
least one hundred twenty (120) minutes in duration and each run 
collecting a minimum sample of sixty (60) dry standard cubic feet. 
Results shall be reported in lb/MMBtu using the calculation in 40 CFR 
part 60, appendix A, Method 19.
    (8) Alternative compliance determination. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, this paragraph (j)(8) may be used in lieu of paragraph (j)(7) 
of this section to demonstrate compliance with the emission limits in 
paragraph (j)(4) of this section.
    (i) Continuous emission monitoring system. (A) At all times after 
the compliance date specified in paragraph (j)(6) of this section, the 
owner/operator of the unit shall maintain, calibrate, and operate CEMS, 
in full compliance with the requirements found at 40 CFR part 75, to 
accurately measure NOX, diluent, and stack gas volumetric 
flow rate from the unit. All valid CEMS hourly data shall be used to 
determine compliance

[[Page 52484]]

with the emission limitation for NOX in paragraph (j)(4) of 
this section. When the CEMS is out-of-control as defined by 40 CFR part 
75, the CEMS data shall be treated as missing data and not used to 
calculate the emission average. Each required CEMS must obtain valid 
data for at least ninety (90) percent of the unit operating hours, on 
an annual basis.
    (B) The owner/operator of the unit shall comply with the quality 
assurance procedures for CEMS found in 40 CFR part 75. In addition to 
these part 75 requirements, relative accuracy test audits shall be 
calculated for both the NOX pounds per hour measurement and 
the heat input measurement. The CEMS monitoring data shall not be bias 
adjusted. Calculations of relative accuracy for lb/hr of NOX 
and heat input shall be performed each time the CEMS undergo relative 
accuracy testing.
    (ii) Compliance determination for NOX. Compliance with the 
NOX emission limit described in paragraph (j)(4) of this 
section shall be determined based on a rolling 30 boiler-operating-day 
basis. The rolling 30-boiler-operating-day NOX emission rate 
for the unit shall be calculated for each boiler operating day in 
accordance with the following procedure: Step one, sum the hourly 
pounds of NOX emitted for the current boiler operating day 
and the preceding twenty-nine (29) boiler-operating-days to calculate 
the total pounds of NOX emitted over the most recent thirty 
(30) boiler-operating-day period for that unit; Step two, sum the total 
heat input, in MMBtu, during the current boiler operating day and the 
preceding twenty-nine (29) boiler-operating-days to calculate the total 
heat input over the most recent thirty (30) boiler-operating-day period 
for that unit; Step three, divide the total amount of NOX 
calculated from Step one by the total heat input calculated from Step 
two to calculate the rolling 30-boiler-operating-day NOX 
emission rate, in pounds per MMBtu for that unit. Each rolling 30-
boiler-operating-day NOX emission rate shall include all 
emissions and all heat input that occur during all periods within any 
boiler operating day, including emissions from startup, shutdown, and 
malfunction. If a valid NOX pounds per hour or heat input is 
not available for any hour for the unit, that heat input and 
NOX pounds per hour shall not be used in the calculation of 
the rolling 30-boiler-operating-day emission rate.
    (iii) Compliance determination for SO2. Compliance with the 
SO2 emission limit for the unit shall be determined from 
fuel sulfur documentation demonstrating the use of either natural gas 
or natural gas combined with landfill gas.
    (iv) Compliance determination for PM10. Compliance with the 
PM10 emission limit for the unit shall be determined from 
performance stack tests. Within sixty (60) days following the 
compliance deadline specified in paragraph (j)(6) of this section, and 
at the request of the Regional Administrator thereafter, the owner/
operator of the unit shall conduct a stack test on the unit to measure 
PM10 using EPA Methods 1 through 4, 201A, and Method 202, 
per 40 CFR part 51, appendix M. Each test shall consist of three runs, 
with each run at least one hundred twenty (120) minutes in duration and 
each run collecting a minimum sample of sixty (60) dry standard cubic 
feet. Results shall be reported in lb/MMBtu using the calculation in 40 
CFR part 60, appendix A, Method 19.
    (9) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) CEMS data measuring NOX in lb/hr, SO2 in 
lb/hr, and heat input rate per hour.
    (ii) Daily rolling 30-boiler operating day emission rates of 
NOX and SO2 calculated in accordance with 
paragraphs (j)(7)(iii) and (iv) of this section.
    (iii) Records of the relative accuracy test for NOX lb/
hr and SO2 lb/hr measurement, and hourly heat input 
measurement.
    (iv) Records of quality assurance and quality control activities 
for emissions systems including, but not limited to, any records 
required by 40 CFR part 75.
    (v) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (vi) Any other records required by 40 CFR part 75.
    (vii) Records of ammonia consumption for the unit, as recorded by 
the instrumentation required in paragraph (j)(7)(ii) of this section.
    (viii) All PM stack test results.
    (10) Alternative recordkeeping requirements. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, the owner/operator shall maintain the records listed in this 
paragraph (j)(10) in lieu of the records contained in paragraph (j)(9) 
of this section. The owner/operator shall maintain the following 
records for at least five years:
    (i) CEMS data measuring NOX in lb/hr and heat input rate 
per hour.
    (ii) Daily rolling 30-boiler operating day emission rates of 
NOX calculated in accordance with paragraph (j)(8)(ii) of 
this section.
    (iii) Records of the relative accuracy test for NOX lb/
hr measurement and hourly heat input measurement.
    (iv) Records of quality assurance and quality control activities 
for emissions systems including, but not limited to, any records 
required by 40 CFR part 75.
    (v) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (vi) Any other records required by 40 CFR part 75.
    (vii) Records sufficient to demonstrate that the fuel for the unit 
is natural gas or natural gas combined with landfill gas.
    (viii) All PM10 stack test results.
    (11) Notifications. All notifications required under this section 
shall be submitted by the owner/operator to the Director, Enforcement 
Division (Mail Code ENF-2-1), U.S. Environmental Protection Agency, 
Region 9, 75 Hawthorne Street, San Francisco, California 94105-3901.
    (i) By March 31, 2017, the owner/operator shall submit notification 
by letter whether it will comply with the emission limits in paragraph 
(j)(3) of this section or whether it will comply with the emission 
limits in paragraph (j)(4) of this section. In the event that the 
owner/operator does not submit timely and proper notification by March 
31, 2017, the owner/operator may not choose to comply with the 
alternative emission limits in paragraph (j)(4) of this section and 
shall comply with the emission limits in paragraph (j)(3) of this 
section.
    (ii) The owner/operator shall submit notification of commencement 
of construction of any equipment which is being constructed to comply 
with either the NOX or SO2 emission limits in 
paragraph (j)(3) of this section.
    (iii) The owner/operator shall submit semiannual progress reports 
on construction of any such equipment.
    (iv) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (v) The owner/operator shall submit notification of its intent to 
comply with the PM10 emission limit in paragraph (j)(4)(iii) 
of this section within one hundred twenty (120) days following the 
compliance deadline specified in paragraph (j)(6) of this section. The 
notification shall include results of the initial performance test and 
the resulting applicable emission limit.
    (12) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-

[[Page 52485]]

2-1), U.S. Environmental Protection Agency, Region 9, 75 Hawthorne 
Street, San Francisco, California 94105-3901. All reports required 
under this section shall be submitted within 30 days after the 
applicable compliance date(s) in paragraph (j)(5) of this section and 
at least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
rolling 30-boiler operating day emission rates for NOX and 
SO2.
    (ii) The owner/operator shall submit excess emission reports for 
NOX and SO2 limits. Excess emissions means 
emissions that exceed the emission limits specified in paragraph (j)(3) 
of this section. Excess emission reports shall include the magnitude, 
date(s), and duration of each period of excess emissions; specific 
identification of each period of excess emissions that occurs during 
startups, shutdowns, and malfunctions of the unit; the nature and cause 
of any malfunction (if known); and the corrective action taken or 
preventative measures adopted.
    (iii) The owner/operator shall submit a summary of CEMS operation, 
to include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall submit the results of any relative 
accuracy test audits performed during the two preceding calendar 
quarters.
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the semiannual report.
    (vi) The owner/operator shall submit results of any PM stack tests 
conducted for demonstrating compliance with the PM limit specified in 
paragraph (j)(3) of this section.
    (13) Alternative reporting requirements. If the owner/operator 
chooses to comply with the emission limits of paragraph (j)(4) of this 
section, the owner/operator shall submit the reports listed in this 
paragraph (j)(13) in lieu of the reports contained in paragraph (j)(12) 
of this section. All reports required under this paragraph (j)(13) 
shall be submitted by the owner/operator to the Director, Enforcement 
Division (Mail Code ENF-2-1), U.S. Environmental Protection Agency, 
Region 9, 75 Hawthorne Street, San Francisco, California 94105-3901. 
All reports required under this paragraph (j)(13) shall be submitted 
within 30 days after the applicable compliance date(s) in paragraph 
(j)(6) of this section and at least semiannually thereafter, within 30 
days after the end of a semiannual period. The owner/operator may 
submit reports more frequently than semiannually for the purposes of 
synchronizing reports required under this section with other reporting 
requirements, such as the title V monitoring report required by 40 CFR 
70.6(a)(3)(iii)(A), but at no point shall the duration of a semiannual 
period exceed six months.
    (i) The owner/operator shall submit a report that lists the daily 
rolling 30-boiler operating day emission rates for NOX.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX limits. Excess emissions means emissions that exceed the 
emission limit specified in paragraph (j)(4) of this section. The 
reports shall include the magnitude, date(s), and duration of each 
period of excess emissions; specific identification of each period of 
excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit; the nature and cause of any malfunction (if 
known); and the corrective action taken or preventative measures 
adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall submit the results of any relative 
accuracy test audits performed during the two preceding calendar 
quarters.
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the semiannual report.
    (vi) The owner/operator shall submit results of any PM10 
stack tests conducted for demonstrating compliance with the 
PM10 limit specified in paragraph (j)(4) of this section.
    (14) Equipment operations. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner/operator shall, to the 
extent practicable, maintain and operate the unit, including associated 
air pollution control equipment, in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator, which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (ii) After completion of installation of ammonia injection on a 
unit, the owner/operator shall inject sufficient ammonia to achieve 
compliance with the NOX emission limit contained in 
paragraph (j)(3) of this section for that unit while preventing 
excessive ammonia emissions.
    (15) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed can be used to establish whether or not the owner/operator 
has violated or is in violation of any standard or applicable emission 
limit in the plan.
    (k) Source-specific federal implementation plan for regional haze 
at Clarkdale Cement Plant and Rillito Cement Plant--(1) Applicability. 
This paragraph (k) applies to each owner/operator of the following 
cement kilns in the state of Arizona: Kiln 4 located at the cement 
plant in Clarkdale, Arizona, and kiln 4 located at the cement plant in 
Rillito, Arizona.
    (2) Definitions. Terms not defined in this paragraph (k)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (k):
    Ammonia injection shall include any of the following: Anhydrous 
ammonia, aqueous ammonia or urea injection.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of NOX

