[Federal Register Volume 79, Number 170 (Wednesday, September 3, 2014)]
[Rules and Regulations]
[Pages 52420-52498]
From the Federal Register Online via the Government Publishing 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 [email protected].
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
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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.
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\13\ 78 FR 46142 (July 30, 2013).
\14\ 79 FR 9318 (February 18, 2014).
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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.
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\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.'').
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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).
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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.
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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.
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\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.
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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.
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\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.
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\104\ GCT Letter at 4.
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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.
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\105\ ``AP 42'' refers to EPA's Compilation of Air Pollutant
Emission Factors. See http://www.epa.gov/ttnchie1/ap42/.
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[[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.
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\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\
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\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.
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\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.
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\120\ 79 FR 9347 (citing Letter from Krishna Parameswaran,
ASARCO, to Gregory Nudd, EPA dated March 6, 2013, page 15).
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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\
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\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.
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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\
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\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).
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\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).
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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\
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\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.''
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\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.
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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.
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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.
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\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.
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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.
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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:
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\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.
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\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,
Draft#5, 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.
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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).
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\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-AZ_RP_sources_all-
Task9_2012-09-30.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\
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\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, FIP_RPG_estimates.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
Draft#5, 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