[[Page 52486]]

emissions, diluent, or stack gas volumetric flow rate.
    Kiln operating day means a 24-hour period between 12 midnight and 
the following midnight during which the kiln operates at any time.
    Kiln operation means any period when any raw materials are fed into 
the kiln or any period when any combustion is occurring or fuel is 
being fired in the kiln.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises a cement kiln identified in paragraph (k)(1) of this 
section.
    Unit means a cement kiln identified in paragraph (k)(1) of this 
section.
    (3) Emissions limitations. (i) The owner/operator of kiln 4 of the 
Clarkdale Plant, as identified in paragraph (k)(1) of this section, 
shall not emit or cause to be emitted from kiln 4 NOX in 
excess of 2.12 pounds of NOX per ton of clinker produced, 
based on a rolling 30-kiln operating day basis. In addition, if the 
owner/operator installs an ammonia injection system to comply with the 
limits specified in this paragraph (k)(3), the owner/operator shall 
also comply with the control technology demonstration requirements set 
forth in paragraph (k)(6) of this section.
    (ii) The owner/operator of kiln 4 of the Rillito Plant, as 
identified in paragraph (k)(1) of this section, shall not emit or cause 
to be emitted from kiln 4 NOX in excess of 3.46 pounds of 
NOX per ton of clinker produced, based on a rolling 30-kiln 
operating day basis. In addition, if the owner/operator installs an 
ammonia injection system to comply with the limits specified in this 
paragraph (k)(3), the owner/operator shall also comply with the control 
technology demonstration requirements set forth in paragraph (k)(6) of 
this section.
    (4) Alternative emissions limitation. In lieu of the emission 
limitation listed in paragraph (k)(3)(i) of this section, the owner/
operator of kiln 4 of the Clarkdale Plant may choose to comply with the 
following limitation by providing notification per paragraph 
(k)(13)(iv) of this section. The owner/operator of kiln 4 of the 
Clarkdale Plant, as identified in paragraph (k)(1) of this section, 
shall not emit or cause to be emitted from kiln 4 NOX in 
excess of 810 tons per year, based on a rolling 12 month basis.
    (5) Compliance date. (i) The owner/operator of each unit identified 
in paragraph (k)(1) of this section shall comply with the 
NOX emissions limitations and other NOX-related 
requirements of paragraph (k)(3) of this section no later than December 
31, 2018.
    (ii) If the owner/operator of the Clarkdale Plant chooses to comply 
with the emission limit of paragraph (k)(4) of this section in lieu of 
paragraph (k)(3)(i) of this section, the owner/operator shall comply 
with the NOX emissions limitations and other NOX-
related requirements of paragraph (k)(4) of this section no later than 
December 31, 2018.
    (6) Control technology demonstration requirements. If the owner/
operator of a unit installs an ammonia injection system to comply with 
the limits specified in paragraph (k)(3) of this section, the owner/
operator must comply with the following requirements for implementing 
combustion and process optimization measures.
    (i) Design report. Prior to commencing construction of an ammonia 
injection system used to comply with the limits specified in paragraph 
(k)(3) of this section, the owner/operator shall submit to EPA for 
review a Design Report as described in appendix A of this section.
    (ii) Optimization protocol. Prior to commencement of the 
Optimization Program, the owner/operator shall submit to EPA for review 
an Optimization Protocol which shall include the procedures, as 
described in appendix A of this section, to be used during the 
Optimization Program for the purpose of adjusting operating parameters 
and minimizing emissions.
    (iii) Optimization period. Following EPA review of the Optimization 
Protocol, the owner/operator shall operate the ammonia injection system 
and collect data in accordance with the Optimization Protocol. The 
owner/operator shall operate the ammonia injection system in such a 
manner for no longer than 180 kiln operating days, or the duration 
specified in the Optimization Protocol, whichever is longer in 
duration.
    (iv) Optimization report. Within 60 calendar days following the 
conclusion of the Optimization Program, the owner/operator shall submit 
to EPA for review an Optimization Report, as described in appendix A of 
this section, demonstrating conformance with the Optimization Protocol, 
and establishing optimized operating parameters for the ammonia 
injection system as well as other facility processes.
    (v) Demonstration period. Following EPA review of the Optimization 
Report, the owner/operator shall operate the ammonia injection system 
consistent with the optimized operations of the facility and ammonia 
injection system specified in the Optimization Report. The owner/
operator shall operate the ammonia injection system in such a manner 
for a period of 270 kiln operating days, or the duration specified in 
the Optimization Report, whichever is longer. The Demonstration Period 
may be shortened or lengthened as provided for in appendix A of this 
section.
    (vi) Demonstration report. Within 60 calendar days following the 
conclusion of the Demonstration Program, the owner/operator shall 
submit a Demonstration Report, as described in appendix A of this 
section, which identifies a proposed rolling 30-kiln operating day 
emission limit for NOX. In a subsequent regulatory action, 
EPA may seek to lower the emission limits in paragraphs (k)(3) and/or 
(k)(4) of this section in view of, among other things, the information 
contained in the Demonstration Report. The proposed rolling 30-kiln 
operating day emission limit shall be calculated in accordance with the 
following formula:

    X = [mu] + 1.65[sigma]

Where:

X = Rolling 30-kiln operating day emission limit, in pounds of NOx 
per ton of clinker;
[mu] = Arithmetic mean of all of the rolling 30-kiln operating day 
emission rates;
[sigma] = Standard deviation of all of the rolling 30-kiln operating 
day emission rates, as calculated in the following manner:
[GRAPHIC] [TIFF OMITTED] TR03SE14.002

Where:

N = The total number of rolling 30-kiln operating day emission 
rates;
xi = Each rolling 30-kiln operating day emission rate;
x = The mean value of all of the rolling 30-kiln operating day 
emission rates.

    (7) Compliance determination--(i) Continuous emission monitoring 
system. (A) At all times after the compliance date specified in 
paragraph (k)(5) of this section, the owner/operator of the unit at the 
Clarkdale Plant shall maintain, calibrate, and operate a CEMS, in full 
compliance with the requirements found at 40 CFR 60.63(f) and (g), to 
accurately measure concentration by volume of NOX, diluent, 
and stack gas volumetric flow rate from the in-line/raw mill stack, as 
well as the stack gas volumetric flow rate from the coal mill stack. 
The CEMS shall be used by the owner/operator to determine compliance 
with the emission limitation in paragraph (k)(3) of this section, in 
combination with data on actual clinker production. The owner/operator 
must operate the

[[Page 52487]]

monitoring system and collect data at all required intervals at all 
times the affected unit is operating, except for periods of monitoring 
system malfunctions, repairs associated with monitoring system 
malfunctions, and required monitoring system quality assurance or 
quality control activities (including, as applicable, calibration 
checks and required zero and span adjustments).
    (B) At all times after the compliance date specified in paragraph 
(k)(5) of this section, the owner/operator of the unit at the Rillito 
Plant shall maintain, calibrate, and operate a CEMS, in full compliance 
with the requirements found at 40 CFR 60.63(f) and (g), to accurately 
measure concentration by volume of NOX, diluent, and stack 
gas volumetric flow rate from the unit. The CEMS shall be used by the 
owner/operator to determine compliance with the emission limitation in 
paragraph (k)(3) of this section, in combination with data on actual 
clinker production. The owner/operator must operate the monitoring 
system and collect data at all required intervals at all times the 
affected unit is operating, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments).
    (ii) Methods. (A) The owner/operator of each unit shall record the 
daily clinker production rates.
    (B)(1) The owner/operator of each unit shall calculate and record 
the 30-kiln operating day average emission rate of NOX, in 
lb/ton of clinker produced, as the total of all hourly emissions data 
for the cement kiln in the preceding 30-kiln operating days, divided by 
the total tons of clinker produced in that kiln during the same 30-day 
operating period, using the following equation:
[GRAPHIC] [TIFF OMITTED] TR03SE14.003


Where:

E[D] = 30 kiln operating day average emission rate of 
NOX, lb/ton of clinker;
C[i] = Concentration of NOX for hour i, ppm;
Q[i] = Volumetric flow rate of effluent gas for hour i, where C[i] 
and Q[i] are on the same basis (either wet or dry), scf/hr;
P[i] = Total kiln clinker produced during production hour i, ton/hr;
k = Conversion factor, 1.194 x 10<-7> for NOX; and
n = Number of kiln operating hours over 30 kiln operating days, n = 
1 up to 720.

    (2) For each kiln operating hour for which the owner/operator does 
not have at least one valid 15-minute CEMS data value, the owner/
operator must use the average emissions rate (lb/hr) from the most 
recent previous hour for which valid data are available. Hourly clinker 
production shall be determined by the owner/operator in accordance with 
the requirements found at 40 CFR 60.63(b).
    (C) At the end of each kiln operating day, the owner/operator shall 
calculate and record a new 30-day rolling average emission rate in lb/
ton clinker from the arithmetic average of all valid hourly emission 
rates for the current kiln operating day and the previous 29 successive 
kiln operating days.
    (D) Upon and after the completion of installation of ammonia 
injection on a unit, the owner/operator shall install, and thereafter 
maintain and operate, instrumentation to continuously monitor and 
record levels of ammonia consumption that unit.
    (8) Alternative compliance determination. If the owner/operator of 
the Clarkdale Plant chooses to comply with the emission limits of 
paragraph (k)(4) of this section, this paragraph (k)(8) may be used in 
lieu of paragraph (k)(7) of this section to demonstrate compliance with 
the emission limits in paragraph (k)(4) of this section.
    (i) Continuous emission monitoring system. At all times after the 
compliance date specified in paragraph (k)(5) of this section, the 
owner/operator of the unit at the Clarkdale Plant shall maintain, 
calibrate, and operate a CEMS, in full compliance with the requirements 
found at 40 CFR 60.63(f) and (g), to accurately measure concentration 
by volume of NOX, diluent, and stack gas volumetric flow 
rate from the in-line/raw mill stack, as well as the stack gas 
volumetric flow rate from the coal mill stack. The CEMS shall be used 
by the owner/operator to determine compliance with the emission 
limitation in paragraph (k)(3) of this section, in combination with 
data on actual clinker production. The owner/operator must operate the 
monitoring system and collect data at all required intervals at all 
times the affected unit is operating, except for periods of monitoring 
system malfunctions, repairs associated with monitoring system 
malfunctions, and required monitoring system quality assurance or 
quality control activities (including, as applicable, calibration 
checks and required zero and span adjustments).
    (ii) Method. Compliance with the ton per year NOX 
emission limit described in paragraph (k)(4) of this section shall be 
determined based on a rolling 12 month basis. The rolling 12-month 
NOX emission rate for the kiln shall be calculated within 30 
days following the end of each calendar month in accordance with the 
following procedure: Step one, sum the hourly pounds of NOX 
emitted for the month just completed and the eleven (11) months 
preceding the month just completed, to calculate the total pounds of 
NOX emitted over the most recent twelve (12) month period 
for that kiln; Step two, divide the total pounds of NOX 
calculated from Step one by two thousand (2,000) to calculate the total 
tons of NOX. Each rolling 12-month NOX emission 
rate shall include all emissions that occur during all periods within 
the 12-month period, including emissions from startup, shutdown and 
malfunction.
    (iii) Upon and after the completion of installation of ammonia 
injection on the unit, the owner/operator shall install, and thereafter 
maintain and operate, instrumentation to continuously monitor and 
record levels of ammonia consumption for that unit.
    (9) Recordkeeping. The owner/operator of each unit shall maintain 
the following records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; emissions and parameters sampled or measured; and 
results.
    (ii) All records of clinker production.
    (iii) Daily 30-day rolling emission rates of NOX, 
calculated in accordance with paragraph (k)(7)(ii) of this section.
    (iv) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records specified by 40 CFR part 60, appendix F, Procedure 1.
    (v) Records of ammonia consumption, as recorded by the 
instrumentation required in paragraph (k)(7)(ii)(D) of this section.
    (vi) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, CEMS and clinker 
production measurement devices.

[[Page 52488]]

    (vii) Any other records specified by 40 CFR part 60, subpart F, or 
40 CFR part 60, appendix F, Procedure 1.
    (10) Alternative recordkeeping requirements. If the owner/operator 
of the Clarkdale Plant chooses to comply with the emission limits of 
paragraph (k)(4) of this section, the owner/operator shall maintain the 
records listed in this paragraph (k)(10) in lieu of the records 
contained in paragraph (k)(9) of this section. The owner or operator 
shall maintain the following records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; emissions and parameters sampled or measured; and 
results.
    (ii) Monthly rolling 12-month emission rates of NOX, 
calculated in accordance with paragraph (k)(8)(ii) of this section.
    (iii) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records specified by 40 CFR part 60, appendix F, Procedure 1.
    (iv) Records of ammonia consumption, as recorded by the 
instrumentation required in paragraph (k)(8)(iii) of this section.
    (v) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS measurement 
devices.
    (vi) Any other records specified by 40 CFR part 60, subpart F, or 
40 CFR part 60, appendix F, Procedure 1.
    (11) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mailcode ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (k)(5) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall submit a report that lists the daily 
30-day rolling emission rates for NOX.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX limits. Excess emissions means emissions that exceed the 
emissions limits specified in paragraph (k)(3) of this section. The 
reports shall include the magnitude, date(s), and duration of each 
period of excess emissions, specific identification of each period of 
excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall also submit results of any CEMS 
performance tests specified by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the reports required by 
paragraph (k)(9)(ii) of this section.
    (12) Alternative reporting requirements. If the owner/operator of 
the Clarkdale Plant chooses to comply with the emission limits of 
paragraph (k)(4) of this section, the owner/operator shall submit the 
reports listed in this paragraph (k)(12) in lieu of the reports 
contained in paragraph (k)(11) of this section. All reports required 
under this section shall be submitted by the owner/operator to the 
Director, Enforcement Division (Mailcode ENF-2-1), U.S. Environmental 
Protection Agency, Region 9, 75 Hawthorne Street, San Francisco, 
California 94105-3901. All reports required under this section shall be 
submitted within 30 days after the applicable compliance date in 
paragraph (k)(5) of this section and at least semiannually thereafter, 
within 30 days after the end of a semiannual period. The owner/operator 
may submit reports more frequently than semiannually for the purposes 
of synchronizing reports required under this section with other 
reporting requirements, such as the title V monitoring report required 
by 40 CFR 70.6(a)(3)(iii)(A), but at no point shall the duration of a 
semiannual period exceed six months.
    (i) The owner/operator shall submit a report that lists the monthly 
rolling 12-month emission rates for NOX.
    (ii) The owner/operator shall submit excess emissions reports for 
NOX limits. Excess emissions means emissions that exceed the 
emissions limits specified in paragraph (k)(3) of this section. The 
reports shall include the magnitude, date(s), and duration of each 
period of excess emissions, specific identification of each period of 
excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted.
    (iii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments.
    (iv) The owner/operator shall also submit results of any CEMS 
performance tests specified by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (v) When no excess emissions have occurred or the CEMS has not been 
inoperative, repaired, or adjusted during the reporting period, the 
owner/operator shall state such information in the reports required by 
paragraph (k)(9)(ii) of this section.
    (13) Notifications. (i) The owner/operator shall submit 
notification of commencement of construction of any equipment which is 
being constructed to comply with the NOX emission limits in 
paragraph (k)(3) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (iv) By June 30, 2018, the owner/operator of the Clarkdale Plant 
shall notify the Regional Administrator by letter whether it will 
comply with the emission limits in paragraph (k)(3)(i) of this section 
or whether it will comply with the emission limits in paragraph (k)(4) 
of this section. In the event that the owner/operator does not submit 
timely and proper notification by June 30, 2018, the owner/operator of 
the Clarkdale Plant may not choose to comply with the alternative 
emission limits in paragraph (k)(4) of this section and shall comply 
with the emission limits in paragraph (k)(3)(i) of this section.
    (14) Equipment operation. (i) At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution

[[Page 52489]]

control equipment in a manner consistent with good air pollution 
control practices for minimizing emissions. Pollution control equipment 
shall be designed and capable of operating properly to minimize 
emissions during all expected operating conditions. Determination of 
whether acceptable operating and maintenance procedures are being used 
will be based on information available to the Regional Administrator 
which may include, but is not limited to, monitoring results, review of 
operating and maintenance procedures, and inspection of the unit.
    (ii) After completion of installation of ammonia injection on a 
unit, the owner or operator shall inject sufficient ammonia to achieve 
compliance with NOX emission limits set forth in paragraph 
(k)(3) of this section for that unit while preventing excessive ammonia 
emissions.
    (15) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (l) Source-specific federal implementation plan for regional haze 
at Hayden Copper Smelter--(1) Applicability. This paragraph (l) applies 
to each owner/operator of batch copper converters 1, 3, 4 and 
5 and anode furnaces 1 and 2 at the copper smelting 
plant located in Hayden, Gila County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (l)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (l):
    Anode furnace means a furnace in which molten blister copper is 
refined through introduction of a reducing agent such as natural gas.
    Batch copper converter means a Peirce-Smith converter in which 
copper matte is oxidized to form blister copper by a process that is 
performed in discrete batches using a sequence of charging, blowing, 
skimming, and pouring.
    Blister copper means an impure form of copper, typically between 96 
and 98 percent pure copper that is the output of the converters.
    Calendar day means a 24 hour period that begins and ends at 
midnight, local standard time.
    Capture system means the collection of components used to capture 
gases and fumes released from one or more emission points, and to 
convey the captured gases and fumes to one or more control devices. A 
capture system may include, but is not limited to, the following 
components as applicable to a given capture system design: Duct intake 
devices, hoods, enclosures, ductwork, dampers, manifolds, plenums, and 
fans.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of SO2 emissions, other pollutant emissions, diluent, 
or stack gas volumetric flow rate.
    Copper matte means a material predominately composed of copper and 
iron sulfides produced by smelting copper ore concentrates.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the equipment identified in paragraph (l)(1) of this 
section.
    Regional Administrator means the Regional Administrator of EPA 
Region 9 or his or her designated representative.
    SO2 means sulfur dioxide.
    (3) Emission capture. (i) The owner/operator must operate a capture 
system that has been designed to maximize collection of process off 
gases vented from each converter identified in paragraph (l)(1) of this 
section. The capture system must include primary and secondary capture 
systems as described in 40 CFR 63.1444(d)(2).
    (ii) The operation of the batch copper converters, primary capture 
system, and secondary capture system shall be optimized to capture the 
maximum amount of process off gases vented from each converter at all 
times.
    (iii) The owner/operator shall prepare a written operation and 
maintenance plan according to the requirements in paragraph (l)(3)(iv) 
of this section and submit this plan to the Regional Administrator 180 
days prior to the compliance date in paragraph (l)(5)(ii) of this 
section. The Regional Administrator shall approve or disapprove the 
plan within 180 days of submittal. At all times when one or more 
converters are blowing, the owner/operator must operate the capture 
system consistent with this plan.
    (iv) The written operations and maintenance plan must address the 
following requirements as applicable to the capture system or control 
device.
    (A) Preventative maintenance. The owner/operator must perform 
preventative maintenance for each capture system and control device 
according to written procedures specified in owner/operator's operation 
and maintenance plan. The procedures must include a preventative 
maintenance schedule that is consistent with the manufacturer's or 
engineer's instructions for routine and long-term maintenance.
    (B) Capture system inspections. The owner/operator must perform 
capture system inspections for each capture system in accordance with 
the requirements of 40 CFR 63.1447(b)(2).
    (C) Copper converter department capture system operating limits. 
The owner/operator must establish, according to the requirements 40 CFR 
63.1447(b)(3)(i) through (iii), operating limits for the capture system 
that are representative and reliable indicators of the optimized 
performance of the capture system, consistent with paragraph (l)(3)(ii) 
of this section, when it is used to collect the process off-gas vented 
from batch copper converters during blowing.
    (4) Emission limitations and work practice standards. (i) 
SO2 emissions collected by any primary capture system 
required by paragraph (l)(3) of this section must be controlled by one 
or more control devices and reduced by at least 99.8 percent, based on 
a 365-day rolling average.
    (ii) SO2 emissions collected by any secondary capture 
system required by paragraph (l)(3) of this section must be controlled 
by one or more control devices and reduced by at least 98.5 percent, 
based on a 365-day rolling average.
    (iii) The owner/operator must not cause or allow to be discharged 
to the atmosphere from any primary capture system required by paragraph 
(l)(3) of this section off-gas that contains nonsulfuric acid 
particulate matter in excess of 6.2 mg/dscm as measured using the test 
methods specified in 40 CFR 63.1450(b).
    (iv) The owner/operator must not cause or allow to be discharged to 
the atmosphere from any secondary capture system required by paragraph 
(l)(3) of this section off-gas that contains particulate matter in 
excess of 23 mg/dscm as measured using the test methods specified in 40 
CFR 63.1450(a).
    (v) Total NOX emissions from anode furnaces 1 
and 2 and the batch copper converters shall not exceed 40 tons 
per 12-continuous month period.
    (vi) Anode furnaces 1 and 2 shall only be charged 
with blister copper or higher purity copper. This charging

[[Page 52490]]

limitation does not extend to the use or addition of poling or fluxing 
agents necessary to achieve final casting chemistry.
    (5) Compliance dates. (i) The owner/operator of each batch copper 
converter identified in paragraph (l)(1) of this section shall comply 
with the emissions limitations in paragraphs (l)(4)(ii) and (l)(4)(iv) 
of this section and other requirements of this section related to the 
secondary capture system no later than September 3, 2018.
    (ii) The owner/operator of each batch copper converter identified 
in paragraph (l)(1) of this section shall comply with the emissions 
limitations in paragraphs (l)(4)(i), (l)(4)(iii), (l)(4)(v), and 
(l)(4)(vi) of this section and other requirements of this section, 
except those requirements related to the secondary capture system, no 
later than September 4, 2017.
    (6) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance date specified in paragraph 
(l)(5) of this section, the owner/operator of each batch copper 
converter identified in paragraph (l)(1) of this section shall 
maintain, calibrate, and operate a CEMS, in full compliance with the 
requirements found at 40 CFR 60.13 and 40 CFR part 60, appendices B and 
F, to accurately measure the mass emission rate in pounds per hour of 
SO2 emissions entering each control device used to control 
emissions from the converters, and venting from the converters to the 
atmosphere after passing through a control device or an uncontrolled 
bypass stack. The CEMS shall be used by the owner/operator to determine 
compliance with the emission limitation in paragraph (l)(4) of this 
section. The owner/operator must operate the monitoring system and 
collect data at all required intervals at all times that an affected 
unit is operating, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments).
    (ii) Compliance determination for SO2 limit for the 
converters. The 365-day rolling SO2 emission control 
efficiency for the converters shall be calculated separately for the 
primary capture system and the secondary capture system for each 
calendar day in accordance with the following procedure: Step one, sum 
the hourly pounds of SO2 vented to each uncontrolled bypass 
stack and to each control device used to control emissions from the 
converters for the current calendar day and the preceding three-
hundred-sixty-four (364) calendar days, to calculate the total pounds 
of pre-control SO2 emissions over the most recent three-
hundred-sixty-five (365) calendar day period; Step two, sum the hourly 
pounds of SO2 vented to each uncontrolled bypass stack and 
emitted from the release point of each control device used to control 
emissions from the converters for the current calendar day and the 
preceding three-hundred-sixty-four (364) calendar days, to calculate 
the total pounds of post-control SO2 emissions over the most 
recent three-hundred-sixty-five (365) calendar day period; Step three, 
divide the total amount of post-control SO2 emissions 
calculated from Step two by the total amount of pre-control 
SO2 emissions calculated from Step one, subtract the 
resulting ratio from one, and multiply the difference by 100 percent to 
calculate the 365-day rolling SO2 emission control 
efficiency as a percentage.
    (iii) Compliance determination for nonsulfuric acid particulate 
matter. Compliance with the emission limit for nonsulfuric acid 
particulate matter in paragraph (l)(4)(iii) of this section shall be 
demonstrated by the procedures in 40 CFR 63.1451(b) and 63.1453(a)(2). 
The owner/operator shall conduct an initial compliance test within 180 
days after the compliance date specified in paragraph (l)(5) of this 
section unless a test performed according to the procedures in 40 CFR 
63.1450 in the past year shows compliance with the limit.
    (iv) Compliance determination for particulate matter. Compliance 
with the emission limit for particulate matter in paragraph (l)(4)(iv) 
of this section shall be demonstrated by the procedures in 40 CFR 
63.1451(a) and 63.1453(a)(1). The owner/operator shall conduct an 
initial compliance test within 180 days after the compliance date 
specified in paragraph (l)(5) of this section unless a test performed 
according to the procedures in 40 CFR 63.1450 in the past year shows 
compliance with the limit.
    (v) Compliance determination for NOX. Compliance with the emission 
limit for NOX in paragraph (l)(4)(v) of this section shall 
be demonstrated by monitoring natural gas consumption in each of the 
units identified in paragraph (l)(1) of this section for each calendar 
day. At the end of each calendar month, the owner/operator shall 
calculate 12-consecutive month NOX emissions by multiplying 
the daily natural gas consumption rates for each unit by an approved 
emission factor and adding the sums for all units over the previous 12-
consecutive month period.
    (7) Alternatives to requirements to install CEMS. The requirement 
in paragraph (l)(6)(i) of this section to install CEMS to measure the 
mass of SO2 entering a control device or venting to the 
atmosphere through uncontrolled bypass stacks will be waived if the 
owner/operator complies with one of the options in this paragraph 
(l)(7).
    (i) Acid plants. The owner/operator may calculate the pounds of 
SO2 entering an acid plant during a calendar day by adding 
the pounds of SO2 emitted through the acid plant tail stack 
and 0.653 times the daily production of anhydrous sulfuric acid from 
the acid plant.
    (ii) Uncontrolled bypass stack. The owner/operator may calculate 
the pounds of SO2 venting to the atmosphere through an 
uncontrolled bypass stack based on test data provided the facility 
operates according to a startup, shutdown, and malfunction plan 
consistent with 40 CFR 63.6(e)(3) and the Regional Administrator has 
approved a calculation methodology for planned and unplanned bypass 
events.
    (8) Capture system monitoring. For each operating limit established 
under the capture system operation and maintenance plan required by 
paragraph (l)(4) of this section, the owner/operator must install, 
operate, and maintain an appropriate monitoring device according to the 
requirements in 40 CFR 63.1452(a)(1) through (6) to measure and record 
the operating limit value or setting at all times the required capture 
system is operating. Dampers that are manually set and remain in the 
same position at all times the capture system is operating are exempted 
from these monitoring requirements.
    (9) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (iii) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (iv) Any other records required by 40 CFR part 60, subpart F, or 40 
CFR part 60, appendix F, Procedure 1.
    (v) Records of all monitoring required by paragraph (l)(8) of this 
section.
    (vi) Records of daily sulfuric acid production in tons per day of 
pure,

[[Page 52491]]

anhydrous sulfuric acid if the owner/operator chooses to use the 
alternative compliance determination method in paragraph (l)(7)(i) of 
this section.
    (vii) Records of planned and unplanned bypass events and 
calculations used to determine emissions from bypass events if the 
owner/operator chooses to use the alternative compliance determination 
method in paragraph (l)(7)(ii) of this section.
    (viii) Records of daily natural gas consumption in each units 
identified in paragraph (l)(1) of this section and all calculations 
performed to demonstrate compliance with the limit in paragraph 
(l)(4)(vi) of this section.
    (10) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (l)(5) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall promptly submit excess emissions 
reports for the SO2 limit. Excess emissions means emissions 
that exceed the emissions limit specified in paragraph (d) of this 
section. The reports shall include the magnitude, date(s), and duration 
of each period of excess emissions, specific identification of each 
period of excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted. For the purpose of this paragraph (l)(10)(i), promptly shall 
mean within 30 days after the end of the month in which the excess 
emissions were discovered.
    (ii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments. The owner/
operator shall submit reports semiannually.
    (iii) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (iv) When no excess emissions have occurred or the CEMS has not 
been inoperative, repaired, or adjusted during the reporting period, 
the owner/operator shall state such information in the semiannual 
report.
    (v) When performance testing is required to determine compliance 
with an emission limit in paragraph (l)(4) of this section, the owner/
operator shall submit test reports as specified in 40 CFR part 63, 
subpart A.
    (11) Notifications. (i) The owner/operator shall notify EPA of 
commencement of construction of any equipment which is being 
constructed to comply with the capture or emission limits in paragraph 
(l)(3) or (4) of this section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (12) Equipment operations. At all times, including periods of 
startup, shutdown, and malfunction, the owner or operator shall, to the 
extent practicable, maintain and operate the unit including associated 
air pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (13) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.
    (m) Source-specific federal implementation plan for regional haze 
at Miami Copper Smelter--(1) Applicability. This paragraph (m) applies 
to each owner/operator of batch copper converters 2, 3, 4 and 5 and the 
electric furnace at the copper smelting plant located in Miami, Gila 
County, Arizona.
    (2) Definitions. Terms not defined in this paragraph (m)(2) shall 
have the meaning given them in the Clean Air Act or EPA's regulations 
implementing the Clean Air Act. For purposes of this paragraph (m):
    Batch copper converter means a Hoboken converter in which copper 
matte is oxidized to form blister copper by a process that is performed 
in discrete batches using a sequence of charging, blowing, skimming, 
and pouring.
    Calendar day means a 24 hour period that begins and ends at 
midnight, local standard time.
    Capture system means the collection of components used to capture 
gases and fumes released from one or more emission points, and to 
convey the captured gases and fumes to one or more control devices. A 
capture system may include, but is not limited to, the following 
components as applicable to a given capture system design: duct intake 
devices, hoods, enclosures, ductwork, dampers, manifolds, plenums, and 
fans.
    Continuous emission monitoring system or CEMS means the equipment 
required by this section to sample, analyze, measure, and provide, by 
means of readings recorded at least once every 15 minutes (using an 
automated data acquisition and handling system (DAHS)), a permanent 
record of SO2 emissions, other pollutant emissions, diluent, 
or stack gas volumetric flow rate.
    Copper matte means a material predominately composed of copper and 
iron sulfides produced by smelting copper ore concentrates.
    Electric furnace means a furnace in which copper matte and slag are 
heated by electrical resistance without the mechanical introduction of 
air or oxygen.
    NOX means nitrogen oxides.
    Owner/operator means any person who owns or who operates, controls, 
or supervises the equipment identified in paragraph (m)(1) of this 
section.
    Slag means the waste material consisting primarily of iron sulfides 
separated from copper matte during the smelting and refining of copper 
ore concentrates.
    SO2 means sulfur dioxide.
    (3) Emission capture. (i) The owner/operator of the batch copper 
converters

[[Page 52492]]

identified in paragraph (m)(1) of this section must operate a capture 
system that has been designed to maximize collection of process off 
gases vented from each converter. The capture system must include a 
primary capture system as described in 40 CFR 63.1444(d)(3) and a 
secondary capture system designed to maximize the collection of 
emissions not collected by the primary capture system.
    (ii) The operation of the batch copper converters, primary capture 
system, and secondary capture system shall be optimized to capture the 
maximum amount of process off gases vented from each converter at all 
times.
    (iii) The owner/operator shall prepare a written operation and 
maintenance plan according to the requirements in paragraph (m)(3)(iv) 
of this section and submit this plan to the Regional Administrator 180 
days prior to the compliance date in paragraph (m)(5) of this section. 
The Regional Administrator shall approve or disapprove the plan within 
180 days of submittal. At all times when one or more converters are 
blowing, the owner/operator must operate the capture system consistent 
with this plan.
    (iv) The written operations and maintenance plan must address the 
following requirements as applicable to the capture system or control 
device.
    (A) Preventative maintenance. The owner/operator must perform 
preventative maintenance for each capture system and control device 
according to written procedures specified in owner/operator's operation 
and maintenance plan. The procedures must include a preventative 
maintenance schedule that is consistent with the manufacturer's or 
engineer's instructions for routine and long-term maintenance.
    (B) Capture system inspections. The owner/operator must perform 
capture system inspections for each capture system in accordance with 
the requirements of 40 CFR 63.1447(b)(2).
    (C) Copper converter department capture system operating limits. 
The owner/operator must establish, according to the requirements 40 CFR 
63.1447(b)(3)(i) through (iii), operating limits for the capture system 
that are representative and reliable indicators of the performance of 
capture system when it is used to collect the process off-gas vented 
from batch copper converters during blowing.
    (4) Emission limitations and work practice standards. (i) 
SO2 emissions collected by the capture system required by 
paragraph (m)(3) of this section must be controlled by one or more 
control devices and reduced by at least 99.7 percent, based on a 365-
day rolling average.
    (ii) The owner/operator must not cause or allow to be discharged to 
the atmosphere from any primary capture system required by paragraph 
(m)(3) of this section off-gas that contains nonsulfuric acid 
particulate matter in excess of 6.2 mg/dscm as measured using the test 
methods specified in 40 CFR 63.1450(b).
    (iii) Total NOX emissions the electric furnace and the 
batch copper converters shall not exceed 40 tons per 12-continuous 
month period.
    (iv) The owner/operator shall not actively aerate the electric 
furnace.
    (5) Compliance dates. (i) The owner/operator of each batch copper 
converter identified in paragraph (m)(1) of this section shall comply 
with the emission capture requirement in paragraph (m)(3) of this 
section; the emission limitation in paragraph (m)(4)(i) of this 
section; the compliance determination requirements in paragraphs 
(m)(6)(i) and (ii) and (m)(7) of this section; the capture system 
monitoring requirements in paragraph (m)(8) of this section; the 
recordkeeping requirements in paragraphs (m)(9)(i) through (viii) of 
this section; and the reporting requirements in paragraphs (m)(10)(i) 
through (iv) of this section no later than January 1, 2018.
    (ii) The owner/operator of each batch copper converter and the 
electric furnace identified in paragraph (m)(1) of this section shall 
comply with all requirements of this paragraph (m) except those listed 
in paragraph (m)(5)(i) of this section no later than September 2, 2016.
    (6) Compliance determination--(i) Continuous emission monitoring 
system. At all times after the compliance date specified in paragraph 
(m)(5) of this section, the owner/operator of each batch copper 
converter identified in paragraph (m)(1) of this section shall 
maintain, calibrate, and operate a CEMS, in full compliance with the 
requirements found at 40 CFR 60.13 and 40 CFR part 60, appendices B and 
F, to accurately measure the mass emission rate in pounds per hour of 
SO2 emissions entering each control device used to control 
emissions from the converters, and venting from the converters to the 
atmosphere after passing through a control device or an uncontrolled 
bypass stack. The CEMS shall be used by the owner/operator to determine 
compliance with the emission limitation in paragraph (m)(4)(i) of this 
section. The owner/operator must operate the monitoring system and 
collect data at all required intervals at all times that an affected 
unit is operating, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required monitoring system quality assurance or quality control 
activities (including, as applicable, calibration checks and required 
zero and span adjustments).
    (ii) Compliance determination for SO2. The 365-day rolling 
SO2 emission control efficiency for the converters shall be 
calculated for each calendar day in accordance with the following 
procedure: Step one, sum the hourly pounds of SO2 vented to 
each uncontrolled bypass stack and to each control device used to 
control emissions from the converters for the current calendar day and 
the preceding three-hundred-sixty-four (364) calendar days, to 
calculate the total pounds of pre-control SO2 emissions over 
the most recent three-hundred-sixty-five (365) calendar day period; 
Step two, sum the hourly pounds of SO2 vented to each 
uncontrolled bypass stack and emitted from the release point of each 
control device used to control emissions from the converters for the 
current calendar day and the preceding three-hundred-sixty-four (364) 
calendar days, to calculate the total pounds of post-control 
SO2 emissions over the most recent three-hundred-sixty-five 
(365) calendar day period; Step three, divide the total amount of post-
control SO2 emissions calculated from Step two by the total 
amount of pre-control SO2 emissions calculated from Step 
one, subtract the resulting ratio from one, and multiply the difference 
by 100 percent to calculate the 365-day rolling SO2 emission 
control efficiency as a percentage.
    (iii) Compliance determination for nonsulfuric acid particulate 
matter. Compliance with the emission limit for nonsulfuric acid 
particulate matter in paragraph (m)(4)(ii) of this section shall be 
demonstrated by the procedures in 40 CFR 63.1451(b) and 63.1453(a)(2). 
The owner/operator shall conduct an initial compliance test within 180 
days after the compliance date specified in paragraph (m)(5) of this 
section unless a test performed according to the procedures in 40 CFR 
63.1450 in the past year shows compliance with the limit.
    (iv) Compliance determination for NOX. Compliance with the emission 
limit for NOX in paragraph (m)(4)(iii) of this section shall 
be demonstrated by monitoring natural gas consumption in each of the 
units identified in paragraph (m)(1) of this section for each calendar 
day. At the end of each calendar month, the owner/operator shall 
calculate monthly and 12-consecutive month NOX emissions by 
multiplying the daily

[[Page 52493]]

natural gas consumption rates for each unit by an approved emission 
factor and adding the sums for all units over the previous 12-
consecutive month period.
    (7) Alternatives to requirements to install CEMS. The requirement 
in paragraph (m)(6)(i) of this section to install CEMS to measure the 
mass of SO2 entering a control device or venting to the 
atmosphere through uncontrolled bypass stacks will be waived if the 
owner/operator complies with one of the options in this paragraph 
(m)(7).
    (i) Acid plants. The owner/operator may calculate the pounds of 
SO2 entering an acid plant during a calendar day by adding 
the pounds of SO2 emitted through the acid plant tail stack 
and 0.653 times the daily production of anhydrous sulfuric acid from 
the acid plant.
    (ii) Alkali scrubber. The owner/operator may calculate the pounds 
of SO2 entering an alkali scrubber during a calendar day by 
using the following equation:

Min,SO2 = Mout,SO2 + SF*Malk

Where:

Min,SO2 is the calculated mass of SO2 entering 
the scrubber during a calendar day;
Mout,SO2 is the mass of SO2 emitted through 
the scrubber stack measured by the CEMS for the calendar day;
SF is a stoichiometric factor; and
Malk is the mass of alkali added to the scrubber liquor 
during the calendar day.

SF shall equal:

1.14 if the alkali species is calcium oxide (CaO);
1.59 if the alkali species is magnesium oxide (MgO);
0.801 if the alkali species is sodium hydroxide (NaOH); or
Another value if the owner/operator has received approval from the 
Regional Administrator in advance.

    (iii) Uncontrolled bypass stack. The owner/operator may calculate 
the pounds of SO2 venting to the atmosphere through an 
uncontrolled bypass stack based on test data provided the facility 
operates according to a startup, shutdown, and malfunction plan 
consistent with 40 CFR 63.6(e)(3) and EPA has approved a calculation 
methodology for planned and unplanned bypass events.
    (8) Capture system monitoring. For each operating limit established 
under the capture system operation and maintenance plan required by 
paragraph (m)(3) of this section, the owner/operator must install, 
operate, and maintain an appropriate monitoring device according to the 
requirements in 40 CFR 63.1452(a)(1) though (6) to measure and record 
the operating limit value or setting at all times the required capture 
system is operating. Dampers that are manually set and remain in the 
same position at all times the capture system is operating are exempted 
from these monitoring requirements.
    (9) Recordkeeping. The owner/operator shall maintain the following 
records for at least five years:
    (i) All CEMS data, including the date, place, and time of sampling 
or measurement; parameters sampled or measured; and results.
    (ii) Records of quality assurance and quality control activities 
for emissions measuring systems including, but not limited to, any 
records required by 40 CFR part 60, appendix F, Procedure 1.
    (iii) Records of all major maintenance activities conducted on 
emission units, air pollution control equipment, and CEMS.
    (iv) Any other records required by 40 CFR part 60, subpart F, or 40 
CFR part 60, appendix F, Procedure 1.
    (v) Records of all monitoring required by paragraph (m)(8) of this 
section.
    (vi) Records of daily sulfuric acid production in tons per day of 
pure, anhydrous sulfuric acid if the owner/operator chooses to use the 
alternative compliance determination method in paragraph (m)(7)(i) of 
this section.
    (vii) Records of daily alkali consumption in tons per day of pure, 
anhydrous alkali if the owner/operator chooses to use the alternative 
compliance determination method in paragraph (m)(7)(ii) of this 
section.
    (viii) Records of planned and unplanned bypass events and 
calculations used to determine emissions from bypass events if the 
owner/operator chooses to use the alternative compliance determination 
method in paragraph (m)(7)(iii) of this section.
    (ix) Records of daily natural gas consumption in each units 
identified in paragraph (m)(1) of this section and all calculations 
performed to demonstrate compliance with the limit in paragraph 
(m)(4)(iv) of this section.
    (10) Reporting. All reports required under this section shall be 
submitted by the owner/operator to the Director, Enforcement Division 
(Mail Code ENF-2-1), U.S. Environmental Protection Agency, Region 9, 75 
Hawthorne Street, San Francisco, California 94105-3901. All reports 
required under this section shall be submitted within 30 days after the 
applicable compliance date in paragraph (m)(5) of this section and at 
least semiannually thereafter, within 30 days after the end of a 
semiannual period. The owner/operator may submit reports more 
frequently than semiannually for the purposes of synchronizing reports 
required under this section with other reporting requirements, such as 
the title V monitoring report required by 40 CFR 70.6(a)(3)(iii)(A), 
but at no point shall the duration of a semiannual period exceed six 
months.
    (i) The owner/operator shall promptly submit excess emissions 
reports for the SO2 limit. Excess emissions means emissions 
that exceed the emissions limit specified in paragraph (d) of this 
section. The reports shall include the magnitude, date(s), and duration 
of each period of excess emissions, specific identification of each 
period of excess emissions that occurs during startups, shutdowns, and 
malfunctions of the unit, the nature and cause of any malfunction (if 
known), and the corrective action taken or preventative measures 
adopted. For the purpose of this paragraph (m)(10)(i), promptly shall 
mean within 30 days after the end of the month in which the excess 
emissions were discovered.
    (ii) The owner/operator shall submit CEMS performance reports, to 
include dates and duration of each period during which the CEMS was 
inoperative (except for zero and span adjustments and calibration 
checks), reason(s) why the CEMS was inoperative and steps taken to 
prevent recurrence, and any CEMS repairs or adjustments. The owner/
operator shall submit reports semiannually.
    (iii) The owner/operator shall also submit results of any CEMS 
performance tests required by 40 CFR part 60, appendix F, Procedure 1 
(Relative Accuracy Test Audits, Relative Accuracy Audits, and Cylinder 
Gas Audits).
    (iv) When no excess emissions have occurred or the CEMS has not 
been inoperative, repaired, or adjusted during the reporting period, 
the owner/operator shall state such information in the semiannual 
report.
    (v) When performance testing is required to determine compliance 
with an emission limit in paragraph (m)(4) of this section, the owner/
operator shall submit test reports as specified in 40 CFR part 63, 
subpart A.
    (11) Notifications.
    (i) The owner/operator shall notify EPA of commencement of 
construction of any equipment which is being constructed to comply with 
the capture or emission limits in paragraph (m)(3) or (4) of this 
section.
    (ii) The owner/operator shall submit semiannual progress reports on 
construction of any such equipment.
    (iii) The owner/operator shall submit notification of initial 
startup of any such equipment.
    (12) Equipment operations. At all times, including periods of 
startup,

[[Page 52494]]

shutdown, and malfunction, the owner or operator shall, to the extent 
practicable, maintain and operate the unit including associated air 
pollution control equipment in a manner consistent with good air 
pollution control practices for minimizing emissions. Pollution control 
equipment shall be designed and capable of operating properly to 
minimize emissions during all expected operating conditions. 
Determination of whether acceptable operating and maintenance 
procedures are being used will be based on information available to the 
Regional Administrator which may include, but is not limited to, 
monitoring results, review of operating and maintenance procedures, and 
inspection of the unit.
    (13) Enforcement. Notwithstanding any other provision in this 
implementation plan, any credible evidence or information relevant as 
to whether the unit would have been in compliance with applicable 
requirements if the appropriate performance or compliance test had been 
performed, can be used to establish whether or not the owner or 
operator has violated or is in violation of any standard or applicable 
emission limit in the plan.

Appendix A to Sec.  52.145--Cement Kiln Control Technology 
Demonstration Requirements

I. Scope

    1. The owner/operator shall comply with the requirements 
contained in this appendix for implementing combustion and process 
optimization measures and in proposing and establishing rolling 30-
kiln operating day limits for nitrogen oxide (NOX).
    2. The owner/operator shall take the following steps to 
establish rolling 30-kiln operating day limits for NOX.
    a. Design Report: At least 6 months prior to commencing 
construction of an ammonia injection system, the owner/operator 
shall prepare and submit to EPA for review a Design Report for the 
ammonia injection system.
    b. Baseline Data Collection: Prior to initiating operation of an 
ammonia injection system, the owner/operator shall either: (i) 
Collect new baseline emissions and operational data for a 180-day 
period; or (ii) submit for EPA review baseline emissions and 
operational data from a period prior to the date of any baseline 
data collection period. Such baseline emissions and operational data 
shall be representative of the full range of normal kiln operations, 
including regular operating changes in raw mix chemistry due to 
different clinker manufacture, changes in production levels, and 
operation of the oxygen plants.
    c. Optimization Protocol: Prior to commencement of the 
Optimization Period, the owner/operator shall submit for EPA review 
an Optimization Protocol which shall include the procedures to be 
used for the purpose of adjusting operating parameters and 
minimizing emissions.
    d. Optimization Period: Following completion of installation of 
an ammonia injection system, the owner/operator shall undertake a 
startup and optimization period for the ammonia injection system.
    e. Optimization Report: Within 60 calendar days following the 
conclusion of the Optimization Program, the owner/operator shall 
submit to EPA an Optimization Report demonstrating conformance with 
the Optimization Protocol, and establishing optimized operating 
parameters for the ammonia injection system as well as other 
facility processes.
    f. Demonstration Period: Upon completion of the optimization 
period specified above, the owner/operator shall operate the ammonia 
injection system in a manner consistent with the optimization period 
for a period of 270 kiln operating days (subject to being shortened 
or lengthened as provided for in Items 17 and 18 of this appendix) 
for the purpose of establishing a rolling 30-kiln operating day 
limit.
    g. Demonstration Report: The owner/operator shall prepare and 
submit to EPA for review, a report following completion of the 
demonstration period for the ammonia injection system.

II. Design Report

    3. Prior to commencing construction of the ammonia injection 
system, the owner/operator shall submit to EPA for review a Design 
Report for the ammonia injection system. The owner/operator shall 
design the ammonia injection system to deliver the proposed reagent 
to the exhaust gases at the rate of at least 1.2 mols of reagent to 
1.0 mols of NOX (1.2:1 molar ratio). The system shall be 
designed to inject Ammonia into the kiln exhaust gas stream. The 
owner/operator shall specify in the Design Report the reagent(s) 
selected, the locations selected for reagent injection, and other 
design parameters based on maximum emission reduction effectiveness, 
good engineering judgment, vendor standards, available data, kiln 
operability, and regulatory restrictions on reagent storage and use.
    4. Any permit application which may be required under state or 
federal law for the ammonia injection system shall be consistent 
with the Design Report.

III. Baseline Data Collection

    5. Prior to commencement of continuous operation of the ammonia 
injection system, the owner/operator shall either: (a) Collect new 
baseline emissions and operational data for a 180-day period; or (b) 
submit for EPA review existing baseline emissions and operational 
data collected from a period of time prior to the initiation of a 
baseline collection period. Such baseline emissions and operational 
data shall include the data required by Item 8 below for periods of 
time representing the full range of normal kiln operations including 
changes in raw mix chemistry due to differing clinker manufacture, 
changes in production levels and operation of the oxygen plants. 
Within 45 Days following the completion of the baseline data 
collection period, the owner/operator shall submit to EPA the 
baseline data collected during the Baseline Data Collection Period.

IV. Optimization Period

    6. The owner/operator shall install, operate, and collect 
NOX emissions data from a CEMS in accordance with Sec.  
52.145(k)(7)(i), reagent injection data in accordance with Sec.  
52.145(k)(7)(ii)(D), and other operational data prior to 
commencement of the Optimization Period.
    7. During the Baseline Data Collection Period (if the owner/
operator elects to collect new data) and the Optimization Period, 
the owner/operator shall operate the Kiln in a manner necessary to 
produce a quality cement clinker product. The owner/operator shall 
not be expected to operate the Kiln within normal operating 
parameters during periods of Kiln Malfunction, Startup and Shutdown. 
The owner/operator shall not intentionally adjust kiln operating 
parameters to increase the rate of emission (expressed as lb/ton of 
clinker produced) for NOX. Increases or variability in 
the Kiln feed sulfur content, fuel and other raw materials 
composition including imported raw materials, resulting from the 
inherent variability within the onsite quarries and imported 
materials shall not constitute an intentional increase in emission 
rate.
    8. The data to be collected during the Baseline Data Collection 
Period (if the owner/operator elects to collect baseline data) and 
the Optimization Period will include the following information 
either derived from available direct monitoring or as estimated from 
monitored or measured data:
    a. Kiln flue gas temperature at the inlet to the fabric filter 
or at the Kiln stack (daily average);
    b. Kiln production rate in tons of clinker (daily total) by 
type;
    c. Raw material feed rate in tons (daily total) by type;
    d. Type and percentage of each raw material used and the total 
feed rate (daily);
    e. NOX and CO concentrations (dry basis) and mass 
rates for the Kiln (daily average for concentrations and daily 
totals for mass rates) as measured at the Kiln stack gas analyzer 
location;
    f. Flue gas volumetric flow rate (daily average in dry acfm);
    g. Sulfate in feed (calculated to a daily average percentage);
    h. Feed burnability (C3S) (at least daily). In the event that 
more than one type of clinker is produced, the feed burnability for 
each clinker type will be included;
    i. Temperatures in or near the burning zone (by infrared or 
optical pyrometer);
    j. Kiln system fuel feed rate and type of fuel by weight or heat 
input rate (calculated to a daily average);
    k. Fuel distribution, an estimate of how much is injected at 
each location (daily average);
    l. Kiln amps (daily average);
    m. Kiln system draft fan settings and primary air blower flow 
rates;
    n. Documentation of any Startup, Shutdown, or Malfunction 
events;
    o. An explanation of any gaps in the data or missing data; and

[[Page 52495]]

    p. Amount of oxygen generated and introduced into the Kiln (lb/
day).
    9. The owner/operator shall submit the data to EPA in an 
electronic format and shall explain the reasons for any data not 
collected for each of the parameters. The owner/operator shall 
report all data in a format consistent with and able to be 
manipulated by Microsoft Excel.
    10. Prior to commencement of the Optimization Period, the owner/
operator shall submit to EPA for review a protocol (``Optimization 
Protocol'') for optimizing the ammonia injection system, including 
optimization of the operational parameters resulting in the 
minimization of emissions of NOX to the greatest extent 
practicable without violating any limits. The Protocol shall 
describe procedures to be used during the Optimization Period to 
optimize the facility processes to minimize emissions from the kiln 
and adjust ammonia injection system operating parameters, and shall 
include the following:
    a. The following measures to optimize the facility's processes 
to reduce NOx emissions in conjunction with the ammonia injection 
system:
    i. Adjustment of the balance between fuel supplied to the 
existing riser duct burner and the existing calciner burners to 
improve overall combustion within the calciner while maintaining 
product quality;
    ii. Adjustments to the calciner combustion to ensure complete 
fuel burning, which will help to both reduce CO and improve NOx 
levels by, at a minimum:
    1. Adjusting fuel fineness to improve the degree of combustion 
completed in the calciner; and
    2. Adjusting the proportions of primary, secondary and tertiary 
air supplied to the kiln system while maintaining product quality; 
and
    iii. Adjustments to the raw mix chemical and physical properties 
using onsite raw materials to improve kiln stability and maintain 
product quality, including but not limited to, fineness of the raw 
mix. As part of this optimization measure, the owner/operator shall 
take additional measurements using existing monitoring equipment at 
relevant process locations to evaluate the impact of raw mix 
refinements.
    b. The range of reagent injection rates (as a molar ratio of the 
average pollutant concentration);
    c. Sampling and testing programs that will be undertaken during 
the initial reagent injection rate period;
    d. A plan to increase the reagent injection rate to identify the 
injection rates with the maximum emission reduction effectiveness 
and associated sampling and testing programs for each increase in 
the reagent rate. The owner/operator shall test, at a minimum, for 
the ammonia injection system at molar ratios of 0.75, 1.0, and 1.20. 
If data collected at the highest molar ratio indicates decreasing 
lb/ton emissions, the owner/operator shall continue to test the 
ammonia injection system by increasing the molar ratio by increments 
of 0.10 until either the lb/ton emission data indicates no 
significant decrease from the previous increment, or adverse effects 
are observed (e.g., ammonia slip emissions above 10 ppm, presence of 
a secondary particulate plume, impaired product, impaired kiln 
operations).
    e. The factors that will determine the optimum reagent injection 
rates and pollutant emission reductions (including maintenance of 
Kiln, productivity, and product quality); and
    f. Evaluation of any observed synergistic effects on Kiln 
emissions, Kiln operation, reagent slippage, or product quality from 
the ammonia injection system.
    11. As part of the Optimization Protocol, the owner/operator 
shall submit to EPA a schedule for optimizing each the ammonia 
injection system parameters identified in Item 10 of this appendix. 
The schedule shall indicate the total duration of the Optimization 
period, and must optimize each identified parameter for the 
following minimum amounts of time:

------------------------------------------------------------------------
                                                              Minimum
                                                           optimization
                        Parameter                             period
                                                            (operating
                                                               days)
------------------------------------------------------------------------
Fuel usage between riser duct burner and calciner                     15
 burners................................................
Calciner combustion.....................................              45
Raw mix chemical and physical properties stabilization..              45
Setup of SNCR, initial operation of reagent injection,                60
 and calibration........................................
------------------------------------------------------------------------

    12. Within 60 days following the termination of the Optimization 
Period(s), the owner/operator shall submit to EPA for review an 
Optimization Report demonstrating conformance with the Optimization 
Protocol for the ammonia injection system and establishing the 
optimized operating parameters for the facility processes and the 
ammonia injection system determined under the Optimization Protocol, 
including optimized injection rates for all reagents. The owner/
operator may take into account energy, environmental, and economic 
impacts and other costs in proposing the optimized state of the 
ammonia injection system, including the injection rates of reagents, 
and the operating parameters for the facility processes. The owner/
operator may also include in the Optimization Report a discussion of 
any problems encountered during the Optimization Period, and how 
that problem may impact the potential emission reductions (e.g. the 
quantity of reagent slip at varying injection rates and/or the 
possible observance of a detached plume above the Stack).
    13. Optimization Targets: Except as otherwise provided in this 
Item and in Item 14 of this appendix, the ammonia injection system 
shall be deemed to be optimized if the Optimization Report 
demonstrates that the ammonia injection system during periods of 
normal operation has achieved emission reductions consistent with 
its maximum design stoichiometric rate identified in the Design 
Report.
    14. Notwithstanding the provisions of Item 13 of this appendix, 
the ammonia injection system may be deemed to be optimized at a 
lower rate of emission reductions than that identified in Item 13 of 
this appendix if the Optimization Report demonstrates that, during 
periods of normal operation, a lower rate of emission reductions 
cannot be sustained after all parameters and injection rates are 
optimized during the Optimization Period without creating a 
meaningful risk of impairing product quality, impairing Kiln system 
reliability, impairing compliance with a maximum ammonia slip 
emissions limit of 10 ppm or other permitted levels, or forming a 
detached plume.
    15. During the Optimization Period, the owner/operator, to the 
extent practicable and applicable, shall operate the ammonia 
injection system in a manner consistent with good air pollution 
control practice consistent with 40 CFR 60.11(d). The owner/operator 
will adjust its optimization of the ammonia injection system as may 
be necessary to avoid, mitigate or abate an identifiable non-
compliance with an emission limitation or standard for pollutants 
other than NOx. In the event the owner/operator determines, prior to 
the expiration of the Optimization Period, that its ability to 
optimize the ammonia injection system will be affected by potential 
impairments to product quality, kiln system reliability or increased 
emissions of other pollutants, then the owner/operator shall 
promptly advise EPA of this determination, and include these 
considerations as part of its recommendation in its Optimization 
Report.

V. Demonstration Period

    16. The Demonstration Period shall commence within 7 days after 
the owner/operator's receipt of final comments from EPA on the 
Optimization Report. During the Demonstration Period, the owner/
operator shall operate the ammonia injection system for a period of 
270 Operating Days consistent with the optimized operations of the 
Facility and the ammonia injection system as contained in the 
Optimization Report. This 270 Operating Day Demonstration Period may 
be shortened or lengthened as provided for in Items 17 and 18 of 
this appendix.
    17. If Kiln Operation is disrupted by excessive unplanned 
outages, or excessive Startups and Shutdowns during the 
Demonstration Period, or if the Kiln temporarily ceases operation 
for business or technical reasons, the owner/operator may advise EPA 
that it is necessary to temporarily extend the Demonstration Period. 
Data gathered during periods of disruption may not be used to 
determine an emission limitation.
    18. If evidence arises during the Demonstration Period that 
product quality, kiln system reliability, or emission compliance 
with an emission limitation or standard is impaired by reason of 
longer term operation of the ammonia injection system in a manner 
consistent with the parameters identified in the Optimization 
Report, then the owner/operator may, upon notice to EPA, temporarily 
modify the manner of operation of the facility process or the 
ammonia injection system to mitigate the effects and, if necessary, 
notify EPA that the owner/operator will suspend or extend the

[[Page 52496]]

Demonstration Period for further technical evaluation of the effects 
of a process optimization or permanently modify the manner of 
operation of the ammonia injection system to mitigate the effects.
    19. During the Demonstration Period, the owner/operator shall 
collect the same data as required in Item 8 of this appendix. The 
Demonstration Report shall include the data collected as required in 
this Item.
    20. Within 60 Days following completion of the Demonstration 
Period for the ammonia injection system, the owner/operator shall 
submit a Demonstration Report to EPA, based upon and including all 
of the data collected during the Demonstration Period including data 
from Startup, Shutdown and Malfunction events, that identifies a 
proposed 30-kiln operating day emission limit for NOX. 
The 30-kiln operating day emission limit for NOX shall be 
based upon an analysis of CEMS data and clinker production data 
collected during the Demonstration Period, while the process and 
ammonia injection system parameters were optimized in determining 
the proposed final Emission Limit(s) achievable for the Facility. 
Total pounds of an affected pollutant emitted during an individual 
Operating Day will be calculated from collected CEMS data for that 
Day. Hours or Days when there is no Kiln Operation may be excluded 
from the analyses. However, the owner/operator shall provide an 
explanation in the Demonstration Report(s) for any data excluded 
from the analyses. In any event, the owner/operator shall include 
all data required to be collected during the Demonstration Period in 
the Final Demonstration Report(s).
    21. The owner/operator shall propose a 30-kiln operating day 
emission limit for NOx in the Demonstration Report(s) as provided in 
Item 20 of this appendix. This 30-kiln operating day emission limit 
shall be calculated in accordance with the following formula:

X = [mu] + 1.65[sigma]

Where:

X = 30-Day Rolling Average Emission Limit (lb/Ton of clinker);
[mu] = arithmetic mean of all of the 30-Day rolling averages;
[sigma] = standard deviation of all of the 30-Day rolling averages, 
as calculated in the following manner:
[GRAPHIC] [TIFF OMITTED] TR03SE14.004

Where:

N = The total number of rolling 30-kiln operating day emission 
rates;

xi = Each rolling 30-kiln operating day emission rate;
x  = The mean value of all of the rolling 30-kiln operating day 
emission rates.

    22. Supporting data required to be submitted under this appendix 
may contain information relative to kiln operation and production 
that the owner/operator may consider to be proprietary. In such a 
situation, the owner/operator may submit the information to EPA as 
CBI, subject to the provisions of 40 CFR part 2.

Appendix B to Sec.  52.145--Lime Kiln Control Technology Demonstration 
Requirements

I. Scope

    1. The owner/operator shall comply with the requirements 
contained in this appendix for implementing combustion and process 
optimization measures and in proposing and establishing rolling 12-
month limits for nitrogen oxide (NOX).
    2. The owner/operator shall take the following steps to 
establish rolling 12-month limits for NOx.
    a. Design Report: At least 6 months prior to commencing 
construction of an ammonia injection system, the owner/operator 
shall prepare and submit to EPA for review a Design Report for the 
ammonia injection system;
    b. Baseline Data Collection: Prior to initiating operation of an 
ammonia injection system, the owner/operator shall either: (i) 
Collect new baseline emissions and operational data for a 180-day 
period; or (ii) submit for EPA review baseline emissions and 
operational data from a period prior to the date of any baseline 
data collection period. Such baseline emissions and operational data 
shall be representative of the full range of normal kiln operations.
    c. Optimization Protocol: Prior to commencement of the 
Optimization Period, the owner/operator shall submit for EPA review 
an Optimization Protocol which shall include the procedures to be 
used for the purpose of adjusting operating parameters and 
minimizing emissions.
    d. Optimization Period: Following completion of installation of 
an ammonia injection system, the owner/operator shall undertake a 
startup and optimization period for the ammonia injection system;
    e. Optimization Report: Within 60 calendar days following the 
conclusion of the Optimization Program, the owner/operator shall 
submit to EPA an Optimization Report demonstrating conformance with 
the Optimization Protocol, and establishing optimized operating 
parameters for the ammonia injection system as well as other 
facility processes.
    f. Demonstration Period: Upon completion of the optimization 
period specified above, the owner/operator shall operate the ammonia 
injection system in a manner consistent with the optimization period 
for a period of 360 kiln operating days (subject to being shortened 
or lengthened as provided for in Items 17 and 18 of this appendix) 
for the purpose of establishing a rolling 30-kiln operating day 
limit; and
    g. Demonstration Report: The owner/operator shall prepare and 
submit to EPA for review, a report following completion of the 
demonstration period for the ammonia injection system.

II. Design Report

    3. Prior to commencing construction of the ammonia injection 
system, the owner/operator shall submit to EPA for review a Design 
Report for the ammonia injection system. The owner/operator shall 
design the ammonia injection system to deliver the proposed reagent 
to the exhaust gases at the rate of at least 1.2 mols of reagent to 
1.0 mols of NOx (1.2:1 molar ratio). The system shall be designed to 
inject Ammonia into the kiln exhaust gas stream. The owner/operator 
shall specify in the Design Report the reagent(s) selected, the 
locations selected for reagent injection, and other design 
parameters based on maximum emission reduction effectiveness, good 
engineering judgment, vendor standards, available data, kiln 
operability, and regulatory restrictions on reagent storage and use.
    4. Any permit application which may be required under state or 
federal law for the ammonia injection system shall be consistent 
with the Design Report.

III. Baseline Data Collection

    5. Prior to commencement of continuous operation of the ammonia 
injection system, the owner/operator shall either: (a) Collect new 
baseline emissions and operational data for a 180-day period; or (b) 
submit for EPA review existing baseline emissions and operational 
data collected from a period of time prior to the initiation of a 
baseline collection period. Such baseline emissions and operational 
data shall include the data required by Item 8 of this appendix for 
periods of time representing the full range of normal kiln 
operations. Within 45 Days following the completion of the baseline 
data collection period, the owner/operator shall submit to EPA the 
baseline data collected during the Baseline Data Collection Period.

IV. Optimization Period

    6. The owner/operator shall install, operate, and collect 
NOX emissions data from a CEMS in accordance with Sec.  
52.145(k)(7)(i), reagent injection data in accordance with Sec.  
52.145(k)(7)(ii)(D), and other operational data prior to 
commencement of the Optimization Period.
    7. During the Baseline Data Collection Period (if the owner/
operator elects to collect new data) and the Optimization Period, 
the owner/operator shall operate the Kiln in a manner necessary to 
produce a quality lime product. The owner/operator shall not be 
expected to operate the Kiln within normal operating parameters 
during periods of Kiln Malfunction, Startup and Shutdown. The owner/
operator shall not intentionally adjust kiln operating parameters to 
increase the rate of emission (expressed as lb/ton of lime product 
produced) for NOX.
    8. The data to be collected during the Baseline Data Collection 
Period (if the owner/operator elects to collect baseline data) and 
the Optimization Period will include the following information 
either derived from available direct monitoring or as estimated from 
monitored or measured data:
    a. Kiln flue gas temperature at the inlet to the fabric filter 
or at the Kiln stack (daily average);
    b. Kiln production rate in tons of lime product (daily total) by 
type;
    c. NOX and CO concentrations (dry basis) and mass 
rates for the Kiln (daily average for concentrations and daily 
totals for mass rates) as measured at the Kiln stack gas analyzer 
location;
    d. Flue gas volumetric flow rate (daily average in dry acfm);

[[Page 52497]]

    e. Sulfate in feed (calculated to a daily average percentage);
    f. Feed burnability (C3S) (at least daily). In the event that 
more than one type of lime product is produced, the feed burnability 
for each type of lime product will be included;
    g. Temperatures in or near the burning zone (by infrared or 
optical pyrometer);
    h. Kiln system fuel feed rate and type of fuel by weight or heat 
input rate (calculated to a daily average);
    i. Fuel distribution, an estimate of how much is injected at 
each location (daily average);
    j. Kiln amps (daily average);
    k. Kiln system draft fan settings and primary air blower flow 
rates;
    l. Documentation of any Startup, Shutdown, or Malfunction 
events;
    m. An explanation of any gaps in the data or missing data; and
    n. Amount of oxygen generated and introduced into the Kiln (lb/
day).
    9. The owner/operator shall submit the data to EPA in an 
electronic format and shall explain the reasons for any data not 
collected for each of the parameters. The owner/operator shall 
report all data in a format consistent with and able to be 
manipulated by Microsoft Excel.
    10. Prior to commencement of the Optimization Period, the owner/
operator shall submit to EPA for review a protocol (``Optimization 
Protocol'') for optimizing the ammonia injection system, including 
optimization of the operational parameters resulting in the 
minimization of emissions of NOX to the greatest extent 
practicable without violating any limits. The Protocol shall 
describe procedures to be used during the Optimization Period to 
optimize the facility processes to minimize emissions from the kiln 
and adjust ammonia injection system operating parameters, and shall 
include the following:
    a. The range of reagent injection rates (as a molar ratio of the 
average pollutant concentration);
    b. Sampling and testing programs that will be undertaken during 
the initial reagent injection rate period;
    c. A plan to increase the reagent injection rate to identify the 
injection rates with the maximum emission reduction effectiveness 
and associated sampling and testing programs for each increase in 
the reagent rate. The owner/operator shall test, at a minimum, for 
the ammonia injection system at three molar ratios of 0.75, 1.0, and 
1.20;
    d. The factors that will determine the optimum reagent injection 
rates and pollutant emission reductions (including maintenance of 
Kiln, productivity, and product quality); and
    e. Evaluation of any observed synergistic effects on Kiln 
emissions, Kiln operation, reagent slippage, or product quality from 
the ammonia injection system.
    f. Any additional facility processes that the owner/operator 
determines may reduce NOX emissions in conjunction with 
the ammonia injection system.
    11. As part of the Optimization Protocol, the owner/operator 
shall submit to EPA a schedule for optimizing each of the ammonia 
injection system parameters identified in Item 10 of this appendix. 
The schedule shall indicate the total duration of the Optimization 
period, and must optimize each identified parameter for the 
following minimum amounts of time:

------------------------------------------------------------------------
                                                             Minimum
                                                           optimization
                       Parameter                              period
                                                            (operating
                                                              days)
------------------------------------------------------------------------
Setup of SNCR, initial operation of reagent injection,               60
 and calibration.......................................
------------------------------------------------------------------------

    12. Within 60 Days following the termination of the Optimization 
Period(s), the owner/operator shall submit to EPA for review an 
Optimization Report demonstrating conformance with the Optimization 
Protocol for the ammonia injection system and establishing the 
optimized operating parameters for the facility processes and the 
ammonia injection system determined under the Optimization Protocol, 
including optimized injection rates for all reagents. The owner/
operator may take into account energy, environmental, and economic 
impacts and other costs in proposing the optimized state of the 
ammonia injection system, including the injection rates of reagents, 
and the operating parameters for the facility processes. The owner/
operator may also include in the Optimization Report a discussion of 
any problems encountered during the Optimization Period, and how 
that problem may impact the potential emission reductions (e.g. the 
quantity of reagent slip at varying injection rates and/or the 
possible observance of a detached plume above the Stack).
    13. Optimization Targets: Except as otherwise provided in this 
Item and in Item 14 of this appendix, the ammonia injection system 
shall be deemed to be optimized if the Optimization Report 
demonstrates that the ammonia injection system during periods of 
normal operation has achieved emission reductions consistent with 
its maximum design stoichiometric rate identified in the Design 
Report approved pursuant to Item 3 of this appendix.
    14. Notwithstanding the provisions of Item 13 of this appendix, 
the ammonia injection system may be deemed to be optimized at a 
lower rate of emission reductions than that identified in Item 13 of 
this appendix if the Optimization Report demonstrates that, during 
periods of normal operation, a lower rate of emission reductions 
cannot be sustained after all parameters and injection rates are 
optimized during the Optimization Period without creating a 
meaningful risk of impairing product quality, impairing Kiln system 
reliability, impairing compliance with a maximum ammonia slip 
emissions limit of 10 ppm or other permitted levels, or forming a 
detached plume.
    15. During the Optimization Period, the owner/operator, to the 
extent practicable and applicable, shall operate the ammonia 
injection system in a manner consistent with good air pollution 
control practice consistent with 40 CFR 60.11(d). The owner/operator 
will adjust its optimization of the ammonia injection system as may 
be necessary to avoid, mitigate or abate an identifiable non-
compliance with an emission limitation or standard for pollutants 
other than NOX. In the event the owner/operator 
determines, prior to the expiration of the Optimization Period, that 
its ability to optimize the ammonia injection system will be 
affected by potential impairments to product quality, kiln system 
reliability or increased emissions of other pollutants, then the 
owner/operator shall promptly advise EPA of this determination, and 
include these considerations as part of its recommendation in its 
Optimization Report.

V. Demonstration Period

    16. The Demonstration Period shall commence within 7 days after 
the owner/operator's receipt of the final comments from EPA on the 
Optimization Report. During the Demonstration Period, the owner/
operator shall operate the ammonia injection system for a period of 
360 Operating Days consistent with the optimized operations of the 
Facility and the ammonia injection system as contained in the 
Optimization Report. This 360 Operating Day Demonstration Period may 
be shortened or lengthened as provided for in Items 17 and 18 of 
this appendix.
    17. If Kiln Operation is disrupted by excessive unplanned 
outages, or excessive Startups and Shutdowns during the 
Demonstration Period, or if the Kiln temporarily ceases operation 
for business or technical reasons, the owner/operator may advise EPA 
that it is necessary to temporarily extend the Demonstration Period. 
Data gathered during periods of disruption may not be used to 
determine an emission limitation.
    18. If evidence arises during the Demonstration Period that 
product quality, kiln system reliability, or emission compliance 
with an emission limitation or standard is impaired by reason of 
longer term operation of the ammonia injection system in a manner 
consistent with the parameters identified in the Optimization 
Report, then the owner/operator may, upon notice to EPA, temporarily 
modify the manner of operation of the facility process or the 
ammonia injection system to mitigate the effects and, if necessary, 
notify EPA that the owner/operator will suspend or extend the 
Demonstration Period for further technical evaluation of the effects 
of a process optimization or permanently modify the manner of 
operation of the ammonia injection system to mitigate the effects.
    19. During the Demonstration Period, the owner/operator shall 
collect the same data as required in Item 8 of this appendix. The 
Demonstration Report shall include the data collected as required in 
this Item.
    20. Within 60 Days following completion of the Demonstration 
Period for the ammonia injection system, the owner/operator shall 
submit a Demonstration Report to EPA, based upon and including all 
of the data collected during the Demonstration Period including data 
from Startup, Shutdown and Malfunction events, that identifies a 
proposed rolling 12-month emission limit for NOX. The 
rolling 12-month emission limit for NOX shall be based 
upon an analysis of

[[Page 52498]]

CEMS data and lime production data collected during the 
Demonstration Period, while the process and ammonia injection system 
parameters were optimized in determining the proposed Emission 
Limit(s) achievable for the Facility. However, the owner/operator 
shall provide an explanation in the Demonstration Report(s) for any 
data excluded from the analyses. In any event, the owner/operator 
shall include all data required to be collected during the 
Demonstration Period in the Final Demonstration Report(s).
    21. The owner/operator shall propose a rolling 12-month emission 
limit for NOX in the Demonstration Report(s) as provided 
in Item 20 of this appendix. This rolling 12-month limit shall be 
calculated in accordance with the following formula:

X = [mu] + 1.65[sigma]

Where:

X = Rolling 12-month Average Emission Limit (lb/Ton of lime 
product);
[mu] = arithmetic mean of all of the Rolling 12-month averages;
[sigma] = standard deviation of all of the rolling 12-month 
averages, as calculated in the following manner:
[GRAPHIC] [TIFF OMITTED] TR03SE14.005

Where:

N = The total number of rolling 12-month emission rates;
xi = Each rolling 12-month emission rate;
x = The mean value of all of the rolling 12-month emission rates.
    22. Supporting data required to be submitted under this Appendix 
may contain information relative to kiln operation and production 
that the owner/operator may consider to be proprietary. In such a 
situation, the owner/operator may submit the information to EPA as 
CBI, subject to the provisions of 40 CFR part 2.

[FR Doc. 2014-15895 Filed 9-2-14; 8:45 am]
BILLING CODE 6560-50-P


